Download ESC Victoria Electricity Distribution Price Review 2006

October 2006 Final Decision
Electricity Distribution Price Review
2006-10
October 2005 Price Determination as
amended in accordance with a decision
of the Appeal Panel dated 17 February
2006
Final Decision Volume 1
Statement of Purpose and Reasons
Essential Services Commission
Level 2, 35 Spring Street
Melbourne VIC 3000, Australia
Telephone 61 3 9651 0222
Facsimile 61 3 9651 3688
[email protected]
www.esc.vic.gov.au
Contents
Page
PREFACE ................................................................................................................................................................VII
PART A:
OVERVIEW AND INTRODUCTION ..............................................................................................1
Key outcomes of the review ...................................................................................................................................1
Focus of this review................................................................................................................................................2
Enhanced accountability ..............................................................................................................................3
Establishing forecast revenue requirements.................................................................................................5
Real price reductions ............................................................................................................................................10
Consultation process.............................................................................................................................................11
Issues arising from the review ..............................................................................................................................12
Looking ahead ......................................................................................................................................................13
1
INTRODUCTION ..............................................................................................................................................15
1.1 Legislative framework ...............................................................................................................................15
1.2 The Commission’s consultation process....................................................................................................18
1.3 The Commission’s broad framework and approach ..................................................................................19
1.4 Structure of the Decision ...........................................................................................................................22
PART B1:
2
SERVICES PROVIDED AND ENERGY DELIVERED ...............................................................23
SERVICE STANDARDS ...................................................................................................................................27
2.1 Final Decision............................................................................................................................................28
2.1.1
Reliability measures ....................................................................................................................28
2.1.2
Quality of supply measures .........................................................................................................30
2.1.3
Customer service measures .........................................................................................................31
2.2 Reasons for the Decision ...........................................................................................................................32
2.2.1
Reliability measures ....................................................................................................................32
2.2.2
Quality of supply measures .........................................................................................................45
2.2.3
Customer service measures .........................................................................................................53
ATTACHMENT 1:
EXAMPLES OF WORST SERVED FEEDERS ..............................................................61
ATTACHMENT 2:
TARGETED LEVELS — RELIABILITY MEASURES ................................................64
3
SERVICE INCENTIVE MECHANISMS ........................................................................................................69
3.1 Final Decision............................................................................................................................................70
3.1.1
S-factor scheme ...........................................................................................................................70
3.1.2
GSL payments scheme ................................................................................................................75
3.1.3
Other service incentive arrangements..........................................................................................76
3.1.4
Operation of the service incentive mechanisms ..........................................................................77
3.2 Reasons for the Decision ...........................................................................................................................78
3.2.1
S-factor scheme ...........................................................................................................................78
3.2.2
GSL payments scheme ..............................................................................................................102
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3.2.3
3.2.4
Other proposed service incentive arrangements ........................................................................115
Exclusion criteria.......................................................................................................................122
ATTACHMENT: ANNUAL HEALTH CARD ....................................................................................................129
4
GROWTH FORECASTS ................................................................................................................................131
4.1 Final Decision..........................................................................................................................................131
4.2 Reasons for the Decision .........................................................................................................................133
4.2.1
Historic growth rates .................................................................................................................136
4.2.2
Assumptions underpinning the different scenarios....................................................................138
4.2.3
Price elasticity of demand .........................................................................................................150
PART B2:
REVENUE REQUIREMENT — DUOS .......................................................................................153
5
RELEVANT COSTS........................................................................................................................................159
5.1 Final Decision..........................................................................................................................................160
5.2 Reasons for the Decision .........................................................................................................................163
5.2.1
Allocation between retail and distribution services...................................................................165
5.2.2
Allocation between prescribed and excluded services...............................................................166
5.2.3
Capitalisation of indirect (corporate) overheads........................................................................166
5.2.4
Movements in provisions ..........................................................................................................167
5.2.5
The market price for services ....................................................................................................168
5.2.6
Other adjustments......................................................................................................................185
5.2.7
Further adjustments to CitiPower and Powercor .......................................................................185
5.2.8
Summary ...................................................................................................................................192
6
OPERATING AND MAINTENANCE EXPENDITURE .............................................................................195
6.1 Final Decision..........................................................................................................................................195
6.2 Reasons for the Decision .........................................................................................................................196
6.2.1
Distributors’ proposed operating and maintenance expenditure................................................197
6.2.2
Base operating and maintenance expenditure............................................................................199
6.2.3
Rate of change ...........................................................................................................................205
6.2.4
Impact of growth .......................................................................................................................211
6.2.5
Step changes ..............................................................................................................................212
7
CAPITAL EXPENDITURE ............................................................................................................................251
7.1 Final Decision..........................................................................................................................................252
7.2 Reasons for the Decision .........................................................................................................................254
7.2.1
Commission’s objectives...........................................................................................................255
7.2.2
Framework and approach ..........................................................................................................257
7.2.3
Distributors’ proposed capital expenditure................................................................................258
7.2.4
Review of the distributors’ proposals ........................................................................................261
7.2.5
Aggregate level of capital expenditure ......................................................................................265
7.2.6
Implementation of capital works programs ...............................................................................267
7.2.7
Information asymmetry .............................................................................................................268
7.2.8
Commission’s determination of capital expenditure requirements............................................269
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7.2.9
Assessment of the distributors’ capital expenditure proposals by asset category......................272
8
REGULATORY ASSET BASE ......................................................................................................................321
8.1 Final Decision..........................................................................................................................................321
8.2 Reasons for the Final Decision ................................................................................................................323
8.2.1
Opening value of the asset base (1 January 2006).....................................................................324
8.2.2
Rolled forward values of the regulatory asset base (2006-10)...................................................327
9
COST OF CAPITAL FINANCING................................................................................................................331
9.1 Final Decision..........................................................................................................................................332
9.2 Reasons for the Decision .........................................................................................................................332
9.2.1
Methodology for estimating the after-tax WACC .....................................................................333
9.2.2
Estimating the after-tax WACC ................................................................................................338
9.2.3
Taxation.....................................................................................................................................398
10
EFFICIENCY CARRYOVER MECHANISM ...................................................................................415
10.1 Final Decision..........................................................................................................................................417
10.2 Reasons for the Decision .........................................................................................................................418
10.2.1 Calculation of the 2001-05 efficiency carryover amounts.........................................................418
10.2.2 Efficiency carryover mechanism in the 2006-10 regulatory period ..........................................430
ATTACHMENT:
PART B3:
11
PRICES — DUOS............................................................................................................................439
REVENUE REQUIREMENT ..............................................................................................................443
11.1 Final Decision..........................................................................................................................................443
11.2 Reasons for the Final Decision ................................................................................................................446
11.2.1 Distributors’ proposed revenue requirement .............................................................................449
11.2.2 Translation of revenue requirement into forecast tariff revenue requirement ...........................451
ATTACHMENT:
12
2001-05 BENCHMARK ADJUSTMENT FOR CARRYOVER MECHANISM.........437
CALCULATION OF THE S FACTOR INCLUSIVE P0...............................................459
PRICE CONTROL ARRANGEMENTS.............................................................................................461
12.1 Reporting requirements............................................................................................................................461
12.1.1 Tariff Strategy Report................................................................................................................462
12.1.2 Annual Tariff Report .................................................................................................................464
12.2 Pricing principles .....................................................................................................................................465
12.3 Price control formulas..............................................................................................................................467
12.3.1 Distribution price control formula .............................................................................................467
12.3.2 Transmission price control formula...........................................................................................476
12.4 Rebalancing constraints ...........................................................................................................................478
12.4.1 Distribution tariff rebalancing constraint...................................................................................478
12.4.2 Transmission rebalancing constraint .........................................................................................481
12.5 Tariff re-assignment.................................................................................................................................486
12.6 Pass through provisions ...........................................................................................................................487
12.7 Tariff approval process ............................................................................................................................490
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12.7.1 Tariffs for the 2006 calendar year .............................................................................................490
12.7.2 Tariffs for the 2007-10 calendar years.......................................................................................492
12.8 Demand management and non-network solutions ...................................................................................492
12.8.1 Benefits associated with the interval meter rollout (IMRO)......................................................494
12.8.2 Weighted average price cap.......................................................................................................494
12.8.3 Building blocks approach ..........................................................................................................495
12.8.4 Service incentive mechanism ....................................................................................................497
12.8.5 Stakeholder responses ...............................................................................................................498
PART B4:
13
PRESCRIBED METERING SERVICES......................................................................................503
REVENUE REQUIREMENT — METERING ..................................................................................505
13.1 Final Decision..........................................................................................................................................505
13.2 Reasons for the Decision .........................................................................................................................507
13.2.1 Responsibility for metering services .........................................................................................507
13.2.2 Regulation of metering services ................................................................................................509
13.2.3 Revenue requirement.................................................................................................................512
13.2.4 Enhanced offerings....................................................................................................................554
ATTACHMENT: FORECAST QUANTITIES AND UNIT COSTS..................................................................557
14
PRICE CONTROLS AND INCENTIVE ARRANGEMENTS — METERING .............................565
14.1 Final Decision..........................................................................................................................................566
14.2 Reasons for the Decision .........................................................................................................................569
14.2.1 Price controls.............................................................................................................................570
14.2.2 Incentive arrangements..............................................................................................................577
14.2.3 Metering service charges...........................................................................................................582
14.2.4 Excluded service charges ..........................................................................................................585
PART C:
15
EXCLUDED SERVICES AND OTHER ACTIVITIES...............................................................591
EXCLUDED SERVICES AND OTHER ACTIVITIES.....................................................................593
15.1 Changes to excluded services during the 2006-2010 regulatory period ..................................................593
15.1.1 Final Decision............................................................................................................................593
15.1.2 Reasons for the Decision ...........................................................................................................595
15.2 Policies and definitions............................................................................................................................600
15.2.1 Final Decision............................................................................................................................600
15.2.2 Reasons for the Decision ...........................................................................................................600
15.3 Revisions to excluded service charges.....................................................................................................602
15.4 Other Activities........................................................................................................................................604
PART D:
SUMMARY OF THE FINAL DECISION BY DISTRIBUTOR.................................................607
AGLE .................................................................................................................................................................608
CitiPower............................................................................................................................................................626
Powercor.............................................................................................................................................................645
SP AusNet ..........................................................................................................................................................665
United Energy.....................................................................................................................................................684
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APPENDIX A
THE PRICE REVIEW PROCESS .......................................................................................703
The price review process ....................................................................................................................................703
Commission’s publication and submissions received from stakeholders ...........................................................706
Public forums and workshops.............................................................................................................................717
Independent advice and consultancies in relation to the price review ................................................................720
GLOSSARY AND ABBREVIATIONS .................................................................................................................722
REFERENCES ........................................................................................................................................................730
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PREFACE
The Essential Services Commission (the Commission) is required to review and decide on
new price controls for the charges to be levied by the five Victorian electricity distributors
from 1 January 2006. The Commission’s decisions are framed by the Essential Services
Commission Act 2001, the Electricity Industry Act 2000 and the Victorian Tariff Order.
This price review is the second review of the electricity distribution price controls that apply
to the five Victorian distributors undertaken by an independent regulator. It has provided an
opportunity for Victorian customers to review the services and service levels provided by the
distributors and balance their service-related requirements against the prices that they are
willing to pay.
The Commission has undertaken extensive consultation with stakeholders and information
gathering and analysis in reaching this Determination. Consultation began in March 2004 and
has taken the form of consultation papers, workshops, public information sessions in
Melbourne and regional centres and submissions from the distributors and other stakeholders.
A Draft Decision was released in June 2005 that provided stakeholders with the opportunity
to comment on the Commission’s views before it made its Final Determination. Advice has
also been obtained from technical consultants.
The Determination comprises two volumes:
•
Final Decision Volume 1 — Statement of Purpose and Reasons: the Statement of
Purpose and Reasons provides the context for the review and outlines the key issues,
the various comments and submissions received and the Commission’s analysis,
reasons and conclusions regarding the new price controls. It is structured around the
key issues that have been addressed by the Commission throughout this price review.
•
Final Decision Volume 2 — Price Determination: the Price Determination sets out the
detailed price controls and the associated implementation mechanisms which gives
effect to those price controls. The price controls represent the translation of the
Commission’s conclusions presented in the Final Decision into a legal document that
will provide the basis for regulating the charges levied by the distributors. These
controls will be implemented on 1 January 2006 and apply for a five year period.
In conducting this review and making this Determination, the Commission has been guided
by the statutory framework. The Commission considers that this Determination, which has
been arrived at following the extensive price review process, provides a firm foundation for
electricity distribution services for the next regulatory period and beyond.
A.C. Larkin
Acting Chairperson
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PART A: OVERVIEW AND INTRODUCTION
The Commission has made a Final Decision on the prices and service levels applying to the
five Victorian distribution businesses for the period 2006-2010. This overview summarises
the key outcomes, issues and future regulatory policy implications that have emerged from
this, the second major independent review of the electricity distribution charges for the five
Victorian monopoly distributors, since the electricity industry reforms of the mid 1990s.
The key theme and objective of this review has been to substantially increase the
accountability of the businesses for maintaining and improving the delivery of reliable
electricity distribution services to Victorian customers. Reliability of essential services such
as electricity distribution services has a significant impact on economic growth,
competitiveness and the welfare of all Victorian citizens. The prices paid for distribution
services account for approximately 40 per cent of electricity customers' total bills. Moreover,
the sale of such services is expected to generate industry revenues of around $6.3 billion over
the next five years. The adequacy of revenue, return and incentive is critical to the necessary
investment in, and maintenance of, reliable networks.
Key outcomes of the review
The price controls established for the five Victorian monopoly distribution businesses
provide for the financing of $3.3 billion1 of capital expenditure for the period of 2006-10.
This represents an increase of around 43 per cent above the actual capital investment made by
the businesses during the period 2001-2005 including metering, or around 30 per cent
excluding metering. The Commission considers that this level of capital expenditure
benchmark is more than sufficient to account for the demands of network reinforcement, new
customer connections, asset replacement, safety and environmental obligations and the
installation of a significant number of interval meters.
The Commission’s Final Decision will result in average price reductions of 12 per cent across
the industry in 2006, with a further 1.2 per cent reduction per annum over the following four
years.2 This compares to initial price reductions averaging 23 per cent in the Draft Decision.
The adjustment to the initial price reductions between the Draft and Final Decisions has been
made in light of further information that supports increases in forecast operating and capital
expenditures, a reduction in forecast demand and an acceleration of the depreciation profile
for some distributors.
In developing the price controls for the 2006-2010 regulatory period the Commission has
deliberately adopted a longer term view with a focus on locking in the performance gains
made to date as well as providing incentives to improve reliability and customer service to
levels consistent with the values placed on them by customers. Substantial increases in both
the rewards and penalties imposed under the broadened service incentive scheme will provide
distributors with strong financial incentives to improve service performance. These incentives
are accompanied by an enhanced system of guaranteed service level payments to bring about
improvements in those areas that are currently worst served.
1
2
Gross capital expenditure including metering.
Including metering charges.
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The introduction of strategic initiatives such as the interval meter rollout will also provide a
platform for the delivery of improved demand management outcomes and greater efficiency
in distribution services and related markets. The interval meter roll out will be managed so
that distributors are provided with adequate compensation for the cost of the rollout whilst
providing incentives to achieve efficiencies in the cost and volume of installations.
Focus of this review
The Commission recognises that the distributors have achieved a marked improvement in
service performance for virtually all customers over the last ten years.
In the time since the industry was restructured, privatised and placed under formal economic
regulation, all key indicators of network reliability have shown significant improvement. The
broadest indicator of reliability, average customer minutes off supply per annum (or SAIDI),
has fallen from 199 in 1997 to 132 in calendar year 2004. The proportion of customers
experiencing more than five hours of supply outages (or 300 minutes off supply) has reduced
from 20.5 to 11.6 percent over the same period. The annual incidence of interruptions (as
indicated by SAIFI) has also reduced significantly.3
Services have not only improved in terms of average network performance, but they have
also improved for customers located in those parts of the electricity distribution network that
have historically experienced poor performance. There has been significant improvement in
the minutes off supply for worst served customers (ESC 2004g, p. 30). For example,
Powercor reports that the worst served 15 per cent of customers in its network area have
experienced an improvement of 41 per cent since 2000, from an average of 738 minutes off
supply in 2000 to 434 minutes off supply in 2004.
Notwithstanding this picture of strong performance overall, there remain some pockets where
the level of service has not kept pace with the demands of customers in a growing economy,
particularly in some regional areas. As explained below, an important focus of this review has
been to establish arrangements that will address these areas of concern.
Instrumental in delivering the widespread improvement in services has been the improved
operational and investment focus of the distributors. Accountability for delivering services in
line with customer expectations ultimately lies with the distributors, and will continue to
remain so. Nevertheless, the Commission’s experience over two regulatory periods is that the
detailed regulatory arrangements governing service performance play a significant role in
securing that focus by the distributors, and rewarding it appropriately.
The Commission’s highest priority for this review is to secure and enhance this recent
performance record into the future. This goal has defined the two main areas of attention for
this review:
•
3
augmenting the monitoring and incentive framework applying to service performance,
with a particular regard to strengthening the distributors’ accountability for delivering
reliable distribution network services, including for those customers where service is
still not matching reasonable expectations; and
SAIFI is the system average interruption frequency index.
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•
undertaking a careful evaluation of the future operating expenditure and investment
requirements proposed by the distributors, and ensuring that sufficient revenue is
available to finance expected changes in the cost of delivering services at current levels,
as well as incentive arrangements that ensure continued improvements in service and
reliability.
These two areas are closely related. A continued emphasis on maintaining and enhancing the
distributors’ current performance can only be achieved if expected revenues (and so the
prices that customers pay) are sufficient to finance the necessary expenditure to deliver that
service. Nevertheless, it is also recognised that irrespective of how much money is made
available through the price controls, there is no guarantee that the distributors will undertake
the investment necessary to secure and enhance network reliability or indeed the investment
that they have proposed to make. Intrinsic to a strengthened accountability framework is the
principle that some portion of distributors’ expected revenues should be conditional on the
achievement of desired levels of reliability. Importantly, customers should not be expected to
pay for reliability improvements promised but not delivered.
Enhanced accountability
In developing its approach to increasing the accountability of the distributors, the
Commission has drawn a distinction between establishing capital expenditure and operating
and maintenance expenditure forecasts sufficient to maintain the delivery of current service
performance in line with ‘business as usual’ and the arrangements for identifying and funding
opportunities to invest in further service improvements.
Business as usual expenditure has been provided for within the ‘building block’ revenue
requirements that underpin the principal price controls which are outlined in more detail in
the following sections. This expenditure does not include an allowance for improvements to
existing average service reliability levels but does allow for improvements in quality of
supply. The targeted levels of service reliability for the purpose of reporting and monitoring
in the 2006-10 regulatory period have been set equal to the 2005 targets, except where a
distributor has been consistently outperforming this target. In this case, the current level of
performance has been considered in deciding a new target
The most significant measure in this Decision for ensuring that the distributors deliver the
services that they are paid to deliver is an increase in the rewards and penalties under the
service incentive scheme (the ‘S-factor’ in the price controls).
These rewards and penalties will apply for any improvements or shortfalls in service
performance outcomes through changes to the distributor’s allowed revenue. These
adjustments are symmetric: not only will distributors receive additional income when service
enhancements are achieved but also they may incur penalties of a similar magnitude if service
performance is not delivered.
Under these arrangements the distributors — rather than the Commission — will be
responsible for identifying and deciding upon initiatives that will bring about service
improvements, with the rewards then flowing once those service improvements are
delivered. This will facilitate delivery of the optimum level of service, given the value
customers place on service and the cost to deliver this level of service.
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The main improvements made to the incentives for service provision include:
•
increases in the incentive rates;
•
adopting a uniform incentive rate for all distributors;
•
broadening the range of indicators that are subject to the financial incentive;
•
substantial increases in the value of Guaranteed Service Level (GSL) payments;
•
broadening of the monitoring regime; and
•
a quantitative rather than qualitative approach to excluding supply interruptions from
the calculation of the S-factor and the obligation to make GSL payments.
The incentive rates for the current price control period were set by reference to the estimated
marginal cost of delivering service improvements. These costs were inherently uncertain and
varied significantly from one distributor to another. For the 2006-10 period, the incentive
rates will increase based on a uniform $30,000 per MWh or 1000 times the average selling
price of distributed energy4. This value is based on the cost that poor service imposes on
customers and is known as the Value of Customer Reliability (VCR) and increases the value
up to six times compared to the value that has applied during the 2001-05 regulatory period.
The Commission is also broadening the range of indicators that are subject to the S-factor
incentive scheme. For the coming regulatory period, the scheme will include new incentives
for unplanned minutes off supply, momentary interruptions and call centre performance while
also retaining the existing incentive for the frequency of unplanned interruptions. Planned
minutes off supply has been removed from the scheme because of the concerns expressed by
some stakeholders that it would create an incentive for more ‘live line’ work, potentially
resulting in a greater incidence of unsafe work practices. Nevertheless, distributors will
continue to report planned minutes off supply on a regular basis.
In addition to incentives provided through the S-factor, the Commission has increased
substantially the payments that are to be made to customers where service performance does
not meet a guaranteed minimum level. All customers will automatically receive these
Guaranteed Service Level (GSL) payments when they experience more than 20 hours,
30 hours and 60 hours of cumulative sustained unplanned interruptions in a year with the
GSL payment increasing for each threshold. Customers will also receive a GSL payment
where the number of sustained interruptions is more than 10, 15 and 30 in a year, or the
number of momentary interruptions is more than 24 and 36 in a year, again with increasing
payments for each threshold.
A further measure to be introduced for the 2006-10 period is a broadened of the monitoring
regime. This includes:
•
additional reporting associated with quality of supply;
•
reporting the annual duration and frequency of interruptions (planned and unplanned)
experienced by the worst served 15 per cent of customers;
•
reporting the causes of unplanned interruptions and the actions the distributor proposes
to undertake to improve its performance;
4
With the exception of CitiPower’s CBD customers, where the incentive rates will be based on $60,000 per MWh
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•
reporting customer service measures, including call centre performance; and
•
reporting other measures of performance that are less amenable to specification in a
financial incentive regime.
The Commission is confident that, taken together, these arrangements will significantly
increase the accountability of distributors for delivering reliable quality services.
Importantly, the distributors will be able to control the value of the impact of these
arrangements. The expected value of the penalties and rewards associated with the S-factor
incentive scheme is approximately zero where the distributors do not respond to the
arrangements but distributors stand to earn considerable rewards where they respond by
investing in their network to achieve service improvement outcomes. This is because the
rewards under the scheme have increased significantly whilst the costs of achieving them
have reduced as a result of changes to the efficiency carry-over mechanism discussed in later
sections.
The Commission anticipates that this will cause distributors to pursue the rewards that will be
delivered by carefully targeted and innovative programs to benefit all customers and
particularly worst served customers. This will include placing greater emphasis on
undertaking investment and operational measures that reduce network outages and their
associated inconvenience to all customers. However, customers will only pay for these
improvements once they are delivered.
These revised service performance measures should encourage distributors to shift their
business focus away from short term cost minimisation and the payments available under the
efficiency carryover mechanism towards longer term network planning and management and
investment, to avoid the penalties imposed when services are not provided.
Establishing forecast revenue requirements
In addition to enhancing the accountability of distributors for the delivery of services and
reliability, the regulatory framework is also focused on the establishment of forecast revenue
requirements for each distributor over the forthcoming regulatory period. These revenue
requirements are intended to be sufficient for each distributor to recover the efficient costs of
operating its network business, including a commercial return on invested capital for
“business as usual” service levels outlined in the previous section.
The service delivery and out-turn expenditure performance of the distributors during the
2001-05 regulatory period can be characterised as having achieved more in terms of service
delivery, but with significantly less expenditure than the distributors considered necessary in
their proposals to the last price review. On readily available measures of industry
performance, this combination of outcomes can only be described as virtuous — more has
been delivered, for a cost less than expected.
However, the sustainability of the expenditure and service performance outcomes during this
regulatory period was not apparent in the expenditure projections contained in the
distributors’ submissions to this review. As a group, the distributors proposed average
increases in capital expenditure and operating and maintenance expenditure allowances for
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the 2006-10 regulatory period of 54 per cent and 45 per cent respectively5 over their average
capital expenditure in 2001-2005 and their average operating and maintenance expenditure in
2001-2005 (see Figures A.1 and A.2).
Figure A.1:
Capital expenditure (gross), industry aggregate, actual expenditure
1996-2004a and distributor’s proposed forecast expenditure 2005-10,
$million, real $2004
900
800
700
600
500
$M
400
300
200
100
0
1996
1997
1998
1999
2000
2001
Actual capex (inc meters)
a
2002
2003
2004
DB proposed CAPEX (ex meters)
2005
2006
2007
2008
2009
2010
DB proposed CAPEX (inc meters)
Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs
Figure A.2:
Operating and maintenance expenditure, industry aggregate, actual
operating and maintenance expenditure 2001-04a and distributors’
proposed expenditure, 2005-10, $million, real $2004
600
500
400
$M 300
200
100
0
2001
2002
2003
2004
2005
2006
Actual opex
a
5
2007
2008
2009
2010
Distributor proposed
Exclusive of operating and maintenance expenditure associated with prescribed metering services.
This is exclusive of the cost of metering. Including metering the distributors’ proposals represent 69 and 62 per cent
increases over the average capital expenditure in 2001-05 and their average operating and maintenance expenditure in
2001-05 respectively..
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The Commission’s task of reconciling this seemingly inconsistent combination of historical
expenditure requirements and projected expenditure has been far from straightforward. At
one end of the spectrum, the distributors’ proposals might be characterised as ‘ambit claims’
in what they take to be a process of negotiation. In this case, an important priority for the
Commission is to protect the interests of customers who would otherwise bear the cost of
excessive expenditure proposals. At the other end of the spectrum, the distributors may well
have identified opportunities where capital expenditure scheduled for the last period was
efficiently deferred, but now needs to be undertaken in the coming regulatory period.
Reconciliation of these two extremes has been a key challenge for the Commission in
reaching its Final Decision.
In its Draft Decision the Commission adopted forward looking capital and operating
expenditure forecasts that, at an industry aggregate level, represented real increases in capital
and operating and maintenance expenditure of around 5 and 22 per cent respectively6 over the
level of expenditure for the 2001-05 period. These increases reflected the impact of a number
of step changes in operating and maintenance expenditure to account for new or changed
functions and regulatory obligations, and increases in the capital expenditure forecasts
reflecting the priority accorded by the distributors and the Commission to investing in
network renewal, capacity augmentation to meet peak load growth and to comply with
regulations regarding electrical safety.
Since releasing its Draft Decision the Commission has had regard to further information
provided by the distributors and other stakeholders and the advice that it has received from its
technical consultants in relation to the distributors’ expenditure requirements for the
2006-10 regulatory period. As a result of this the Commission has revised its position with
respect to a number of assumptions underpinning capital and operating cost forecasts as
outlined in the following sections.
Capital expenditure forecasts
The Commission has adopted forward looking capital expenditure forecasts that, at an
industry aggregate level, represent a real increase in capital investment of around 30 per cent
over the level of expenditure for the 2001-05 period (see Figure A.3).7 This increase reflects
the information before the Commission that indicates that there are reasons why future
investment will need to be undertaken at greater than historic levels, for example the ageing
of assets, growth in peak demand and improved compliance with safety obligations.
The Commission has recognised that the allowance is less than the allowance claimed to be
required by the distributors, and the recommendations from its technical consultants.
However, the Commission is satisfied that taking into account the incentives at the time of a
price review to over-state expenditure requirements and then within the regulatory period to
minimise expenditure this allowance is sufficient for the obligations of the distributors with
regard to service provision and safety. Further, the Commission has taken into account the
removal of the efficiency carryover mechanism which has reduced the cost to the distributors
of undertaking investment where required and the significant increase in the rewards where
investment delivers reliability and customer service improvements.
6
7
Excluding metering expenditure.
When expenditure for metering is included, this increases to 43 per cent, at an industry level.
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Essential Services Commission, Victoria
Final Decision
Figure A.3:
Total gross capital expenditure, industry aggregate, out-turn capital
expenditure 2001-04a and Final Decision 2006-10, $million, real $2004
900
800
700
600
500
$M
400
300
200
100
0
1996
1997
1998
1999
Actual capex (inc meters)
a
2000
2001
2002
2003
2004
Commission Final Decision CAPEX (ex meters)
2005
2006
2007
2008
2009
2010
Commission Final Decision CAPEX (inc meters)
Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs
Operating and maintenance expenditure forecasts
The Commission has adopted forward looking operating and maintenance expenditure
forecasts that, at an industry aggregate level, represent a real increase in operating and
maintenance expenditure of around 21 per cent8 over the normalised level of expenditure
undertaken during the 2001-05 period (see Figure A.4).9 This increase reflects the impact of a
number of step changes (due to new or changed functions or regulatory obligations) after
making adjustments for matters such as provisions, changes in capitalisation policies and
contractual arrangements reported during the 2001-04 period. Increases in labour costs
reflecting recognised skills shortages and the cost associated with growth have also been
reflected in operating and maintenance forecasts.
The Commission is satisfied that, although these expenditure forecasts are less than the
distributors proposed, they nevertheless provide adequately for future operating needs, and
take account of relevant changes in the safety standards to which the industry must work, as
well as the continuing need to train apprentices.
8
9
Excluding metering expenditure
This calculation assumes that 2005 operating and maintenance expenditure is consistent with the Commission’s Final
Decision.
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Essential Services Commission, Victoria
Final Decision
Figure A.4:
Total operating and maintenance expenditure,a industry aggregate, outturn operating and maintenance expenditure 2001-04 and Commission
Final Decision 2006-10, $million, real $2004
600
500
400
$M 300
200
100
0
2001
2002
2003
2004
2005
2006
Commission Final Decision
a
2007
2008
2009
2010
Actual opex
Exclusive of operating and maintenance expenditure associated with prescribed metering services.
Forecast revenue requirement
In addition to the operating and capital expenditure forecasts established, the building blocks
approach adopted for this price review includes allowances for:
•
return on capital, comprising a market-based estimate of the weighted average cost of
capital applied to a regulatory asset base that incorporates new net capital expenditure
less allowed depreciation and disposals over the previous regulatory period;
•
an efficiency carryover allowance that extends the reward for out-performance against
the capital and operating expenditure benchmarks established at the last review; and
•
depreciation and corporate taxation payments.
To determine the return on capital component of the revenue requirement, the Commission
has applied a real after-tax weighted average cost of capital of 5.9 per cent to the rolled
forward values of the regulatory asset base. The change in the weighted average cost of
capital from that used in the last price review is due principally to the decline in long term
real interest rates which, for ten year CPI-linked Commonwealth government bonds, from
3.5 to 2.64 per cent.10 The building blocks described above have then been aggregated to
establish forecast revenue requirements for each of the distributors over the five year period
of this review. These revenue requirements are set out in Table A.1.
From 1 January 2006, prescribed metering services will be regulated under a separate price
control mechanism from distribution use of system services. In this Decision, the
Commission has determined a separate revenue requirement and price control for the
regulation of these services which includes the expenditure associated with rolling out
10
These rates are based on the last 20 trading days to 31 July 2005.
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Essential Services Commission, Victoria
Final Decision
interval meters. This revenue requirement has been developed using the Commission’s
building blocks approach and is then translated into a set of prescribed metering charges
using forecasts of growth over the period.
Table A.1:
Building blocks revenue requirement, 2006-10, $million, real $2004
Distributor
AGLE
2006
2007
2008
2009
2010
129.7
123.2
127.3
135.0
132.5
5.1
6.9
8.7
10.6
12.3
Total
134.8
130.1
136.0
145.6
144.8
DUoS
182.7
171.3
160.1
161.1
169.4
4.6
7.2
9.7
11.6
13.4
Total
187.2
178.5
169.8
172.6
182.8
DUoS
320.0
326.0
331.7
340.2
348.0
Metering
14.3
18.8
24.5
29.9
35.1
Total
334.3
344.8
356.1
370.1
383.1
DUoS
289.7
279.5
290.8
289.3
307.6
Metering
18.0
20.5
25.6
30.2
34.6
Total
307.7
300.1
316.4
319.4
342.2
DUoS
271.7
251.9
257.0
243.5
230.2
7.9
10.5
14.5
18.0
20.9
279.6
262.5
271.5
261.5
251.2
DUoS
Metering
CitiPower
Metering
Powercor
SP AusNet
United Energy
Metering
Total
Looking ahead, the experience from the 2001-05 regulatory period highlights the difficulties
in distinguishing enduring efficiency gains in implementing capital expenditure programs
(such as would arise from establishing more efficient capital expenditure project management
arrangements) from temporary efficiency gains (such as arise from the deferral of planned
expenditure that does not threaten service performance).
For the 2006-10 regulatory period, the Commission has removed the additional payment for
capital expenditure efficiencies although the efficiency carryover mechanism will continue
with respect to operating and maintenance expenditure. One ancillary benefit of this change is
that any network investment required in addition to the forecast will not attract a penalty.
When combined with the revised service incentive scheme, the Commission expects that the
distributors will actively pursue further capital investment where this delivers improvements
in services.
Real price reductions
The revenue requirements outlined earlier have been developed having regard to forecasts of
growth in customer numbers, peak demand and energy delivered so as to develop a set of
price controls that, when applied to existing prices, will deliver expected revenue over the
following five years that is equal in net present value terms to the revenue requirement
determined by the Commission.
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Final Decision
The combination of favourable capital market conditions, efficiencies achieved in the current
period, and the expectation of growth in customer numbers and energy delivered means that
these revenues can be recovered at prices lower than those applying in the current period.
The benefits that flowed to the distributors over the current period are being returned to
customers to ensure that customers share in the benefits of these efficiency gains as intended
by the Commission’s regulatory framework and as is required by the Tariff Order’s
requirements for a fair sharing of efficiency gains. These price reductions will manifest
through initial larger reductions followed by ongoing smaller real reductions as set out in
Table A.2.
Table A.2:
P0 and X-factors — prescribed services, 2006-10, per cent
Prescribed services
(DUoS and Metering)
Prescribed services
(DUoS)
P0
X1-X4
P0
X1-X4
AGLE
3.1
1.2
3.8
2.5
CitiPower
7.7
1.5
8.7
2.5
Powercor
16.4
1.1
17.3
2.5
SP AusNet
7.8
0.8
9.3
2.5
United Energy
15.6
1.4
14.7
2.5
Consultation process
The Commission has engaged in an extensive process of consultation with distributors,
customer groups and other industry stakeholders in reaching this Final Decision. It has also
sought expert advice on the forecasting of demand, on the review of the distributors’
expenditure proposals, and on a range of economic and legal issues more generally. In
summary, the process has involved:
•
consultation on the framework and approach for the review, over an extended period
beginning in March 2004;
•
the submission by distributors of comprehensive price-service proposals in October
2004;
•
several consultation papers and workshops;
•
the review by independent consultants of the distributors’ growth forecasts and
expenditure proposals;
•
numerous requests for further clarifying information;
•
the publication in March 2005 of a Position Paper which set out the Commission’s
preliminary thinking on a range of key issues for the review and submissions from
stakeholders to the Position Paper;
•
the Draft Decision and extensive submissions by the distributors and other stakeholders
in relation to the Draft Decision; and
•
this Determination.
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Issues arising from the review
Whilst there has been a marked improvement in the service performance of electricity
distributors since the industry was restructured in 1995, the role of economic regulation in
guiding further improvements has never been more important. The privatisation of an
industry that displays monopoly characteristics will often give rise to tensions between a firm
seeking to maximise returns to shareholders and the expectations and objectives of
customers. The task of economic regulation is therefore to design incentives that align the
commercial interests of the distributors with the interests of society at large, namely securing
a reliable supply at an optimal price and quality.
However, regulators must overcome a number of not insubstantial hurdles when
implementing effective regulatory controls. The most notable of these relates to the
information asymmetry that exists between the regulator and the utility. The combination of
the reliance on the information provided by the utility and a focus on shareholder value
means that utilities have a clear incentive to “talk up” the future operating cost and
investment requirements of their networks and to “talk down” their future sales potential, in
order to secure more generous price controls. Designing and managing regulatory processes
that recognise these incentives and address the asymmetry of information is a well recognised
and fundamental challenge for monopoly infrastructure regulators.
The regulatory controls that were introduced by the Office of the Regulator-General in 2001
were specifically designed to address these hurdles. The implementation of a building block
revenue requirement along with an efficiency carryover mechanism was designed to provide
distributors with an incentive to reveal their efficient costs over the course of the first
regulatory period.
The central proposition of the framework was that under-spending against the expenditure
benchmarks would be rewarded equally irrespective of the year in which the under-spending
occurred. Under this framework it was assumed that the distributors would have a reduced
incentive to defer efficiency improvements or allow expenditure to increase towards the end
of one regulatory period so as to obtain more generous expenditure forecasts in the following
regulatory period. Given this, it was expected that revealed costs from the first regulatory
period could be given greater weight in establishing efficient expenditure forecasts for the
next regulatory period. In hindsight the Commission underestimated the challenges that
would present themselves in relying on the reported costs of the distribution businesses.
One of the main factors complicating the Commission’s task has been the considerable
restructuring of the distribution businesses since the implementation of the current price
controls, including arrangements entered into by the distributors with entities with common
ownership that are not directly covered by the regulatory regime.
In the period since the last review, many of the distributors have entered into or extended
existing arrangements under which other parties provide services to the legal entity
responsible for distribution services under the Distribution Licence. Where there is an
incentive to enter into an arrangement that is not arm’s length, the potential effect of such
arrangements is to inflate or obscure the reported costs of the distributor.
Outsourcing arrangements, multi jurisdictional operations and other integrated organisational
arrangements have accentuated the challenges with respect to obtaining transparent cost data
and unravelling complex and changing cost allocations. This has raised issues in reconciling
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Essential Services Commission, Victoria
Final Decision
historic information with current forecasts and therefore the ability to determine reasonable
forecasts and the efficiencies to be shared with customers.
Throughout the price review the Commission faced considerable difficulties with obtaining
information to enable a proper assessment to be made of the costs incurred in providing
distribution services. In some instances the difficulties were confined to delays, whilst in
others the information was withheld entirely. In one instance, where information was not
voluntarily provided by a significant service provider to a licensed distributor, the
Commission issued notices under section 37 of the Essential Services Act 2001. The notices
were subsequently appealed on the grounds that they were not made in accordance with the
law and were unreasonable. The Appeal Panel upheld the appeal in part on the basis that the
period of time within which the service provider was required to provide the documents and
information specified in the notices was not sufficiently long. This was in spite of the fact
that the information had been sought over a long period of time.
Although the Appeal has highlighted aspects of the law which will require clarification, and
some procedural improvements which will need to be made in relation to the issue of
section 37 notices, the Appeal Panel clearly accepted that the Commission could serve such a
notice on parties other than regulated distributors and that the Commission did have the
power to obtain the details of industry costs from sub contractors.
The entry by distributors into outsourcing arrangements, particularly where those outsourcing
arrangements have not or are not capable of being appropriately market-tested, and the
regulatory treatment of such outsourcing arrangements, is an issue that has been the subject
of much consideration by the Commission. In this, the Commission is not alone — regulators
in other industries and jurisdictions face similar challenges. However, it is critical to the
integrity of the regulatory framework that regulators are able to investigate these
arrangements and ensure that their existence does not prejudice the delivery of the benefits to
customers under the regulatory framework.
As a result of the difficulty that the Commission has had in obtaining information on the costs
of providing distribution services from at least some of the distributors, the Commission has
been forced to either directly estimate relevant out-turn costs or make a number of
adjustments to the information reported to derive their relevant costs for the 2001-04 period.
The necessity for such adjustments arises in the context of all forms of monopoly regulation
that rely on business-specific cost information, because of the associated incentive to report
or represent costs as being greater than they are. This is particularly the case where the
benefits of efficiencies are required to be shared between distributors and customers, in which
case there is a greater incentive for a distributor to enter into arrangements or adopt practices
that distort the sharing of the benefits.
Whilst the Commission is satisfied that the expenditure allowances which it has made are
more than sufficient for the distributors to meet their obligations and future investment needs,
the Commission notes that an approach that relies on adjustments to reported expenditure
may not be sustainable over the longer term.
Looking ahead
An important backdrop to this review is the planned transfer of responsibility for rule making
and for regulation of energy distribution businesses to the new national framework for
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Essential Services Commission, Victoria
Final Decision
regulation of energy markets, administered by the Australian Energy Market Commission
(AEMC) and the Australian Energy Regulator (AER). Although the detailed transition path is
still to be finalised, the working presumption is that the price controls applying to Victorian
electricity distributors from 2011 will be determined by the AER, under a framework of rules
to be reviewed and implemented by the AEMC. It is inevitable that this framework will
involve some change to the legal and regulatory environment that governs this review.
The Commission believes it important to note that its approach to this review has not been
altered by the prospect of change that the new national framework involves. Rather, the
Commission has approached this review, first, by applying the existing legal framework as it
best sees fit and, second, by articulating the principles it has applied and the facts it has
considered as clearly as possible. In the Commission’s view, this not only represents good
regulatory practice, but it also means that, once the transfer of responsibilities does take
place, it will be relatively easy for the AER to understand what was done and why, and for
the appropriate transition arrangements to be put in place.
Over the past year or more, the Commission has also sought to invigorate debate on the
potential for greater use of index-based approaches to regulating monopoly services,
including electricity distribution. The Commission’s principal motivation for this work is to
seek refinements that can improve both the process and the incentives arising in the conduct
of regulatory reviews. The Commission is particularly interested in regulatory approaches
that either reduce or eliminate the role of forecasts in regulatory reviews as well as the role
played by company specific reported costs in determining efficiency outcomes, both of which
give rise to regulatory burdens and distorted incentives.
To this end the Commission has published a major report investigating and comparing the
incentive power of alternative regulatory regimes (PEG 2005b). The combination of positive
stakeholder responses, conclusions from the incentive power work and the continuing
challenge of determining forward looking building blocks in the face of strong information
asymmetries, has strengthened the Commission’s resolve to make progress in this area.
The Commission recognises that further work and consultation is essential to ensure that an
indexed-based approach to regulation can be established as a viable option for determining
price controls from 2011. Irrespective of which regulatory body is responsible for taking
forward the regulation of Victorian and other electricity distributors, it will remain an
inescapable challenge for the economic regulation of long lived infrastructure assets to
provide the optimum incentives for efficient asset management and investment while also
delivering appropriate price-service outcomes for customers.
Although there is considerable debate over how company specific cost data is used in
regulation the ability for a regulator to have access to, and rely on, reliable, consistent and
robust information on the provision of regulated services is critical to the effective
implementation of all forms of regulation, including indexing and price monitoring.
October 06
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Essential Services Commission, Victoria
Final Decision
1 INTRODUCTION
This is the second review of the electricity distribution price controls to apply to the five
Victorian distributors undertaken by an independent regulator. The first review was
undertaken by the Office of the Regulator-General (the Commission’s predecessor) in 2000
for the 2001-05 regulatory period. The initial price controls and related arrangements for the
1995-2000 regulatory period were established by the Victorian Government in the context of
restructuring and privatising the electricity distribution industry in the mid-1990s.
This review has provided an opportunity for Victorian customers to consider their servicerelated requirements and the prices that they are willing to pay for those services. It has also
provided an opportunity for the Commission and stakeholders to review the current
regulatory approach and identify areas that could be improved based on the experience to
date.
The Commission has undertaken extensive consultation with stakeholders and information
gathering and analysis in reaching this Determination.11 Consultation began in March 2004
and has taken the form of consultation papers, workshops, public information sessions in
Melbourne and regional centres and submissions from the distributors and other stakeholders.
A Draft Decision was released in June 2005 that provided stakeholders with the opportunity
to comment on the Commission’s views before it made its Determination. Advice has also
been obtained from technical consultants.
The Commission sought feedback on the services and service levels Victorian customers are
receiving and considered opportunities to further improve the regulatory arrangements to
ensure that they provide balanced incentives for distributors to deliver services at least long
term cost.
This Determination sets out the price controls to apply for the use of the electricity
distribution system and to prescribed metering services over the period from 1 January 2006
to 31 December 2010. It also sets out the service levels that the distributors will be required
to deliver over the period.
1.1 Legislative framework
The Commission has undertaken this price review in an environment of change. The Council
of Australian Governments (COAG) is currently working towards national regulation of the
electricity industry. Once this national regulatory framework and the institutions to
administer it have been agreed and established, it is intended that State Governments will
transfer responsibility for the regulation of electricity distribution services to a new energy
regulatory body — the Australian Energy Regulator (AER). This means that the Commission
is unlikely to undertake the next review of the electricity distribution price controls.
11
The Determination comprises Final Decision Volume 1 — Statement of Purpose and Reasons and Final Decision
Volume 2 — Price Determination
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Essential Services Commission, Victoria
Final Decision
While the Commission has been conscious of the changes that are occurring, it has been
required to undertake this price review under the current Victorian statutory framework for
the regulation of the electricity distribution businesses.
The legal framework that has guided the 2006 price review includes the Essential Services
Commission Act 2001, the Electricity Industry Act 2000 and the Tariff Order. In making its
Determination, the Commission has had regard to the objectives specified by this legal
framework and has made its Determination in accordance with this legal framework.
The Essential Services Commission Act sets out the objectives of the Commission in
performing its functions and exercising its powers. It also sets out the powers the
Commission has in relation to the regulation of electricity distribution charges, the matters it
must have regard to and requirements with which the Commission must comply in making a
Determination that regulates such charges.12
The Commission’s primary objective is to protect the long term interests of Victorian
consumers with regard to the price, quality and reliability of essential services. This includes
services provided by the electricity distribution industry.
In seeking to achieve this primary objective, the Act requires the Commission to have regard
to the following facilitating objectives:
•
to facilitate efficiency in regulated industries and the incentive for efficient long-term
investment;
•
to facilitate the financial viability of regulated industries;
•
to ensure that the misuse of monopoly or non-transitory market power is prevented;
•
to facilitate effective competition and promote competitive market conduct;
•
to ensure that regulatory decision making has regard to the relevant health, safety,
environmental and social legislation applying to the regulated industry;
•
to ensure that users and consumers (including low-income or vulnerable customers)
benefit from the gains from competition and efficiency; and
•
to promote consistency in regulation between States and on a national basis.
In addition, the Electricity Industry Act requires the Commission to promote:
•
a consistent regulatory approach between the electricity and gas industries; and
•
the development of full retail competition.
Apart from these two Acts, the other principal statutory instrument that has guided the
Commission in this review is the Tariff Order issued under the Electricity Industry Act.
Clause 2.1 of the Tariff Order requires the Commission to utilise price based regulation
adopting a CPI-X approach, and not rate of return regulation. Other elements of clause 2.1
require the Commission to have regard to the need to:
•
12
provide each distributor with incentives to operate efficiently;
Essential Services Commission Act 2001, s. 8, 14, 30, 32, 33 and 35
October 06
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Essential Services Commission, Victoria
Final Decision
•
ensure a fair sharing of the benefits achieved through efficiency gains between
customers and the distributors;
•
ensure appropriate incentives for capital expenditure and maintenance in the
distributors’ distribution systems; and
•
have regard to the level of executive remuneration in each distributor by reference to
any relevant interstate and international benchmarks for such remuneration.
Clause 2.1 also specifies the manner in which the Commission is to value the distributors’
fixed assets, which were in existence as at 1 July 1994, and requires the Commission to adopt
a regulatory period of no less than 5 years.
Clause 2.2 of the Tariff Order is also particularly relevant to this price review. It specifies the
criteria to be applied by the Commission in determining, and the manner for determining,
whether a distribution service is an excluded service. An excluded service is a service the
charge for which is excluded from the price controls. The terms and charges for these
services are regulated by the Commission in accordance with the distributors’ distribution
services.
The Commission is expressly required to adopt an approach and methodology in regulating
prices which the Commission considers will best meet its statutory objectives referred to
above.13 However, within these constraints, the Commission is empowered to regulate the
relevant prices in any manner it considers appropriate.14
Within its legal framework, the Commission has broad discretion in determining the
regulatory approach adopted. As the Victorian Supreme Court stated with respect to the
Office of the Regulator-General in TXU Electricity v Office of the Regulator-General:15
The wording of cl.5.10,16 the purposes of the legislation and the objectives of the Office
set out in the legislation, together with any relevant matters found in s.25(4)17 which
were not inconsistent with the Tariff Order, establish that the task left to the Office
involved the Office making its own decision with respect to the most appropriate
methodology to achieve the incentive objectives of the price fixing exercise.
This involved the Office making its own investigations of material that it could, and
making its own judgment as to relevant factors, the methodology used and the weight
that should be attached to the various relevant factors. The task was entrusted by
Parliament to the Office.
…
In the final analysis, it was a matter for the Office to investigate and obtain what
information it could, relevant to its assessment, to select relevant matters to take into
account and to determine the proper methodology. The choice of techniques for
estimation and analysis, and the utility of certain matters that should be taken into
13
14
15
16
17
Essential Services Commission Act 2001, s. 33(2)
Essential Services Commission Act 2001, s. 33(5)&(6)
[2001] VSC 153, at par.314, 315 & 317
The equivalent provision of clause 5.10 in the old Tariff Order is now clause 2.1 in the new Tariff Order.
The equivalent provision of s. 25(4) of the Office of the Regulator-General Act 2004 is now s. 33(3) of the Essential
Services Commission Act 2001.
October 06
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Final Decision
account were all properly left, in my view, to the expert discretion of the Office. The
Office employed and engaged consultants in the fields of price regulation and
economics, and the Parliament and the framers of the Tariff Order intended that these
matters should all be left to the good judgment of the Office.
In this price review, as it did in the last price review, the Commission has consulted widely
with stakeholders in developing its framework and approach and in making this
Determination. Having given detailed consideration to the submissions, feedback and
information received from stakeholders and the requirements under its legislative framework,
the Commission has made its Determination. In doing so, the Commission has exercised the
discretion allowed to it under its legal framework, while also complying with the objectives
and requirements of this framework.
1.2 The Commission’s consultation process
The Commission began consultation on the 2006-10 Electricity Distribution Price Review in
March 2004 with the release of Consultation Paper No. 1: Framework and Approach. In this
paper, the Commission indicated its intention to follow a consultation process that was open
and transparent and provided stakeholders with sufficient opportunity to present their views.
To achieve this aim, the Commission indicated that it would consult widely and ensure all
interested stakeholders had access to sufficient information on the process being followed and
the issues being considered (ESC 2004b, p. 4-5).
The Commission has undertaken extensive consultation and analysis, including:
•
The release of Consultation Paper No. 1 which set out for comment the proposed
framework for, and approach to, reviewing the existing price controls and establishing a
new set of price controls for the regulatory period commencing 1 January 2006.
•
A series of public information sessions held in Melbourne and several regional centres
to communicate the commencement of the price review and the content of Consultation
Paper No. 1 to Victorian stakeholders (March-April 2004).
•
Further consultation papers, discussion papers, open letters and workshops on:
•
y
the service incentive arrangements (papers in April 2004 and August 2005 and
workshops in May 2004 and July 2005);
y
excluded services (paper and workshop in May 2004);
y
the efficiency carryover mechanism (workshop in June 2004);
y
metering issues (paper in June 2004 and workshops in June 2004 and July 2005);
y
pricing issues (discussion papers in May, July and September 2004 and
workshops in June, July, August, September and November 2004 and March
2005); and
y
expenditure issues (open letter and workshop in July 2005).
The release of Final Framework and Approach: Volume 1, Guidance Paper in June
2004. This set out the framework and approach that the Commission would follow in
making its decision on the price controls. Together with Final Framework and
Approach: Volume 2, Information Templates, Volume 1 also provided guidance to the
distributors for the preparation of their price-service proposals.
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Final Decision
•
The release of a Summary of the Victorian Electricity Distributors’ Price-Service
Proposals to provide a broad overview of the distributors’ price-service proposals and
assist stakeholders to understand the content of these documents (November 2004).
•
The release of an Issues Paper which raised several major issues arising from the
Commission’s initial analysis of the distributors’ price-service proposals (December
2004).
•
The release of a Position Paper that aimed to provide an earlier opportunity to respond
to the Commission’s preliminary views in advance of its Draft Decision (March 2005).
•
The release of a Draft Decision that provided an opportunity for stakeholders to
comment and discuss the Commission’s views before the final determination (June
2005).
•
Further public information sessions in Melbourne and regional centres to communicate
the Commission’s Issues Paper, Position Paper and Draft Decision to stakeholders and
provide an opportunity for stakeholders to discuss the issues raised and the
Commission’s preliminary views (December 2004, April 2005 and June 2005).
The Commission’s consultation process, including the publications released, submissions
received and public forums and workshops held, is set out in further detail in Appendix A.
The appendix also lists the technical consultancy advice that the Commission has received.
1.3 The Commission’s broad framework and approach
In Consultation Paper No. 1, the Commission indicated that it proposed to adopt a framework
and approach for the 2006 price review that was similar to that used in the 2001 price review,
while also enhancing and refining it where this was considered appropriate based on
experience to date (ESC 2004b, p. 8).
As required by the Victorian Tariff Order, the Commission has maintained a CPI-X approach
to the 2006-10 regulatory period and has utilised the ‘building blocks’ approach (with an
efficiency carryover mechanism) to determine the forward-looking revenue requirements for
each distributor. The building blocks approach is characterised in Box 1.1.
In making this Determination, the Commission has used as its starting point reported
(adjusted) out-turn information on expenditure, financing requirements, service performance,
energy consumption, customer numbers and peak demand growth for the current period.
With the performance over the current period as a starting point, the onus has been on the
distributors to provide sufficient supporting information on why their forecasts for the
2006-10 regulatory period of costs, growth and/or service performance should vary from
those achieved over the current period. Such justifications may include, for example, any
changes in obligations or functions that would cause costs to change over the next period and
evidence of customers’ willingness to pay for any proposed improvements in service
performance.
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Final Decision
Box 1.1:
Building blocks approach to setting the price controls
The building blocks approach can be characterised by three steps — determining outputs/outcomes; determining
the revenue requirement necessary to finance these output/outcomes; and translating the revenue requirement
into a price control that would permit recovery of the required revenue.
Step 1: Determining outputs/outcomes
The first step to determining the price controls is to decide upon the service outcomes that the distributors are
required to deliver over the period. These outcomes will reflect the service standards that are set as part of this
price review (see Chapter 2) as well as legislative and functional obligations that the distributors must meet in
accordance with licensing or legislative requirements. In setting these service outcomes, it is also necessary to
consider anticipated future peak demand and customer numbers (see Chapter 4).
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Box 1.1 (cont.):
Building blocks approach to setting the price controls
Step 2: Determining the revenue required
Having determined the outcomes that must be delivered, the revenue requirements are then determined that are
sufficient to enable the distributors to deliver these outcomes efficiently. The building blocks approach involves
building up the distributors’ revenue from key components that reflect their operating and maintenance costs
(Chapter 6) and financing requirements (Chapter 9). The distributors’ financing costs (return on and of capital)
are built up with reference to the rolled forward value of their regulatory asset bases (Chapter 8) and the capital
expenditure that they must undertake (Chapter 7).
The Commission’s approach also incorporates an efficiency carryover amount into the revenue requirement that
allows the distributors to carry over benefits of any efficiency gains achieved against the expenditure forecasts
in the prior regulatory period into the next regulatory period (Chapter 10).
Step 3: Translating the revenue requirement into a price control
Having determined the revenue required (Chapter 11), it is then translated into unit prices using forecasts of
energy consumption and customer numbers (Chapter 4). This is then translated into specific tariff proposals in
accordance with a price control mechanism which specifies how prices will be adjusted annually (Chapter 12).
Relying on actual costs incurred in providing distribution services as the Commission’s
starting point for assessing the distributors’ proposed changes to expenditure going forward
requires an accurate record of the costs incurred in carrying out each distributor’s functions
presented on a basis that is consistent with the 2001-05 building blocks benchmarks and the
distributors’ expenditure proposals for the 2006-10 regulatory period. For the purposes of this
price review, the Commission has made adjustments to the expenditure reported by the
distributors to ensure that current costs and future estimates are presented on a ‘like-for-like’
basis which permits valid comparisons.
The Commission’s framework and approach for determining the distributors’ growth
forecasts had anticipated that it could rely on the distributors obtaining independent
verification that their forecasts, assumptions, key input data and forecasting methods are
reasonable and that the forecasting method had been applied appropriately.
However, in the course of the price review, the Commission identified a number of issues
with the distributors’ growth forecasts that led it to undertake a more detailed review. These
issues included apparent inconsistencies in the assumptions used and between forecast and
historic data.
For metering, the Commission’s framework and approach indicated that standard metering
services for small customers (those who consume less than 160 MWh per annum and do not
have a remotely read meter) would be regulated as prescribed services, with the charges for
these services set separately to distribution use of system charges. The framework and
approach also stated that the Commission would build up a revenue requirement for
prescribed metering services under an approach similar to that used for prescribed
distribution use of system services. Metering services for customers who consume more than
160MWh per annum or have a remotely read interval meter installed will be regulated by the
Commission as an excluded service.
The Commission has maintained its current approach to the regulation of excluded service
charges, although it has set out more detailed information requirements and clarified the
policies and definition of each excluded service charge.
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1.4 Structure of the Decision
This volume is structured in four parts. Part A provides an Overview of the decision and Part
B provides the Commission’s decision on prescribed distribution services — both distribution
use of system (DUoS) and metering services.
•
Part B1 sets out the Commission’s decision on service standards (Chapter 2), the
service incentive arrangements (Chapter 3) and growth forecasts (Chapter 4).
•
Part B2 sets out the decision on the components of the distribution use of system
(DUoS) revenue requirement:
y
relevant costs (Chapter 5);
y
operating and maintenance expenditure (Chapter 6);
y
capital expenditure (Chapter 7);
y
the value of the regulatory asset base (Chapter 8);
y
cost of capital financing requirements (Chapter 9); and
y
the efficiency carryover mechanism (Chapter 10).
•
Part B3 sets out the decision on the revenue requirements (including P0s and X-factors)
for each distributor and the price control arrangements applying to DUoS.
•
Part B4 sets out the Commission’s decision on prescribed metering services.
Part C discusses the Commission’s decision on the arrangements applying to excluded
services and Part D provides a summary of the Commission’s decision by distributor.
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PART B1:
SERVICES PROVIDED AND ENERGY
DELIVERED
In this Part, the Commission sets out its Final Decision and reasons on the targeted levels for
the service reliability, quality of supply and customer service measures, the distributors’
reporting requirements, the service incentive arrangements and the growth forecasts that
underpin the Final Decision on the revenue requirements for each distributor.
The revenue requirements and X-factors set out in this Final Decision have been established
with reference to a set of targeted levels of service that each distributor is expected to achieve
over the period. The Commission sets targeted levels to ensure that any reductions in
expenditure that distributors achieve over the period are not achieved to the detriment of the
standards of service that they provide.
The distributors are held accountable for their performance through monitoring and publicly
reporting on their performance against the targeted levels as well as through the financial
incentive arrangements that the Office of the Regulator-General (ORG) set in place at the last
price review. Under the S-factor scheme, the distributors have been financially rewarded or
penalised for their relative service reliability performance through an adjustment to the price
control mechanism. That is, distributors can earn more (or less) revenue by improving (or
reducing) their service performance.
The ORG also set in place a Guaranteed Service Level (GSL) payments scheme that aimed to
ensure that individual customers, particularly worst-served customers, received a minimum
level of service reliability. Under the GSL payments scheme, the distributor is required to
make automatic payments to customers who receive a level of service reliability that is worse
than a pre-determined threshold.
Average reliability levels
In the 2001-05 price review, the ORG decided upon service reliability targets that anticipated
improvements in the average reliability of supply over the 2001-05 regulatory period. At the
time, the ORG (2000a, p. 14) concluded after extensive consultation that customers valued
improvements in reliability. Expenditure amounts were incorporated into the revenue
requirements to achieve those improvements.
With the exception of SP AusNet,18 the distributors have improved their service reliability
performance over the period and, in a number of cases, are outperforming the average
reliability targets while also improving the level of service reliability to worst-served
customers. As a result, the distributors have earned additional revenues through the S-factor
scheme and paid out fewer GSL payments to worst-served customers than was anticipated at
the last price review. Conversely, SP AusNet has been financially penalised for its
performance through lower revenues.
While in this price review customers have emphasised the importance that they place on a
reliable electricity supply, the Commission has received little indication that customers value
further improvements in average reliability levels.
18
Formerly TXU
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Final Decision
Consequently, for reporting and monitoring purposes, the Commission has set the targeted
levels of service for the 2006-10 regulatory period equal to the 2005 targets, except where a
distributor is consistently outperforming this target. In this case, the current level of
performance is considered in deciding the new targeted level.
This means that, unlike in the last price review, no allowance is being made in the
expenditure forecasts for further improvements in average reliability levels. Rather, any
further improvements will be funded through the S-factor scheme after the improvement in
reliability has been delivered.
For the purposes of the S-factor scheme, the reliability targets are the same as the
2005 targets which ensures that distributors are not rewarded for improvements already
achieved and already paid for by their customers. That is, they will only receive additional
revenue for improvements when further improvements in outcomes are delivered and
customers receive the service they then pay for.
Worst-served customers, quality of supply and customer service
Despite general satisfaction with current average reliability levels, customers have indicated
that pockets of poor reliability remain and that quality of supply and customer service have
both become increasingly important.
The Commission received feedback from customers situated in heavily wooded areas such as
Lavers Hill and the Mt Dandenong region that suggests that current reliability levels in these
areas are not sufficient. For other customers, the voltage that they receive is either insufficient
for their equipment to operate effectively or is too high, thereby causing damage to their
equipment. In public information sessions, customers also indicated their dissatisfaction with
the performance of call centres and the quality of information that is provided by these call
centres.
The Commission has addressed these concerns in its Final Decision by expanding the range
of measures and targets against which the distributors are required to publicly report.
Distributors must continue to report upon their performance against the service reliability
targets but must now also report on the following:
•
The annual duration of interruptions (planned and unplanned) experienced by the
15 per cent of customers in their area that experience the longest time off supply in that
year.
•
A breakdown of the causes of unplanned interruptions and the actions the distributor is
proposing to undertake to improve its performance.
•
Low reliability feeders for which the average minutes off supply (for planned and
unplanned interruptions) is above a threshold which is reduced relative to the existing
threshold.
•
Low reliability feeders for which the frequency of momentary interruptions is above a
threshold and zone substations and feeders which are not compliant with the standards
as set out in the Electricity Distribution Code.
•
Where a zone substation (for quality) or feeder (for reliability or quality) is reported,
the distributor will be required to provide comments regarding its plans for that zone
substation or feeder.
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Final Decision
The Commission has also adjusted the thresholds at which the GSL payments scheme begins
to operate, and increased the size of the required payments to customers. These adjustments
aim to increase the incentive that distributors have to improve reliability to worst-served
customers and to customers who are not worst-served but who receive a level of supply
reliability less than the average.
An improvement in reliability to those receiving less than the average level of reliability may
also improve a distributor’s performance against the average reliability targets. Hence,
distributors may have an additional incentive to improve reliability to those receiving less
than the average because of the potential to earn an additional financial reward under the
S-factor scheme.
In its Final Decision, the Commission is requiring the distributors to continue to report
against the quality of supply measures that they currently report against. The focus for the
2006-10 regulatory period is on providing an accurate picture of the quality of supply and
improving compliance with the Electricity Distribution Code for all customers.
The magnitude of the expenditure required to ensure all customers’ supply is compliant with
the Code is such that the expenditure will span multiple regulatory periods. Distributors will
therefore be required to prioritise their spending during the next regulatory period.
While the Commission would prefer that quality of supply expenditure is linked financially to
the achievement of outcomes, the minimal historical data available and the fact that the data
that is available is only from a sample of points on some feeders may result in perverse
outcomes where a financial incentive is applied. Accordingly the Commission has decided
not to include quality of supply measures in either the S-factor scheme or the GSL payments
scheme for the 2006-10 regulatory period.
In this Final Decision, the Commission has also set targeted levels for the proportion of calls
answered by a call centre within 30 seconds and the number of overload events occurring
during the 2006-10 regulatory period. The distributors are required to publicly report against
these levels on an annual basis and a call centre performance measure has been included in
the S-factor scheme.
Growth forecasts
Forecasts of growth in customer numbers, energy consumption and peak demand are central
to translating the revenue requirements into the average price changes implied by the CPI-X
form of price control. They are also used in establishing estimates of load-related capital
expenditure.
The distributors have earned higher revenues over the current regulatory period than forecast
by the ORG at the last price review due to higher than anticipated growth in customer
numbers and energy consumption. This outcome has been compounded by the restructuring
of tariffs in a manner that has caused revenue to be higher than forecast for any given volume
growth, for example by increasing the variable component of tariff charges.
The Commission has not accepted the forecasts of customer numbers and energy
consumption submitted by the distributors. The distributors’ forecasts factor in assumptions
on Victorian Gross State Product, energy conservation policies and downside risks to
Victorian manufacturing activity that appear overly conservative when compared to other
available sources of information.
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2 SERVICE STANDARDS
A key element of incentive-based regulation is to provide adequate incentives for distributors
to achieve the level of service that is valued by customers. Mechanisms to ensure sufficient
incentives exist for distributors to achieve service levels valued by customers, and for which
they are accountable, are discussed in detail in this Chapter.
Incentive-based regulation provides incentives for distributors to achieve efficiencies in the
provision of services by allowing them to retain any savings in the cost of service provision
for a period. To ensure that any reductions in expenditure are due to efficiencies and not a
deteriorating level of service, the Commission and regulators in other jurisdictions have
recognised the importance of clearly specifying service standards for the regulatory period,
and monitoring and publicly reporting against the targeted levels, so that distributors are
accountable for achieving those standards.19
Measures of service standards usually distinguish between those for reliability of supply,
quality of supply and customer service. Whilst reliability of supply is concerned with the
availability of supply, quality of supply is concerned with the characteristics of the electricity
supply delivered to customers’ premises, specifically whether there are short term or transient
voltage increases (voltage surges) or reductions (voltage sags) and harmonic distortions.
Customer service relates to the distributors’ performance in meeting customer requirements
such as responding to queries, providing information and meeting timelines.
One of the key features of the Commission’s decision on the price controls to apply for the
2006-10 regulatory period is to ensure that customers receive the service that they pay for.
This is to be achieved through identifying and measuring the level of service that is expected
to be provided, and outlining clear reporting requirements, and by providing financial
rewards and penalties for the service outcomes delivered. This Chapter provides the
Commission’s decision on the service levels customers should receive and the reporting
requirements in respect of those services.
Reporting on the service delivered plays an important role in service provision. It provides:
•
information to customers on the distributors’ performance against the level of service
that customers should expect;
•
a focus on the performance standards to be met; and
•
information to enable further service measures to be incorporated into the financial
incentive arrangements over time.
The Commission’s decision on service standards is set out in Section 2.1, while in Section 2.2
the reasons for the decision on service standards are set out. Reliability measures, quality of
supply measures and customer service measures are discussed in Sections 2.2.1, 2.2.2 and
2.2.3 respectively.
19
Targeted levels are used as the basis for reporting purposes to monitor whether customers are getting the service they
are paying for. Generally, distributors should be able to meet or exceed the targeted levels in most years. Targeted
levels are different from the S-factor targets that apply to the service incentive mechanism described in Chapter 3.
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To encourage distributors to maintain and improve service provision, where efficient to do
so, a service incentive mechanism has been provided. This is discussed in detail in Chapter 3.
2.1 Final Decision
2.1.1 Reliability measures
The distributors will continue to report against the following average reliability measures, by
network type: annual duration of unplanned interruptions (unplanned SAIDI), annual
frequency of unplanned interruptions (unplanned SAIFI), annual duration of planned
interruptions (planned SAIDI), annual frequency of planned interruptions (planned SAIFI)
and frequency of momentary interruptions (MAIFI). MAIFI will continue to be defined as an
interruption of duration less than one minute.
The targeted level for each of these reliability measures during the 2006-10 regulatory period
is provided in Table 2.1. The targeted levels do not incorporate any improvement in the
average measures of reliability over the 2006-10 period. Rather, incentives to improve
reliability are provided to distributors through the service incentive arrangements, through
increased revenues when improved outcomes are delivered (see Chapter 3).
Table 2.1:
Annual targeted levels of reliability, by distributor, 2006-10 regulatory
period
Network
Type
AGLE
CitiPower
Powercor
SP AusNeta
United Energy
a
Annual targeted levels of reliability, 2006-10
Unplanned
Planned
interruptions
interruptions
SAIDI
SAIFI
SAIDI
SAIFI
MAIFI
Urban
73
1.27
6.0
0.03
0.8
Short rural
113
2.25
14.0
0.08
2.6
CBD
14
0.25
5.9
0.02
0.03
Urban
35
0.80
9.9
0.03
0.3
Urban
98
1.63
16.0
0.09
1.5
Short rural
118
1.80
35.0
0.15
3.1
Long rural
297
3.30
70.0
0.25
9.0
Urban
109
1.82
16.0
0.09
3.5
Short rural
185
2.73
35.0
0.15
4.0
Long rural
300
4.28
70.0
0.30
10.8
Urban
59
1.06
16.0
0.10
1.4
Short rural
96
2.03
35.0
0.15
3.4
Formerly TXU
The distributors will also report the annual minutes off supply (SAIDI for planned and
unplanned interruptions) experienced by the 15 per cent of customers in their area
experiencing the longest time off supply in that year. Table 2.2 sets out the targeted levels of
SAIDI for the worst served 15 per cent against which the distributors are to report.
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Table 2.2:
Targeted levels of reliability experienced by the worst served 15 per cent
of customers
Total minutes off supply (SAIDI) for worst
served 15 per cent
AGLE
267
CitiPower
138
Powercor
535
SP AusNet
United Energy
734
231
Additionally, the distributors will provide a breakdown of the causes of unplanned
interruptions on an annual basis into the following categories:
•
weather (for example, storms, rainfall, wind blown debris);
•
equipment failure;
•
operational error;
•
vegetation (for example, trees);
•
animals (for example, possums, birds);
•
third party impacts, including vehicle collisions, vandalism, dig-ins, bushfire, etc;
•
transmission failure;
•
load shedding;
•
inter distributor connection failure; and
•
other, which is to be clearly specified.
The distributors must provide an explanation for any significant, adverse year on year
changes, and identify any actions to address these changes.
Distributors will continue to report, on an annual basis, low reliability feeders for which the
average minutes off supply (for planned and unplanned interruptions) is above a threshold.
The thresholds for reporting these feeders during the 2006-10 regulatory period are as set out
in Table 2.3.
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Table 2.3:
Network Type
Thresholds for low reliability feeders, by network type,
2006-10 regulatory period
Average annual minutes off supply (SAIDI)
for planned and unplanned interruptions
Momentary Interruptions
(MAIFI)
70,
where number of interruptions is greater than 1
n/a
Urban
270
5
Short rural
600
12
Long rural
850
25
CBD
Additionally, the distributors will report, on an annual basis, low reliability feeders for which
the frequency of momentary interruptions is above a threshold. The thresholds for reporting
low reliability feeders with respect to MAIFI are as set out in Table 2.3.
Where a feeder is reported as a low reliability feeder, the distributor will be required to
provide comments regarding its plans for that feeder.
2.1.2 Quality of supply measures
The distributors will continue to report quality of supply against the following measures:
•
Number of over-voltage events – due to high voltage injection;
•
Number of customers receiving over-voltage – due to high voltage injection;
•
Number of over-voltage events – due to lightning;
•
Number of customers receiving over-voltage – due to lightning;
•
Number of over-voltage events – due to voltage regulation or other cause;
•
Number of customers receiving over-voltage – due to voltage regulation or other cause;
•
Number of voltage variations – steady state;
•
Number of voltage variations – one minute; and
•
Number of voltage variations – ten seconds.
The number of voltage variations will be broken down and data provided as measured at the
zone substation level, and as measured at the feeder level. Additionally, for the zone
substation level only, a breakdown of ten second voltage variations will be provided based on
the minimum voltage during that voltage variation (less than 70 per cent of nominal voltage,
less than 80 per cent of nominal voltage and less than 90 per cent of nominal voltage).
Given the level of non compliance with the quality of supply standards, as set out in the
Electricity Distribution Code, by Powercor, SP AusNet20 and United Energy, reasonable
expenditure has been provided to them to improve their compliance (refer Chapter 7). The
cumulative numbers of customers of these distributors who are expected to receive an
improvement in their quality of supply as a result of such improved compliance are provided
20
Formerly TXU Networks.
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Final Decision
in Table 2.4. The distributors will report on an annual basis the number of customers who
have received an improvement in the quality of supply.
Table 2.4:
Improvement in quality of supply, cumulative number of affected
customers, Powercor, SP AusNet and United Energy, 2006-10 regulatory
period
Year
Powercor
SP AusNet
United Energy
2006
9,200
12,988
200 – 400
2007
22,800
27,600
400 – 800
2008
35,400
43,837
600 – 1,200
2009
2010
47,400
59,000
61,697
81,181
800 – 1,600
1,000 – 2,000
Additionally, United Energy will improve the quality of supply at one zone substation per
annum.
The rural distributors (Powercor and SP AusNet) will increase the number of voltage
monitoring devices installed at the end of high voltage distribution feeders by 20 per cent by
the end of 2006. A plan is to be provided to the Commission by 31 December 2005
explaining where and when the additional voltage monitoring devices are to be installed.
These plans will be made available on the Commission’s website when received.
Additionally, the distributors will report, on an annual basis, zone substations and feeders
which are not compliant with the standards as set out in the Electricity Distribution Code.
Where a zone substation or feeder is reported, the distributor will be required to provide
comments regarding its plans for that zone substation or feeder.
Residential and small business customers will continue to be entitled to compensation, on a
like for like basis, for damage due to voltage variation (surges and brown outs).
2.1.3 Customer service measures
Call centre performance
Distributors will continue to report on the proportion of calls to their fault line answered
within 30 seconds and the number of occasions where the fault line is overloaded. The calls
to the fault line answered within 30 seconds will:
•
include telephone calls answered by an IVR (interactive voice response) within
30 seconds where the IVR provides substantive information and the customer does not
request to be connected to an operator; and
•
include telephone calls abandoned by the customer within 30 seconds of the telephone
call being queued for response by a human operator.
Where the time in which a telephone call is abandoned is not measured, then an estimate of
the number of calls abandoned within 30 seconds will be determined by taking 20 per cent of
the total number of abandoned calls.
Additionally, the total number of calls to the fault line excludes missed calls where the fault
line is overloaded.
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Distributors will also report on the number of overload events that occur in their call centres
each year. Where an overload event occurs, the distributor will provide an explanation of the
events that lead to the overload event occurring.
The targeted levels for the proportion of calls answered within 30 seconds and the number of
overload events per year during the 2006-10 regulatory period are provided in Table 2.5.
Table 2.5:
Annual targeted level of call centre response, by distributor,
2006-10 regulatory period
Proportion of calls to the fault line
to be responded to within 30
seconds (per cent)
Number of overload events
AGLE
75
0
CitiPower
80
0
Powercor
81
0
SP AusNet
70
0
United Energy
72
0
Metering related measures
The distributors will report against the following metering-related measures:
•
Number of interval meters installed during the year (by meter type);
•
Number of accumulation meters installed during the year (by meter type);
•
Number of scheduled meter reads; and
•
Number of reads estimated where meter is not read when scheduled.
Other customer service measures
The distributors will continue to report on the existing customer service measures for
complaints, street light repairs, appointments, new connections and planned interruptions for
which four days notice is not given. Where the Commission identifies additional relevant
customer service measures through its existing end-to-end (E2E) project, these measures will
be incorporated into the annual reporting by distributors.
The Commission will work with distributors and retailers to develop a “report card” on the
B2B capability and performance of the parties they interface with and, when completed, will
provide such reports on a regular (six monthly) basis.
2.2 Reasons for the Decision
2.2.1 Reliability measures
Reliability of supply is typically considered to be the most important characteristic of
distribution services. In its simplest terms, reliability of supply concerns whether electricity is
available when sought by a customer. Reliability measures typically focus on the extent of
availability, or non-availability, of electricity to customers.
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Reliability was also a key focus of the 2001-05 price review. As a result, better reliability
information is available in Victoria than in any other jurisdiction, and reliability has improved
over the last four years. For the 2006-10 regulatory period, the Commission has reviewed
whether the appropriate measures are being reported and that the level of service is
appropriate.
The reliability measures on which the distributors have reported during the current regulatory
period include:
•
CAIDI21 (customer average interruption duration index), which is the average time
taken for supply to be restored to a customer when a supply interruption (of duration
equal to or longer than one minute) occurs.
•
SAIFI (system average interruption frequency index), which is the number of occasions
when a customer could expect, on average, to experience a supply interruption (of
duration equal to or longer than one minute) in a year.
•
SAIDI (system average interruption duration index), which is the total minutes, on
average, that a customer could expect to be without electricity in a year due to supply
interruptions (of duration equal to or longer than one minute).
•
MAIFI (momentary average interruption frequency index), which is the total number of
momentary supply interruptions (of less than one minute duration) that a customer
could expect, on average, to experience in a year.
These measures are disaggregated by network type — central business district (CBD), urban,
short rural and long rural feeders — and, with the exception of MAIFI, for unplanned22 and
planned23 supply interruptions.
With the exception of United Energy, the distributors do not currently include in their
reporting of the measures, supply interruptions which occur during fault finding.24
Conversely, United Energy includes these supply interruptions in their reporting.
From 2006, the Commission will require all distributors, including United Energy, to report
interruptions on the same basis. United Energy advises that this change will not materially
affect its reporting of reliability performance.
Appropriateness of reliability measures
The Commission sought proposals from the distributors for service measures that may have
become more important to customers over the current regulatory period, or for measures that
may provide an early indication that issues are emerging with the reliability or security of the
electricity supply.
21
22
23
24
CAIDI is equal to SAIDI divided by SAIFI
Unplanned interruptions are those supply interruptions which are not planned by the distributor and for which a
customer does not receive prior notice.
Planned interruptions are those supply interruptions which are planned by the distributor and for which a customer
should receive prior notice.
When tracing faults on their networks, distributors seek to restore supply to customers as quickly as possible.
Sometimes this results in a faulty section of the network being joined to a healthy section, resulting in a short outage of
the healthy section.
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Final Decision
None of the distributors proposed any additional service measures against which their service
provision should be measured during the 2006-10 regulatory period.
While reliability outcomes reported over the period indicate that average reliability has
improved, the Commission has received a number of submissions throughout the price
review from customers that indicate that pockets of poor reliability remain.
Customers’ concerns about supply reliability are supported by the performance data reported
by the distributors by feeder. This data indicates that the unplanned minutes off supply
experienced by the worst served 15 per cent of customers is approximately 3 to 4 times
greater than that experienced by the average customer.
Although no additional measures were proposed regarding reliability to customers with worse
than average reliability, the Commission considered options to provide greater visibility in
this area given these submissions.
The Essential Services Commission of South Australia (ESCOSA) commissioned KPMG to
undertake a willingness to pay study in South Australia. The results of ESCOSA’s
commissioned study indicated that approximately 85 per cent of customers were satisfied
with their existing level of supply reliability, but around 15 per cent of customers were
dissatisfied with the level of their reliability (ESCOSA 2005, p. 41).
Anecdotally, similar results have been experienced in other jurisdictions with, on average,
between 80 and 85 per cent of customers satisfied with their existing level of supply
reliability, the proportion tends to be higher in urban areas and lower in rural areas.
Very little customer research has been undertaken on willingness to pay in Victoria.
Assuming a similar proportion of Victorian electricity customers are satisfied with their
electricity supply as in South Australia, the Commission set out in its Position Paper two
options to provide greater visibility of the performance experienced by the worst served
customers and against which targeted levels could be set:
•
Option 1: Reporting of the minutes off supply and number of supply interruptions
(sustained and momentary) experienced by the worst served 15 per cent of customers
for each distributor. Such measures are simple but do not illustrate the range of
reliability experienced by these worst served customers, although some of this
information can be obtained on the basis of the Guaranteed Service Level (GSL)
payments made and the low reliability feeders reported.
•
Option 2: Reporting of the proportion of customers (rather than the feeder averages)
who experience less than 2 hours, 2 – 4 hours, 4 – 8 hours, 8 – 12 hours and more than
12 hours off supply per annum, the proportion of customers who experience less than
2 interruptions, 2 - 4 interruptions, 4 – 8 interruptions, 8 – 12 interruptions and more
than 12 interruptions per annum, and the proportion of customers who experience less
than 5 momentary interruptions, 5 – 10 momentary interruptions, 10 – 15 momentary
interruptions, 15 - 20 momentary interruptions and more than 20 momentary
interruptions per annum. These measures are more complex to interpret than those
under Option 1 but illustrate more readily the range of reliability experienced by these
worst served customers. Additionally, this method of reporting is similar to that
currently provided in the Comparative Performance Report.
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Stakeholders varied in their responses — from support for reporting the worst served
customers (SP AusNet 2005b, p. 24, Johanna Seaside Cottages 2005b, p. 2), to concern that
any measure of the worst served customers would be problematic because distributors do not
have a precise picture of the connectivity of all customers (with the result that measures
relying on interruptions should be aggregated at the high voltage feeder level) (AGLE 2005b,
p. 15, CitiPower 2005b and Powercor 2005b).25 CUAC (2005c, p. 5) did not think that either
of the two options presented would give adequate information on performance in the worst
served areas.
The Energy and Water Ombudsman of Victoria (EWOV) (2005b, p. 2) supported Option 2 as
it would appear to far more readily allow customers to compare their experiences with other
customers’ experiences. Option 2 was also supported by the Energy Users Coalition of
Victoria (EUCV) (2005b, p. 62) as it would provide a sound trend basis for concerns about
the “health” of the network. The Commission notes that the data is currently available to
analyse the data at a feeder level as per Option 2, but not on a per customer basis.
Given that Option 1 is a simpler measure to report on and that reporting on option 2 on a per
customer basis is not currently possible, the Commission has decided to require reporting on
Option 1 rather than Option 2. However, while reporting of both SAIDI and SAIFI is
required, targeted levels of performance have been set for SAIDI only. This is because SAIDI
is a measure of both interruption duration and interruption frequency and the Commission
does not wish to constrain distributors from adopting improvement strategies that target either
measure, when deciding how to improve reliability performance to worst served customers.
The Commission will require distributors to continue to report against the average reliability
measures for the 2006-10 regulatory period by network type — that is, unplanned SAIDI,
unplanned SAIFI, planned SAIDI, planned SAIFI and MAIFI. In addition, distributors will be
required to report the annual minutes off supply experienced by the 15 per cent of customers
who are experiencing the longest time off supply in that year. This will measure and focus
accountability for the service reliability levels experienced by these customers. Where
connectivity information is not available, this measure will be based on reliability at the
feeder level. Together with the GSL payments and reporting of low threshold feeders, this
measure will illustrate the range of reliability service levels experienced by customers, and
enable customers to compare their experience to others.
In addition, the Lavers Hill & District Progress Association (2005, p. 5) suggested that:
The Commission could consider a “cause” measure. Such a measure would indicate
what action was necessary to improve reliability.
A “cause” measure would enable the Commission to monitor any trends in the causes of
unplanned interruptions which may provide early indications of a factor leading to
deteriorating reliability over the longer term. The Commission proposed a breakdown of
primary causes against which unplanned minutes off supply could be categorised. The cause
measures were proposed to identify issues that can be controlled by the distributors which
25
Historically, distributors have recorded the connection of each customer against the distribution transformer supplying
that customer. Hence, individual customers affected by faults on high voltage feeders supplying distribution substations
can be determined. However, individual customers affected by the impact of certain faults on the low voltage network
cannot be determined without a site inspection. Outages of high voltage feeders account for a high proportion of the
supply interruptions experienced by customers.
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may impact on reliability in the longer term. For example, if the minutes off supply due to
vegetation increases this may indicate insufficient vegetation management or if the minutes
off supply due to equipment failure increases this may indicate emerging issues with asset
replacement.
EWOV (2005b, p. 2) and CUAC (2005c, p. 2) supported the breakdown of unplanned
minutes off supply by primary cause as it provides useful comparative information for
customers, customer representatives, distributors and the Commission.
CitiPower (2005b, p. 2) and Powercor (2005b, p. 2) suggested additional causes for
unplanned minutes off supply. The Commission agrees that these additional causes would
improve the focus of the measure on causes for which distributors can reasonably be
considered accountable.
CitiPower (2005t, p. 5) and Powercor (2005aa, p. 9) also suggested that the ‘operational
error’ category be widened to capture events caused by operating the network such as
interruptions resulting from operational procedures. This would avoid the need to wait on the
outcome of investigations to determine if an error had occurred. However, the Commission
notes that this would capture normal operational activities and would not separately identify
those supply interruptions caused through error. It is also inconsistent with the national
reporting framework agreed through the Utility Regulators Forum. Given that this
information is required once per year, distributors should be able to correctly classify events
within the required reporting timeframe.
The Commission therefore requires that the distributors provide a breakdown of unplanned
interruptions on an annual basis, by the primary causes, as set in Section 2.1.1. The
distributors are to provide an explanation for any significant year on year changes, and
identify any actions to address these changes, where the movement is adverse.
Proposed improvements in reliability
With the exception of CitiPower, each of the distributors initially proposed expenditure over
the 2006-10 regulatory period to improve reliability.
•
AGLE proposed $1.3 million to improve areas of poor reliability.
•
Powercor proposed approximately $11 million to improve the overall reliability
performance to customers/areas currently receiving the lowest level of service and
improve the ability to automatically detect outages through automated fault indicators,
and approximately $6.6 million to continue existing reliability programs which will
maintain the 2005 average reliability over the 2006-10 regulatory period.
•
SP AusNet proposed $23 million to address reliability in its worst-served areas
(Murrindindi, Kinglake, Newmerella, Cann River, Mount Dandenong, Sassafras and
Upwey).
•
United Energy proposed $12 million to, among other things, reduce the frequency of
momentary interruptions and improve its performance in its worst served areas.
Additionally, in its enhanced offering, CitiPower proposed $28 million over the
2006-10 regulatory period to, among other things, increase the number of customers who
remain served during planned or unplanned transmission network contingencies and to place
network assets on the CBD fringe underground. In its enhanced offering, Powercor proposed
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$54 million over the 2006-10 regulatory period to, among other things, improve reliability
performance by targeting key feeders and reducing the impact and incidence of pole fires
(thereby resulting in a reduction in SAIDI of four minutes per annum), and $38 million to
improve the security of supply. Powercor has indicated that the improvement to the security
of supply will reduce the probability of a sustained outage, but the probability of a sustained
outage is so low that there is no quantifiable improvement in reliability.
Typically, improvements in reliability require expenditure. While improved management
practices through better information and procedures can impact reliability, these are likely to
be small, and it is the avoidance of a decline in reliability through poor management that is of
importance.
Expenditure on reliability improvement projects may be provided for in a number of ways —
through the distributor’s revenue requirement; or through improvements in service that is
rewarded through a service incentive arrangement (see Chapter 3); or through a direct
contribution by a customer. Except in the latter case, the additional costs incurred are passed
through to a distributor’s customers in the prices they pay for electricity and necessarily
involve those customers who do not receive a reliability improvement paying more so that
other, worse served customers can receive an improvement.
Where the costs are passed through in the revenue requirement, the distributor receives the
revenue regardless of whether the required outcomes are delivered (less any penalties through
the service incentive arrangements). Hence, under a pass through arrangement, distributors
have an incentive to under-invest against the forecast expenditure levels and it is uncertain
whether appropriate investments in reliability will be made. However, where the costs are
recovered through the service incentive arrangements, the distributor receives the revenue
only when the required outcomes are delivered, avoiding the incentive to under-invest.
The Commission consulted on whether expenditure for reliability improvements should be
provided, that is, whether customers were prepared to pay more to improve the levels of
supply reliability. Although many stakeholders, particularly customers experiencing poor
reliability, expressed dissatisfaction with the levels of reliability currently experienced, they
did not indicate that they were prepared to pay more for the proposed improvements in
reliability. In submissions and public information sessions held by the Commission,
stakeholders indicated that, in their opinion, they were already paying for a certain level of
reliability that is not being delivered and should not pay more to realise that level of
reliability. South Gippsland Shire Council (2005b, p. 1) considered it was inappropriate to
improve reliability only where customers are prepared to pay more, as this would severely
disadvantage rural and regional Victoria:
The consequence of poor reliability to a 300 head dairy farm should not be given the
same weight as a single family household.
However, some customers indicated their support for paying for reliability improvements
through the S-factor scheme. Under this approach, all customers pay more but only when
reliability improvements are actually delivered rather than through the revenue requirement,
which would require customers to pay more regardless of whether the reliability
improvement is delivered or not. For example, CUAC (2005b, p. 9):
… strongly believes that the service improvements should be funded through the service
incentive mechanism as opposed to claiming revenue requirements. Only the service
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incentive arrangements can ensure that the expenditure has been targeted to actually
improve the service levels.
SP AusNet (2005b, pp. 3-4) expressed a different view and considered that the regional
forums had demonstrated that the community expects that all customers should receive an
acceptable level of service reliability and are willing to pay for reliability improvements. It
considered that specific funding would be required to provide adequate investment in
reliability for worst served customers and, unless separate funding is to be provided, separate
monitoring was not needed. Further, business stakeholders such as the Geelong
Manufacturing Council and Bruck Textiles considered that improvements in reliability and
system security are valued and funding of these activities should be considered, although at
minimum cost to industry.
In support of its view, SP AusNet indicated that customer consultations it had undertaken
demonstrated that customers were willing to pay to improve the reliability of the worst served
customers. However, in the Commission’s view, these consultations were based on too small
a number of interviews and customer focus groups and do not directly establish how much
customers are willing to pay or cross-subsidise worst served customers for such
improvements. It is also unclear how SP AusNet would guarantee the delivery of these
improvements.
CitiPower and Powercor engaged an independent market research firm to research the extent
to which customers are willing to pay for the improvements in reliability proposed by them.
CitiPower and Powercor consider that the research results indicate there is some customer
support for reliability improvements. While the results presented indicated that service
improvements were valued, the research did not clearly identify how much the customers
were willing to pay for these improvements. In addition, it is unclear how CitiPower and
Powercor would guarantee that the improvements would be delivered. The Commission also
notes that, where it is claimed that the improvements could not be measured, it is difficult to
assume customers would still be willing to pay for them.
According to CUAC (2005b, p. 2), customers in certain parts of Victoria believe that they are
already paying very high prices for a poor service and could simply not afford to pay more
for household electricity usage:
Without the capacity to pay they would have “to choose” to retain poor supply
reliability.
Some stakeholders, including CUAC, were of the view that further customer research is
required to determine customers’ willingness to pay for improvements. The distributors have
informally indicated that this will be done during the next regulatory period and the
Commission supports such an initiative.
Electricity distribution tariffs are currently not differentiated based on the level of service
received and the costs of providing that service, despite the significant variation in costs for
serving different geographical areas. Generally all customers of the same classification
(residential, small business, large business) pay the same rate for electricity within a
distribution area, regardless of location within that area. Under these tariffs, where reliability
is to be improved in a particular area, all customers of that classification will pay for that
improvement.
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The Minister for Energy Industries, Hon. Theo Theophanous (2005, p. 2) urged the
Commission and the distributors to ensure that adequate measures are implemented to
provide significant improvements to the reliability of supply to customers in the worst served
areas, without detriment to existing overall reliability target levels, suggesting that a schedule
of works be prepared to address the worst served areas of rural and regional Victoria.
The Commission considers that, at this stage, the evidence provided to support the
proposition that all Victorian customers are prepared to pay for improvements in reliability in
worst served areas is difficult to respond to in practice as it does not reveal what level of
reliability customers are prepared to pay for. Importantly, for the purpose of the price review,
the Commission needs to be confident that customers are willing to pay the amounts
proposed by the distributors for the level of improvements proposed. In the absence of
support for the payment of the amounts proposed, the Commission finds it difficult to require
customers to pay for these specific projects, particularly when the impacts on the level of
service are uncertain or not measurable.
During the 2001-05 regulatory period, the distributors improved service on average and to
worst served customers. However, the cost of achieving these service improvements does not
appear to have been as much as was estimated by the distributors during the 2000 price
review. Four out of five distributors have spent less than they estimated whilst continuing to
improve the level of service, despite increasing demand. In some cases, improvements
beyond the service targets have been achieved resulting in some distributors receiving even
more revenue, despite actual costs remaining below the estimated costs. This demonstrates
that distributors can and do find more efficient means of addressing service improvement
issues.
Importantly, the Commission acknowledges that it is neither practical nor possible for a
regulator to assess the scope of individual reliability improvement projects or to evaluate
their costs and benefits. It therefore has not sought to establish a list of suitable projects or to
impose an economic test that distributors might be required to apply. The Commission has
provided an incentive through financial rewards and penalties (see Chapter 3) that ensures
distributors have incentives to deliver service improvements where it is efficient to do so.
The Commission considers that customers should not pay for reliability improvements that
cannot be measured or cannot be guaranteed to be delivered. Further, customers should not
pay more for the service improvements than the value they place on them. Therefore, for the
2006-10 regulatory period, the Commission considers customers should only pay for
reliability improvements through the service incentive arrangements. The service incentive
arrangements provide additional revenue to the distributors when service improvements are
delivered. Under the S-factor scheme, the revenue received is based on an estimate of the
average value that customers place on reliability.
Accordingly, the Commission will rely upon the service incentive arrangements (the S-factor
scheme and the reduction in GSL payments under the GSL payments scheme) to provide
revenue to distributors once reliability improvements are delivered. Improvements in
reliability will therefore be decided by the distributors directly, taking into account the
incentive arrangements. Where these services are not delivered, customers will not be
required to pay higher distribution prices and may receive a GSL payment. Indicative
examples of the type of cost-benefit trade off that a distributor may make are set out in
Attachment 1 to this chapter.
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The Commission has therefore excluded expenditure amounts for reliability improvements
from the revenue requirements.
The Commission’s analysis indicates that some of the projects for worst served customers
proposed by the distributors may be economically efficient and proceed under the service
incentive arrangements and some may not. SP AusNet and Powercor have indicated that,
under these arrangements, proposals to improve reliability in locations such as the Mt
Dandenong area and Lavers Hill may not be financially viable under the service incentive
scheme.
The Commission notes that distributors will not undertake the investments unless the
improvements can be economically achieved, otherwise they will not receive sufficient
benefits under the incentive scheme to offset the expenditures required. In these cases, the
cost of achieving the improvements is greater than the average value assumed to be placed on
reliability by customers. To provide these distributors with the expenditure proposed through
the revenue requirement rather than the service incentive arrangements would result in price
increases greater than the average value customers place on the improvements (as determined
by CRA’s study on the value of customer reliability for VENCorp). That is, all other
customers would pay more and there would be no guarantees that the service improvements
would result or even that the investment would be undertaken.
Where service levels remain worse than the service thresholds that trigger GSL payments,
these customers will receive these payments. The annual cost of making these payments to
customers, in addition to the increased incentive rates in the S-factor scheme to deliver
improved services, will provide distributors with the incentive to continue to seek ways of
addressing the issues more efficiently without customers being required to pay more than the
value they place on the improvement in reliability.
If specific groups of customers wish to have their service improved and are willing to pay for
it, they can agree a payment and outcome with the distributor separate from the price control
arrangements. Under this scenario, the customers who benefit from the improvement would
pay for the improvement rather than the cost of the improvement being spread across all of a
distributor’s customers.
However, EUAA (2005a, p. 10) notes that some distributors are reluctant to establish an
enduring guarantee to those customers who have made investments in the distributor’s
infrastructure.
The Commission notes that such reluctance is contrary to the intent of the Electricity
Distribution Code, which states that customers and distributors may seek written agreement
to expressly vary their rights and obligations under the code. This right includes matters
relating to quality of supply and reliability of supply. If a customer has a concern in this
regard, it is able to raise it with the industry’s Ombudsman or with the Commission.
Additionally, the Commission notes that there is scope for the specifications for items of
customers’ electrical equipment to be amended so that they are able to withstand momentary
interruptions. Such an approach would be expected to be more economically efficient than
reducing the frequency of momentary interruptions at the network level. In response to the
Position Paper, Ron Brons (2005, p. 3) proposed that:
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Final Decision
SP AusNet sell a cheap digital alarm clock with a built-in battery-powered back-up
system which will enable the clock to keep running properly during momentary power
outages.
Whilst the Commission’s role is not to regulate such an activity by the distributors, it does
expect the distributors to contribute to changing equipment standards to recognise the
practical limitations of the electricity supply system. Of course, customers can also seek out
options for addressing specific issues for themselves that best meet their individual needs.
Appropriateness of proposed targeted levels of reliability
Targeted levels of reliability are required for reporting and monitoring purposes. They reflect
the reliability that customers should expect to experience over the 2006-10 regulatory period,
based on historical performance and the prices paid. Targeted levels are different from the
S-factor targets that apply to the service incentive mechanism described in Chapter 3.
In its Final Framework and Approach, the Commission proposed that the 2005 reliability
targets be adopted as the targeted levels for the 2006-10 regulatory period. However, two
issues have since arisen:
•
distributors are, in some areas, proposing variations to the 2005 targets; and
•
actual performance during the current regulatory period suggests that the 2005 targets
should be reviewed.
For some reliability measures, the targeted levels proposed by the distributors for the
2006-10 regulatory period reflect improvement or deterioration relative to the 2005 targets.
The distributors’ proposals are also based on experience gained by them during the current
regulatory period and/or due to proposed expenditure to improve reliability.
For example, SP AusNet and United Energy have proposed a deterioration in the targeted
levels for planned SAIDI for the 2006-10 regulatory period compared to their 2005 targets in
response to concerns regarding the potential for safety incidents associated with live line
work practices, and due to the increased capital expenditure that they have proposed. Both of
these factors would result in more planned outages whilst work is undertaken.
The Commission is of the view that, where customers have paid through the current S-factor
scheme for improvements in reliability beyond the existing service targets, and these
improvements have been sustained through the regulatory period, these improvements should
be reflected in the targeted levels going forward.
Origin Energy was of the view that reliability should not deteriorate unless there was strong
consumer support for this, whilst CUAC believed there was merit in improving service in
certain areas but any decision to do so should be based on feedback from customer
consultations. SP AusNet (2005b, p. 25) considered it was appropriate to base future
reliability targets on current performance. However, the Commission notes that SP AusNet’s
current performance is worse than the targeted levels.
In its Draft Decision, the Commission accepted the targeted levels proposed by the
distributors except where:
•
a distributor has improved its performance against the reliability measures during the
2001-05 regulatory period, in which case the Commission’s decision was that the
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targeted levels for the 2006-10 regulatory period should reflect this improved
performance; or
•
the improvement in the reliability measure proposed was dependent on specific
expenditure, and the Commission did not include that expenditure in the distributor’s
revenue requirement.
This approach resulted in changes to some of the targeted levels proposed by CitiPower
(planned CBD, unplanned CBD and MAIFI measures); Powercor (unplanned short rural,
planned rural and MAIFI measures); SP AusNet (planned urban, and planned short rural
measures); and United Energy (planned urban and planned short rural measures). AGLE’s
targeted levels were unchanged.
In submissions to the Draft Decision, CitiPower (2005t, p. 3), Powercor (2005aa, p. 6) and SP
AusNet (2005f, p. 10) commented that the targets proposed for them for planned SAIDI were
too onerous. CitiPower noted its capital works program is forecast to increase above 2001-05
levels and that, together with the interval meter roll-out, this will place increased pressure on
planned outages to accommodate planned works. Powercor accepted the targeted levels
proposed for its rural areas, but contended that a reduction in its urban targeted level from
16 minutes to 10 minutes did not adequately recognise increasing pressures relating to safe
work practices and its works program (including the interval meter roll out). SP AusNet
commented that the significant increases in capital expenditure planned by all distributors, in
addition to more safety conscious work practices, would put significant upward pressure on
planned SAIDI.
Taking into account these comments, the Commission has reviewed the proposed targeted
levels for planned SAIDI and planned SAIFI measures to better align them with 2004
performances and the distributors’ assessment of the impact of changes in safe work practices
and the interval meter roll out program. The Commission also considered the consistency of
targeted levels across distributors. Changes to targeted levels, as set out in Attachment 2,
have been made from those proposed in the Draft Decision as follows: CitiPower (up 7 per
cent in CBD area), Powercor and SP AusNet (up 60 per cent in urban and 17 percent in short
rural network areas) and United Energy (up 23 per cent and 67 per cent in urban and short
rural network areas respectively). No change has been made to AGLE’s targeted levels.
CitiPower did not agree to the proposed reduction in its targeted performance for unplanned
SAIDI in its CBD area from 16 minutes in 2005 to 14 minutes in 2006-10, because of the
expected volatility in this measure. However, the average performance over the
2001-04 period of 11.4 minutes is substantially better than the proposed targeted level and
does not support CitiPower’s proposal. The targeted performance level of 14 minutes has
been retained.
CitiPower notes that MAIFI in the CBD area is small due to the infrequent momentary
interruptions that occur on the sub-transmission system supplying such areas, but was not
zero as assumed by the Commission. It requested a targeted level of 0.05 interruptions per
customer, being a small increase above average levels to account for expected volatility in
this measure. Given the inclusion of MAIFI into the scheme from 2006, the targeted levels
for MAIFI have been set based on the expected value. Notwithstanding that MAIFI for the
CBD area has not been included in the service incentive scheme, the Commission considers
that the targeted level should be based on the average performance and therefore has set the
targeted level to the 2001-04 average of 0.03 interruptions per customer.
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Powercor commented that the targeted levels proposed for it for unplanned SAIDI and SAIFI
in rural areas were acceptable overall, but suggested relaxing targeted levels on short rural
feeders and tightening targeted levels on long rural feeders to better reflect historical
performance. Powercor accepted the tightened targeted levels for long rural feeders, and
proposed that the short rural targeted level for SAIFI and SAIDI be relaxed so that levels of
CAIDI would be more reasonable. A SAIFI of 2.0 and a SAIDI of 118, as set out in the Draft
Decision, results in a CAIDI of 59 minutes, which is less than Powercor’s 2005 targeted level
for urban CAIDI (66 minutes). Powercor proposed that SAIDI be increased to 145 and SAIFI
to 2.1 to provide a CAIDI of 69 minutes which is higher than the 2005 targeted level.
Given that Powercor has out-performed its CAIDI targeted levels in four of the five years to
2004, the Commission expects that the 2005 targeted level is achievable. As the
improvements to achieve the 2005 targeted levels have been funded under the 2001-05 price
decision and there is no evidence to suggest that the targeted levels were set inappropriately,
the Commission has adopted the 2005 targeted levels for short rural feeders for the
2006-10 regulatory period. The long rural feeder targeted level has been maintained at the
level proposed in the Draft Decision.
Powercor claimed that historical data on MAIFI is unreliable leading to proposed targeted
levels that are too aggressive. It sought to relax its targeted levels by an average of 12 per
cent. The Commission notes that reporting on MAIFI has been required since 2001 and
Powercor has had several years to develop appropriate recording systems. It considers that
Powercor’s recorded performance is sufficiently accurate to allow targeted levels to be set
and has retained the targeted performance based on the trend in 2001-04 performance, as
proposed in the Draft Decision.
The targeted performance levels to the worst served 15 per cent of customers set out in the
Draft Decision were based on 2003 performance, taking into account that the GSL payments
scheme has acted to improve performance to the worst served customers over the period. SP
AusNet thought that the targets proposed for it were appropriate, while CitiPower and
Powercor thought that the targets proposed for them were inconsistent with other distributors
and did not take into account the volatility in this measure, proposing increases of 21 per cent
and 14 per cent respectively. They suggested that the targeted level be set slightly above the
2001-04 average.
The Commission accepts that using an averaging of performances would provide an
appropriate allowance for volatility, but considers that the 2000 year should be excluded from
the average. This is because the service incentive schemes introduced in 2001 provided
incentives to distributors to improve reliability to worst served customers. If 2000 was to be
included in the average, the average would reflect the volatility in this measure but would
also exclude the improvements made that customers have already paid for. The targeted
levels have therefore been recalculated, based on the average of the 2001-04 performance for
each distributor. This results in a tightening of the targeted performance levels for AGLE and
SP AusNet and a relaxation of the targeted performance levels for CitiPower and Powercor,
whilst United Energy remains at about the same level as that proposed in the Draft Decision.
The Commission’s decision on the appropriate targeted levels for unplanned SAIDI,
unplanned SAIFI, planned SAIDI, planned SAIFI and MAIFI is provided in Table 2.1 and
Attachment 2 to this Chapter. For SP AusNet, these targets have been adjusted where
appropriate for a change in methodology for counting customers — disconnected customers
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are to be excluded from the calculation of reliability measures from 1 January 2006 — and
movement of customers between network types.
The Commission’s decision on the appropriate targeted levels for the total minutes off supply
for the worst served 15 per cent of customers is provided in Table 2.2.
Definition of momentary interruptions
For the purposes of reporting statistics on momentary interruptions in Victoria, a momentary
interruption has been defined as an interruption that is less than one minute in duration.
CitiPower, Powercor and United Energy have proposed that the definition be amended so that
it includes all interruptions of duration less than three minutes. These distributors consider
that an amended definition would be consistent with the definition adopted in other countries
and would encourage development of semi automated distribution switching responses to an
interruption of duration three minutes thereby avoiding the costs of going to fully automated
systems, which would be necessary to achieve operational responses of less than one minute
(CitiPower 2005b, p. 3 and Powercor 2005b, p. 3).
Whilst these distributors supported the change in definition of momentary interruptions from
one minute to three minutes, SP AusNet (2005b, p. 41) considered it inappropriate to change
the MAIFI definition at this time due to various concerns, including:
•
the necessity to reset network and S-factor targets, which would require a recalculation
of historic data; and
•
the creation of an incentive for work crews to attempt to conduct certain maintenance
work within three minutes to ensure the outage is defined as momentary rather than
sustained, with a corresponding impact on safety.
Stakeholders representing customer interests did not support a change in the definition of
momentary interruptions.
The historical information on MAIFI has been collected and the targeted levels have been set
on the basis of an interruption of a duration less than one minute. In addition, willingness to
pay information regarding MAIFI is based on a one minute definition. Further, the current
S-factor scheme for improvements in reliability encourages a reduction in the duration of
interruptions.
If the definition was changed, there would be no consistent data and introducing a financial
incentive for an improvement in MAIFI would need to be postponed again whilst data based
on a three minute definition were collected. In its Position Paper, the Commission proposed
that if the definition was to change, the information should be reported for both definitions
during the next regulatory period. This would provide historical data as the basis for
amending the definition. However, United Energy (2005c, p. 13) expressed concern
regarding the cost effectiveness of collecting data on the number of momentary interruptions
based on both definitions over the next regulatory period.
The Commission remains of the view that momentary interruptions should be defined as
interruptions of less than one minute duration to be consistent with the current definition and
the national regulatory reporting framework. This assists with comparing performance over
time and setting targets for the service incentive scheme.
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The Commission will not require distributors to collect data based on a three minute
definition of MAIFI during the next regulatory period. However, if distributors continue to
support a change in the definition of MAIFI, they should collect data during the next
regulatory period based on a three minute definition. They should also undertake customer
research to demonstrate that customers would support a change in definition and to ascertain
the difference in customers’ willingness to pay for reductions in the frequency of three
minute interruptions compared to one minute interruptions.
Reporting low reliability feeders
The Comparative Performance Reports, published annually by the Commission, list the
feeders with reliability worse, in terms of greater annual minutes off supply, than threshold
limits set for each feeder type.
The low reliability threshold limits were set based on levels experienced by the worst served
five per cent of customers in 1997 and 1998. Given the improvements in reliability for the
worst served customers, the proportion of customers who experience reliability at these levels
has fallen. The Commission therefore proposed revised thresholds in its Position Paper,
including with respect to MAIFI, based on performance data to 2003.
Stakeholders generally supported ongoing reporting of low reliability feeders. Customers
attending the Commission’s public information forums conveyed the dissatisfaction of those
reliant on the worst served feeders, and the view that the service reliability of the worst
served feeders and the relevant distributors’ plans to improve these feeders should be
transparent to their customers. The Commission concurs with this view and with therefore
require the distributor to provide comments, for inclusion in the Comparative Performance
Report, or its plans for each low reliability feeders.
Distributors supported the Commission’s proposed revision of thresholds but suggested
amendments to some thresholds based on additional data.
The Commission subsequently reviewed the thresholds for reporting low reliability feeders,
incorporating the performance data for 2004, so that they reflect the service reliability and
MAIFI currently experienced by the worst served five per cent of customers. Based on feeder
performance data for 1999 to 2004, the threshold for MAIFI for long rural feeders has been
increased from 24 interruptions proposed in the Position Paper to 25 interruptions.
CitiPower (2005t, p. 8) suggested that the targets for CBD areas should include a SAIFI
threshold as well as the proposed SAIDI threshold, to avoid classifying a feeder as low
reliability following a single sustained outage of 70 minutes. The key issue here is that any
interruption on a predominantly underground supply system is likely to take a significant
time to locate and repair. Incorporating a dual threshold is likely to provide a more balanced
view of when CBD customers experience poor reliability. Accordingly, the threshold will
include a requirement that only applies where more than one interruption has occurred.
The thresholds for the reporting of low reliability feeders are provided in Table 2.3.
2.2.2 Quality of supply measures
Whilst reliability of supply is concerned with the availability of supply, quality of supply is
concerned with the characteristics of the electricity supply delivered to customers’ premises,
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specifically whether there are short term or transient voltage increases (voltage surges) or
reductions (voltage sags) and harmonic distortions. Distributors are obliged to supply
electricity that meets the standards for quality set out in the Electricity Distribution Code.
Where the electricity supplied does not meet the relevant standards, electrical equipment may
not operate as intended and/or damage to customers’ equipment may result.
For the 2001-05 regulatory period, very little information was available on the quality of
supply received by customers, despite this being recognised as an important issue. To enable
distributors to better monitor voltage problems and proactively manage the quality of supply
delivered to customers, they have been required, during the current regulatory period, to
install quality of supply monitoring equipment at each zone substation and at the far end of
one distribution feeder supplied from each zone substation. It was always considered that
once this information was available, it would be possible to concentrate on improvements,
where required.
The distributors have provided performance data to the Commission in relation to the quality
of supply since 1999. However, prior to the completion of the installation of the quality of
supply monitoring equipment, the data have been incomplete.26 The Commission intends to
continue collecting this data and commenced publishing this data in its 2003 Comparative
Performance Report, when the data set was almost complete.
The issues arising from the distributors’ price-service proposals in relation to the quality of
supply measures are:
•
appropriateness of quality of supply measures;
•
targeted levels for quality of supply measures;
•
proposed improvements in quality of supply; and
•
increased costs associated with compensation for voltage variation claims.
Appropriateness of quality of supply measures
The distributors are currently required to report to the Commission on the following:
•
Number of over-voltage events – due to high voltage injection;
•
Number of customers receiving over-voltage – due to high voltage injection;
•
Number of over-voltage events – due to lightning;
•
Number of customers receiving over-voltage – due to lightning;
•
Number of over-voltage events – due to voltage regulation or other cause;
•
Number of customers receiving over-voltage – due to voltage regulation or other cause;
•
Number of voltage variations – steady state;
•
Number of voltage variations – one minute; and
•
Number of voltage variations – ten seconds.
26
By the end of 2003, AGLE, CitiPower, SP AusNet and United Energy had installed 100 per cent of the quality of
supply monitoring equipment, and Powercor had installed 89 per cent of monitoring equipment at the zone substation
level and 95 per cent of monitoring equipment at the feeder level.
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These reporting requirements are additional to reporting the number of customer complaints
on quality of supply required by the national regulatory reporting requirements.
Stakeholders generally supported the existing quality of supply measures, although the
EUCV (2005b, p. 29) was of the view that there should be additional quality of supply
monitoring:
The service standards should record as basic standards, both the frequency and extent
of transient voltage variations, the frequency and length of loss of supply (even if such
loss is for less than one second) and the frequency of occurrences of voltage spikes.
Whilst the Commission is aware of increasing community concerns regarding quality of
supply and has considered improved monitoring of quality of supply, it is concerned about
the feasibility of some of the proposals for additional measures.
In its enhanced offer, CitiPower proposed improving the number of voltage variations of less
than one second. It would be difficult to measure whether this would be achieved or not
because voltage variations are currently only measured for periods less than one minute and
less than ten seconds under the Electricity Distribution Code. The EUCV (2005b, p. 64)
suggested that voltage variations be measured over this shorter time period, while CUAC
(2005c, p. 2) questioned the appropriateness of the current standard for voltage quality:
…[CUAC] recommends that the Commission initiate a dialogue about reasonable
levels of quality, the present and future needs of rural communities and the
appropriateness of the quality levels proposed in the Electricity Distribution Code.
Given the level of non-compliance with the current standards in the Electricity Distribution
Code, the Commission does not consider it appropriate at this stage to consider tightening
these standards across the network and measuring voltage variations of less than one second.
Where specific customers have different needs from the average customer, these should be
addressed by that customer, as discussed further in the next section.
CitiPower (2005b, p. 37) and Powercor (2005b, p. 37) have suggested that:
There should be additional reporting where voltage variations lasting greater than one
minute are segmented into those recorded at zone substation levels and those recorded
at feeder extremity level.
The Commission supports CitiPower’s and Powercor’s proposal to segment quality of supply
monitoring at the zone substation and feeder level. SP AusNet and David Valentine also
supported these proposed changes to reporting requirements.
Discussions with customer groups indicated that voltage variations which result in a voltage
level that is less than 70 per cent or 80 per cent of nominal voltage have a greater impact on
equipment operation than smaller voltage variations. Accordingly, the Commission proposed
in its Position Paper additional reporting at the zone substation level of ten second voltage
variations, where a breakdown is provided of voltage variations which result in a voltage
level that is less than 70 per cent, less than 80 per cent, and less than 90 per cent of nominal
voltage.
United Energy (2005c, p. 55) was supportive of such additional reporting, while Power
Quality Solutions (2005, p. 4) proposed a further breakdown based on the duration of the
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voltage variations: 0.02-0.15 sec, 0.15-1.0 sec, and 1-10 sec. Subsequently, all distributors
advised that monitors installed in their zone substations are capable of measuring on this
basis. While the provision of such information might be helpful to inform the Commission in
future reviews of voltage standards, it is not clear that the cost of collecting such information
is warranted at this time. Hence the Commission encourages distributors to install voltage
monitoring equipment that is capable of recording voltage variations in the time intervals
proposed, and to make this information available to customers when requested, but does not
intend to mandate a specific requirement at this time.
Targeted levels for quality of supply measures
The distributors will continue to report quality of supply against existing measures.
Additionally, distributors will report on the number of voltage variations as measured at the
zone substation level, and as measured at the feeder level. For zone substation level only, a
further breakdown of voltage variations of less than ten seconds will be reported based on the
minimum voltage during that voltage variation (less than 70 per cent of nominal voltage, less
than 80 per cent of nominal voltage and less than 90 per cent of nominal voltage).
Targeted levels for the quality of supply measures were not set during the last price review
because the performance information was unavailable. However, such an approach was
foreshadowed as part of the last Price Determination (ORG 2000a, p. 30).
While stakeholders generally supported the setting of targeted levels for quality of supply
measures against which the Commission could report and monitor distributors’ performance,
some of the distributors did not, identifying a number of issues relating to:
•
a lack of clarity with the definitions of quality of supply (AGLE 2005b, p. 19, United
Energy 2005c, p. 55);
•
the limited quantity and quality of historical data (SP AusNet 2005b, p. 43); and
•
current monitoring equipment which is orientated around reporting a sample of quality
of supply information (Powercor 2005b, p. 2).
CitiPower and Powercor considered that the accurate quantification of the number of
customers receiving over-voltage events is difficult, and that voltage variation reporting
proposed for zone substations is more reliable. Neither they nor United Energy (2005c, p. 55)
supported targeted levels at feeder level but they did support targeted levels at zone
substation level.
The Commission notes AGLE’s and United Energy’s concern regarding a lack of clarity with
the definitions of quality of supply — for example, United Energy reports voltage variations
based on target voltage rather than nominal voltage. Power Quality Solutions (2005, p. 2)
stated that, to ensure consistency of data over the 2006-10 period, all distributors should use
nominal voltage when determining the voltage variation limits rather than target voltage. It
also recommended that the Electricity Distribution Code should reference AS/NZ61000-4-30
as the required measurement methodology standard for all power quality parameters. The
Commission notes that using variations from nominal voltage, rather than targeted voltage,
provided a perverse incentive to lower voltage at zone substations, which could result in even
lower voltages for customers at the end of feeders.
The Commission recognises that clear definitions are required and will clarify these through
consultation on changes to the Electricity Distribution Code. The Commission also
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recognises the limitations in setting the targeted levels associated with the partial historical
data and the measurement of a sample of feeders. Given the variability in the data and the
level of non-compliance with the Electricity Distribution Code, the Commission considers
that the setting of targeted levels at this stage is problematic.
Targeted levels have therefore not been specified for the next regulatory period because of
the difficulties associated with the existing data, although the data are to be measured and
reported (see below). For these purposes, improvements in quality of supply have been
expressed as the number of customers for whom voltage quality will improve, rather than as
improvements in the level of voltage variations per se.
Proposed improvements in quality of supply
The Electricity Distribution Code mandates the minimum standards for quality of supply.
Where the quality of supply does not comply with the Electricity Distribution Code then the
distributor is obligated to improve the quality of supply.
During the current regulatory period the distributors have installed voltage monitoring
equipment. The installation of this equipment has resulted in objective information on quality
of supply being available for the first time. This has enabled the identification of distributors
who are not compliant with the minimum standards for quality of supply in some areas. Data
for 2003 and 2004 indicates a significant number of voltage variations, particularly for the
rural distributors.
The distributors made proposals for expenditure over the 2006-10 regulatory period to
improve quality of supply:
•
Powercor proposed expenditure of approximately $26.4 million to improve the quality
of supply to customers/areas receiving the lowest level of service where the
requirements of the Electricity Distribution Code are not met, and to improve the
proactive identification and rectification of supply quality issues. Powercor anticipated
that a reduction of between 10 and 15 per cent in reported steady state voltage
variations would be achieved.
•
SP AusNet proposed expenditure of $24 million to resolve quality of supply issues to
ensure it complied with the Electricity Distribution Code and to install equipment to
measure harmonics and flicker.
•
United Energy proposed $5.25 million to improve the quality of supply delivered to
customers, such as voltage delivery and harmonics, so that it better complied with the
Electricity Distribution Code.
Non-compliance with the quality of supply requirements in the Electricity Distribution Code
was raised during public information forums, particularly at Bendigo, Wodonga and
Bairnsdale. Uncle Tobys (2005, p. 1) also observed a significant increase in the frequency of
voltage dips.
In its Draft Decision, the Commission included expenditure it considered to be reasonable for
distributors serving rural areas — Powercor, SP AusNet and United Energy — to ensure that
they became compliant over time with the minimum standards for quality of supply as set out
in the Electricity Distribution Code. Ideally, the Commission would prefer that this
expenditure was financially linked to the achievement of outcomes. However, the minimal
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Final Decision
historical data available and the fact that the data items that are available are only from a
sample of feeders may result in perverse outcomes if quality of service were included under
the service incentive arrangements. For example, monitoring equipment may be installed
where compliance is most likely. This would result in a misrepresentation of the actual
circumstances.
Powercor, SP AusNet and United Energy have quantified the number of customers who can
expect improvements in quality of supply over the 2006-10 regulatory period (see Tables 2.6,
2.7 and 2.8).
Table 2.6:
Improvement in quality of supply, Powercor, 2006-10
Year
Cumulative number of customers
2006
9,200
2007
22,800
2008
35,400
2009
2010
47,400
59,000
Table 2.7:
Year
Improvement in quality of supply, SP AusNet, 2006-10
Cumulative number of customers brought within Code
SWER systems
Sags and swells
Negative sequence
voltage
2006
799
10,380
1,809
2007
1,698
22,058
3,844
2008
2,698
35,034
6,105
2009
2010
3,798
4,998
49,307
64,878
8,592
11,305
Table 2.8:
Improvement in quality of supply, United Energy, 2006-10
Year
Cumulative number of customers
Cumulative number of zone substations
2006
200 – 400
1
2007
400 – 800
2
2008
600 – 1 200
3
2009
800 – 1 600
4
2010
1 000 – 2 000
5
The Commission will monitor the extent to which these distributors achieve the outcomes set
out in Tables 2.6, 2.7 and 2.8.
Additionally, the Commission notes that distributors currently must investigate all complaints
regarding quality of supply where it is probable that the supply is not compliant with the
Electricity Distribution Code.
The Commission considers that the continuing focus on quality of supply for the
2006-10 regulatory period should be on providing an accurate picture of the quality of supply
and improving compliance with the Electricity Distribution Code for all customers. The cost
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of further improvements and customer willingness to pay for the improvements can be
considered for the next regulatory period when improved data are available and
improvements can be objectively measured and quantified. Meanwhile, the Commission
intends to closely monitor distributors’ compliance with quality of supply standards through
monitoring of customers’ complaints, distributors’ annual reporting on quality of supply
measures and the regulatory audit program.
Given the concerns expressed in relation to the quality of supply in rural areas and the
information that compliance with the Electricity Distribution Code is likely to be less in these
areas, the Commission considers that reasonable expenditure proposed by the rural
distributors for additional monitoring of the quality of supply should also be included in their
revenue requirements.
The Commission has considered a number of options including installing voltage monitoring
equipment on all rural feeders, and additional monitoring in areas where there is evidence of
non compliance. To ensure that the installation of additional voltage monitoring equipment is
economically efficient, the Commission will provide expenditure for the number of units of
voltage monitoring equipment installed by the rural distributors (Powercor and SP AusNet) to
increase by an additional 20 per cent by the end of 2006.
Powercor and SP AusNet have provided an estimated unit cost for installing sophisticated
voltage quality monitors. Based on the costs provided by SP AusNet,27 the Commission has
provided expenditure for:
•
an additional 27 sophisticated voltage quality monitors to be installed by Powercor at a
cost of $648,000; and
•
an additional 17 sophisticated voltage quality monitors to be installed by SP AusNet at
a cost of $408,000.
The Commission requires Powercor and SP AusNet to provide it with a plan by 31 December
2005 explaining where and when the additional equipment is to be installed. These plans will
be made available on the Commission’s website when received. Additionally, given the
expenditure proposed to improve the quality of supply so that the distributors comply with
the Electricity Distribution Code, the Commission requires that zone substations and feeders
that do not comply with respect to quality of supply be reported.
Where a zone substation or feeder is reported, the distributor must provide comments
regarding its plans for that zone substation or feeder.
There are a number of customers for whom the quality of supply complies with the
Electricity Distribution Code but does not meet the quality of supply required by them.
Representatives of the dairy industry indicated that minimum quality of supply standards
defined in the Electricity Distribution Code are inadequate to meet their needs — especially
“dips” or “sags” in supply of electricity to sensitive food processing plants such as milk
powder driers. The Dairy Processing Power Quality Project (2005, p. 2) estimated that
$23 million of expenditure would be needed to upgrade seven dairy processing plants to
provide for adequate quality of supply.
27
SP AusNet quoted $24 000 per unit for a sophisticated voltage quality monitoring unit whilst Powercor quoted $2 000
per unit for a basic voltage monitoring unit and $32 500 per unit for a sophisticated voltage quality monitoring unit.
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In its enhanced offering, CitiPower proposed expenditure of $28 million over the
2006-10 regulatory period to, among other things, reduce the number of voltage sags of
duration less than 1 second in commercial/retail areas.28 Whilst CitiPower currently complies
with the Electricity Distribution Code in this regard, it indicated that it will reduce the
number of customers who experience voltage sags of duration less than one second by 50 per
cent to 144 000 per annum.
In its enhanced offering, Powercor also proposed expenditure of $54 million over the
2006-10 regulatory period to, among other things, reduce the extent and impact of voltage
fluctuations.
Where the quality of supply complies with the Electricity Distribution Code, the customer
has the option to pay for improvements to the quality of supply where the customer considers
it is economically efficient to do so. This may be achieved through a network solution where
the incremental costs are paid for by the customer or through an individual solution
implemented at the customer’s premises and paid for by the customer. Therefore, the
Commission has not included the expenditure proposed under CitiPower’s and Powercor’s
enhanced offerings.
United Energy (2005c, p. 56) supported this approach. In addition, CitiPower (2005b, p. 5)
and Powercor (2005b, p. 5) noted that they were not aware of any regulatory barriers to
customers buying improved quality of supply from their distributor, and this is clearly
contemplated as an excluded service.
Compensation for voltage variation claims
The Commission codified the circumstances in which residential and small business
customers are entitled to compensation for damage due to voltage variation (surges and
brown outs) in the Electricity Industry Guideline No. 11: Voltage Variation Compensation.
The Commission recently clarified that this guideline does not negate the insurance
companies’ rights to subrogation under the law.
Each of the distributors proposed additional expenditure to cover claims made by insurance
companies, in anticipation that this clarification will increase the number of claims by
insurance companies. This issue is discussed further in Chapter 6.
Additionally, CitiPower and Powercor, in their enhanced offerings, proposed operating
expenditure over the 2006-2010 regulatory period of $3.2 million and $17.9 million
respectively, for enhancements to the management and settlement of voltage variation claims.
This additional expenditure represents:
•
an increase to the current level of compensation based on a “new for old” policy, which
allows customers to be compensated for the cost of a new replacement item, instead of
being compensated for an item of the same age; and
•
a “new for old” compensation policy to be available for all domestic customer claims,
and for all business customer claims under a specified value, if repair is not
economical.
28
Proposed commercial/retail areas to be targeted by CitiPower include Armadale, Camberwell Junction,
Prahran/Richmond, Collingwood, South Melbourne, Albert Park and Port Melbourne.
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AGLE also proposed operating expenditure of $3.6 million to, among other things, increase
the level of compensation based on a “new for old” policy where appliances are less than ten
years old.
Some distributors indicated during meetings with the Commission and the Commission’s
technical consultant that the benefits to distributors in terms of fewer complaints and EWOV
cases may outweigh the costs of the enhanced scheme. If this is the case, it would represent
an efficiency gain for the distributor and should not also be paid for by customers.
In response, EWOV considered that the approach to voltage variation claims should be
consistent across the distributors. SP AusNet (2005c, p. 26) considered that the benefits of a
“new for old” policy were significantly less than its costs, but indicated that it was prepared
to enhance the management and settlement of voltage variation claims. United Energy
advised that it would require an additional $1 million per annum to settle the voltage
variation claims as proposed by AGLE, CitiPower and Powercor.
CitiPower (2005b, p. 38) and Powercor (2005b, p. 38) provided further support for their
proposals:
The key concern for customers is that distributors are currently required to compensate
the customer with “like for like” property. In many cases this does not meet customer
expectations about the appropriate level of compensation. [CitiPower] [Powercor]
believes that increasing the allowed compensation for “new for old” will result in a
lower level of complaints both to [CitiPower] [Powercor] and EWOV.
Furthermore, CitiPower and Powercor engaged an independent market research consultancy
to survey customers on this issue. The results indicate there is some support for a “new for
old” compensation policy. However, it was not clear how much customers are prepared to
pay or the extent to which this might already be addressed through customers’ individual
insurance choices.
Stakeholders to this review did not indicate that they were willing to pay for enhancements to
the management and settlement of voltage variation claims. Some stakeholders expressed
concern during public information forums about the potential for spiralling costs of this
scheme as customers install more expensive digital equipment.
The objective of the industry scheme is to ensure that distributors accept responsibility for
overvoltages, to provide an incentive to minimise them, and to return equipment to the
condition it would have been in had the overvoltage not occurred. This is an industry scheme
rather than an insurance policy. Where a customer requires a “new for old” replacement, that
customer has the option to seek compensation through an insurance claim. The Commission
continues to consider expenditure for a voltage compensation scheme based on “like for like”
replacement rather than “new for old” is sufficient.
The Commission notes that distributors may choose to introduce a “new for old” scheme
where they consider the benefits exceed the costs.
2.2.3 Customer service measures
Customer service relates to the distributors’ performance in meeting customer requirements
such as responding to queries, providing information and meeting timelines.
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Call centre performance measure
Stakeholders’ submissions to the price review have raised two issues in relation to
distributors’ call centre performance:
•
the accuracy of the information provided; and
•
the timeliness of the response, with some stakeholders indicating they currently wait
considerably more than 30 seconds for a call to be answered, including where calls
were made on a special number for life threatening situations.
Stakeholders noted their concern regarding accuracy of information provided by call centres
in the Commission’s public information sessions, and proposed that a dedicated business line
may be required (Wodonga and Lilydale). Powercor also identified the accuracy of
information provided as an important element of customer service (Comments by Mr Damien
Batey of Powercor on ABC Radio Western Victoria, 6 April 2005).
The Commission acknowledges that the accuracy of information provided is of concern to
customers. Whilst the Commission would also like to monitor the accuracy of information
provided to customers when they call the fault line, it recognises that it is difficult to do so on
an objective basis.29
Distributors observed that the inclusion of call centre performance in the S-factor scheme
(see Chapter 3) will provide an incentive to improve the accuracy of information provided by
call centres through their interactive voice response (IVR) so fewer customers elect to speak
to an operator (SP AusNet, CitiPower and Powercor).
The Commission will continue to monitor the accuracy of information provided by call
centres through customer feedback during annual public information sessions and
benchmarking surveys.
In relation to the timeliness of response, distributors are currently required to report on:
•
Number of calls to the fault line;
•
Number of calls to the fault line that are forwarded to an operator; and
•
Number of calls to the fault line that are forwarded to an operator and answered within
30 seconds.
SP AusNet (2005b, p. 45) noted that:
The percentage of calls answered within 30 seconds is a measure currently monitored
by all distribution businesses in Victoria, in addition to being a standard call centre
measure in most industries worldwide. As such, SP AusNet Networks believes this to be
an appropriate measure of performance for the call centre.
There is currently no targeted level against which the distributors’ performance is monitored
and reported.
CitiPower and Powercor proposed a targeted level of 70 per cent of calls to be responded to
within 30 seconds (including those responded to by their IVR) as an appropriate call centre
29
In the UK, Ofgem surveys customers to provide a subjective assessment of information accuracy.
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performance measure for the service incentive arrangements. Further, in their enhanced
offerings, they proposed expenditure of $6.8 million and $7.8 million respectively over the
2006-10 regulatory period to increase the targeted level from 70 per cent to 85 per cent.
SP AusNet proposed a targeted level of 75 per cent of calls to be responded to within
30 seconds (at an expenditure of $3.6 million) or, reflecting current performance, a target of
68 per cent. CUAC believed it reasonable to require that 80 per cent of calls to be responded
to within 30 seconds. Origin Energy recommended that the same targeted level apply to all
distributors.
In its Position Paper, the Commission proposed that a targeted level of 75 per cent be set for
each of the distributors. However, CitiPower and Powercor were of the view that there is
insufficient data to determine a true underlying performance level, and AGLE noted its
concern that the call centre data previously reported to the Commission may not be accurate
as there was no financial incentive connected to the results.
The Commission reviewed call centre data from 1999 to 2004 for each distributor and
considers it sufficient to determine a targeted level for each distributor. In its Draft Decision,
the Commission proposed that the targeted levels be set to the actual performance achieved
by each distributor in 2003, on the basis that 2003 was representative of future performance.
In response, AGLE thought its targeted level was too high while CitiPower and Powercor
provided revised data for 2004 that they claim showed 2003 performance was
unrepresentative of future performance.
Taking into account these comments, the Commission has reviewed the proposed targeted
levels to better align with actual performance over recent years. Except for CitiPower and
Powercor, the targeted level has been determined using the mid point of the average over the
period 2001-04 and the trend line based on the historical data, and projecting the expected
response rate for 2005. This approach has been taken because, while the trend line showed a
clear improvement over the period, it is based on a small number of data points.
Incorporating the average performance provides a conservative approach in setting the
targets.
In setting SP AusNet’s target, the Commission noted that its call centre performance in 2002
was substantially worse (29 per cent) than the average for 2001-04. The poor performance
coincided with a period of underspending and returned to average levels from 2003. The
Commission considers that the call centre performance in 2002 does not represent volatility
in performance and is not representative of future performance levels. Hence, for SP AusNet,
2002 has not been considered in setting the targeted level.
Both Powercor and CitiPower’s call centre performances improved substantially in 2004
when compared to the 2001-03 period. The Commission notes that in May 2004, Powercor
announced the completion of a $3 million upgrade to its Bendigo call centre and that the
centre would field calls from ETSA Utilities in South Australia and CitiPower (Bendigo
Advertiser, 27/5/2004). While CitiPower’s performance shows an approximate 20 per cent
improvement from 2003 to 2004, Powercor’s performance shows a more gradual
improvement over three years, achieving 85 per cent in 2004. Because these distributors now
employ a common call centre, the Commission considers that their future call centre
performances are likely to be similar and that targets should be set on a different basis to the
other distributors.
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CitiPower and Powercor’s operating and maintenance expenditure has increased substantially
in the 2002-04 period (see Chapter 5). They claim that this increase in expenditure reflects
the cost of service improvements including call centre performance. If the targeted level was
to be determined from historical averages, than the target would include the poorer
performance in previous years and customers would be effectively paying for this service
improvement twice; through S-factor rewards because of the lowered target and through the
revenue allowed for operating and maintenance expenditure.
The Commission considers that the targeted level of call centre performance should reflect
the likely service level thorough the 2006-10 period. Accordingly, it has set targeted levels
for Powercor based on the trend 2001-04 of Powercor’s actual performance (81.5 per cent).
The Commission also considers that CitiPower’s future call centre performance is likely to be
closer to its 2004 performance of 80 per cent of calls answered in 30 seconds rather than the
trend over the preceding period. Accordingly, the Commission considers that CitiPower’s call
centre performance target should be no more than its 2004 performance of 80.1 per cent and
should reflect the potential shown in Powercor’s performance target of 81.5 per cent.
Accordingly, a targeted level of 80 per cent has been set for CitiPower.
Distributors noted that the proposed call centre measure did not indicate how missed calls due
to an overload event and how abandoned calls should be treated. United Energy (2005d, p. 9)
suggested that the measure should include missed calls due to call centre overload events and
Powercor (2005aa, p. 10) suggested that the measure should exclude abandoned calls.
In setting the targeted levels, the Commission has included telephone calls answered by an
IVR (interactive voice response) within 30 seconds where the IVR provides substantive
information and the customer does not request to be connected to an operator.
With regard to abandoned calls, the measure will include calls abandoned by the customer
within 30 seconds, that is, where the call has been terminated within 30 seconds of being
queued for response by a human operator. Only CitiPower (25 per cent) and Powercor (12 per
cent) provided the percentage of calls abandoned within 30 seconds, for a single year (2004).
The average of these, rounded to 20 per cent, has been applied to other distributors and to
CitiPower and Powercor’s data prior to 2004 to derive an appropriate number of abandoned
calls in 30 seconds for use in setting the targeted level. This approach provides a lower
targeted level than if abandoned calls are not considered in years prior to 2004.
To reflect the method used to develop the targeted level, where the time in which a call is
abandoned is not measured, distributors will estimate the number of calls abandoned within
30 seconds by taking 20 per cent of the total number of abandoned calls.
With regard to missed calls, the Commission notes that most distributors’ systems are not
capable of recording the number of missed calls when an overload event occurs. Accordingly,
missed calls will not be included in the overall number of calls to the fault call line.
CitiPower and Powercor proposed that call centre performance should be normalised by
reliability performance when examining historical trends. An examination of available data
on network performance and call centre performance across all distributors, however, shows
little correlation between call centre performance and daily SAIDI or SAIFI measures.
Accordingly, the Commission has set targeted levels for the proportion of calls responded to
within 30 seconds based on the above discussion. The targeted levels (as set out in Table 2.5
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of Section 2.1.3) are consistent with current levels of performance for each distributor.
Therefore, the Commission has not included the additional expenditure proposed by SP
AusNet (2005f, p. 11) and by CitiPower and Powercor in their enhanced offerings to increase
the proportion of calls responded to within 30 seconds. The distributors will be rewarded for
any improvements in the timeliness of the call centre response through the S-factor scheme
(see Chapter 3).
While AGLE was concerned about the performance of the call centre during electricity
network outages in particular, SP AusNet (2005b, p. 26) supported the reporting and
monitoring of overload events which are most likely to occur during outages.
Accordingly, the Commission will require reporting on the number of overload events that
occur in each distributor’s call centre each year. This measure is also consistent with national
regulatory reporting requirements (URF 2002, p. 41). The Commission has set a targeted
level of zero for the number of overload events for each distributor because the number
currently experienced is zero or close to zero, but understands that distributors may not be
able to achieve this targeted level under all operating conditions. For example, United Energy
(2005d, p. 10) noted that to guarantee a targeted level of zero would require additional
expenditure of $600,000 to increase the number of ports available to its call centre. Where the
targeted performance has not been achieved, distributors will be required to report the reasons
for not meeting the targeted level.
Metering related measures
Distributors’ accountability for the level of customer service provided to customers in
relation to metering will become increasingly important as interval meters are rolled out.
In recent submissions to the ACCC’s National Electricity Rules metering derogation process,
a number of complaints were raised regarding current service levels provided by the
distributors. In addition, following the joint jurisdictional regulators’ review of metrology
procedures, this situation may be exacerbated as distributors will continue to have exclusive
responsibility for metering services for all ‘small’ customers (defined by the Commission as
those who consume less than 160 MWh per annum and have a manually read meter
installed).
As Origin Energy (2005, pp. 4&7) stated:
Given the pending investment of significant capital in interval metering, monitoring the
performance of the metering component (prescribed services) is becoming even more
important. … Origin is seeking inclusion of interval metering performance standards as
these are clearly linked to the requests for additional capital and operating
expenditure.
Given the classification of most metering services as prescribed services, the distributors’
exclusivity over manually read meter provision (discussed in Chapter 13), and the significant
expenditure approved for the interval meter roll out, the Commission indicated in the Position
Paper that it will require reporting on some metering-related measures.
Customers should be able to understand the service they are paying for and be able to monitor
the performance of distributors with exclusive responsibility to provide these services. The
Commission’s preliminary view, set out in its Position Paper, was that the distributors should
report on the following metering-related measures:
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Essential Services Commission, Victoria
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•
Number of interval meters installed (by meter type);
•
Number of accumulation meters installed (by meter type);
•
Number of scheduled meter reads;
•
Number of reads estimated where meter not read when scheduled;
•
Number of scheduled reads (including estimates where meter not read) forwarded to the
other parties (NEMMCO, retailers) within required timeframes;
•
Number of special meter reads;
•
Number of special meter reads not read by requested date;
•
Number of special meter reads forwarded to the other parties (NEMMCO, retailers)
within required timeframes;
•
Number of meter investigations;
•
Number of meter investigations completed within required timeframes;
•
Number of meter investigations where meter not within accuracy range;
•
Number of families of meters sample tested;
•
Number of families of meters sample tested outside accuracy range;
•
Number of requests for a non standard meter to be installed;
•
Number of non standard meters installed; and
•
Number of non standard meters installed by requested date.
However a number of stakeholders’ submissions to the Position Paper suggested that not all
of the measures proposed were appropriate. Whilst these measures were supported by EUCV
(2005b, p. 53), the distributors raised a number of concerns. SP AusNet (2005b, p. 27)
identified demarcation issues with the use of accredited and audited metering service
providers, whereas United Energy (2005c, p. 58) queried the costs of this reporting relative to
the benefits.
Conversely, AGL Retail (2005, p. 2) indicated that it was concerned about meter changes,
however these were not addressed in the measures proposed.
United Energy (2005c, p. 59) also suggested that the Commission rely on audits conducted on
metering service providers to address issues in this area.
After considering all of these submissions, the Commission has decided to require the
distributors to report on four measures only against which the Commission will monitor their
performance:
•
Number of interval meters installed (by meter type);
•
Number of accumulation meters installed (by meter type);
•
Number of scheduled meter reads; and
•
Number of reads estimated where meter is scheduled to be read.
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These four aspects of the distributors’ performance are fundamental to the delivery of
prescribed metering services and the data should be readily available for reporting.
The Commission will monitor any concerns during the regulatory period through the B2B
report card, which is discussed in the following section, and its operational audits. Additional
measures may be introduced in the next regulatory period if significant systemic issues are
identified.
Other customer service measures
Retailers have previously raised concerns regarding the timeliness and accuracy of
information provided by distributors which is required for the transfer of a customer to a new
retailer. There are currently no customer service measures that measure distributors’
performance against this aspect of service.
The timeliness and accuracy of information provided by distributors required for the transfer
of a customer to a new retailer will become increasingly important to the competitiveness and
efficiency of electricity supply to small customers. This factor, and the concerns raised
regarding distributors’ customer service, warrants investigating the introduction of additional
customer service measures.
Distributors were invited to submit proposals on an appropriate measure and indicate how
they have considered input from stakeholders on this matter. No distributor proposed an
appropriate measure. In general, they did not support any measures regarding the timeliness
and accuracy of information relating to transfers of customers to a new retailer. CitiPower
and Powercor indicated they do not have system reporting in place to capture their
performance in this regard, and that distributors are not wholly in control of the transfer
process. Conversely, SP AusNet identified a number of existing industry initiatives to address
standing data issues.
Other stakeholders, however, identified possible customer service measures. EWOV
suggested measuring the number of transfer delays attributable to the distributor (for
example, where a delay resulted from a failure to take an actual reading of an accessible
meter), measuring the timeframes for special meter reads and meter accuracy tests, and
measuring the timeframe for providing results to the retailer. AGL Electricity Sales and
Marketing also observed that some distributors may be impacting on the completion of
transfers through delays in effecting requested meter changes in a reasonable timeframe.
The Commission is concerned that the measurement of transfer delays attributable to a
distributor may not be practicable, but proposed the measurement of response times to service
orders as an alternative in its Position Paper. In particular, it proposed that the distributors
report on the following customer service measures:
•
Number of service orders (except special meter reads and meter investigations)
received, by service order type;
•
Number of service orders (except special meter reads and meter investigations)
processed by due date, by service order type;
•
Reasons for not processing service orders (except special meter reads and meter
investigations) by due date:
y
Insufficient notice provided by retailer/customer;
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y
Inaccurate information by retailer/customer;
y
Operator error;
y
Scheduling of service order by distributor; and
y
Other.
Whilst EWOV (2005b, p. 3) supported the greater level of transparency provided through
additional reporting of B2B service standards, a number of stakeholders doubted the net
benefit of introducing additional reporting on the proposed customer service measures:
•
United Energy (2005c, p. 58) questioned whether the benefits to retailers of the
additional proposed reporting would warrant the heavy cost of reporting incurred by
distributors, and suggested as an alternative that the Commission make greater use of
existing NEMMCO reports on timeliness and completeness of data, and regular audits
of distributors.
•
AGL Electricity Sales and Marketing (2005c, p. 2) considered the measures proposed
in the Position Paper would not target the typical issues associated with customer
transfers. Rather the relevant issues are related to data that follows transfer, and not to
the distributor processing the transfer itself.
•
SP AusNet and United Energy considered that short term initiatives undertaken by the
industry and the Commission targeted at resolving issues across the electricity market
— such as the current end-to-end (E2E) project — would be more effective in
addressing any impediments to transferring a customer to a new retailer than the
proposed measures.
The Commission’s E2E project (2005, ref to issues paper) is seeking to address the core
issues that impact customer transfers. Therefore, any requirement to report on significant
transfer related issues will be in response to recommendations arising from that project rather
than through the price review process.
The Commission also proposed in its Position Paper that distributors and retailers would
complete a six monthly “report card” on the B2B capability and performance of the retailers
and distributors with whom they had dealt. AGL Electricity Sales and Marketing regarded
this as a positive step. AGLE, CitiPower and Powercor considered the report card should be
developed with industry over the longer term, recognising the current transition to a national
governance framework.
The B2B report cards will be developed in consultation with industry for use by the
Commission as the basis for investigating and seeking resolution on systemic issues and
recurring non compliance issues. The Commission expects the report card to evolve further in
response to the E2E project and ongoing national developments.
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ATTACHMENT 1:
EXAMPLES OF WORST SERVED FEEDERS
Assume a distributor with annual revenue of approximately $250 million undertakes capital works with a depreciation period of 40 years and a rate of
return of 6.5 per cent per annum.
Example 1:
Capital works - $10 million
Saving in GSL payments - $500,000 per annum
S-factor impact - 0.3 per cent
NPV
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
Revenue requirement
250
250
250
250
250
250.4
250.4
250.4
250.4
250.4
Capital works
10
Return on capital
0.7
Depreciation
0.25
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
GSL payments saveda
Efficiency carryover
0.3%
S-factor impact
-0.3%
S-factor revenue impact
a
0.75
0.75
0.75
0.75
0.75
0.75
-0.75
Total revenue – works done
1920
250.0
250.0
250.5
251.3
251.3
251.7
251.7
251.2
251.2
249.7
Total revenue – works not done
1914
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
These are therefore excluded from the revenue requirement from 2011.
In this example, the NPV of revenue if the works were undertaken does not exceed the NPV of revenue if the works were not undertaken by more than
the cost of the works. It is therefore not economically efficient to undertake the works in this scenario.
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Example 2:
Capital works - $5 million
Saving in GSL payments - $500,000 per annum
S-factor impact - 0.5 per cent
NPV
Revenue requirement
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
250
250
250
250
250
250.4
250.4
250.4
250.4
250.4
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
5
Capital works
Return on capital
0.3
Depreciation
0.1
GSL payments saveda
Efficiency carryover
0.5%
S-factor impact
-0.5%
S-factor revenue impact
a
1.25
1.25
1.25
1.25
1.25
1.25
-1.25
Total revenue – works done
1920
250.0
250.0
250.5
251.8
251.8
251.7
251.7
251.2
251.2
248.7
Total revenue – works not done
1914
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
These are therefore excluded from the revenue requirement from 2011.
In this example, the NPV of revenue if the works were undertaken exceeds the NPV of revenue if the works were not undertaken by more than the cost
of the works. It is therefore economically efficient to undertake the works in this scenario.
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Example 3:
Capital works - $3 million
Saving in GSL payments - $500,000 per annum
S-factor impact - 0.3 per cent
NPV
Revenue requirement
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
250
250
250
250
250
250.4
250.4
250.4
250.4
250.4
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
3
Capital works
Return on capital
0.2
Depreciation
0.08
GSL payments saveda
Efficiency carryover
0.3%
S-factor impact
-0.3%
S-factor revenue impact
a
0.75
0.75
0.75
0.75
0.75
0.75
-0.75
Total revenue – works done
1918
250.0
250.0
250.5
251.3
251.3
251.0
251.0
250.5
250.5
249.0
Total revenue – works not done
1914
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
250.0
These are therefore excluded from the revenue requirement from 2011.
In this example, the NPV of revenue if the works were undertaken exceeds the NPV of revenue if the works were not undertaken by more than the cost
of the works. It is therefore economically efficient to undertake the works in this scenario.
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ATTACHMENT 2:
Table 1:
Targeted levels for unplanned SAIDI
Network
type
AGLE
CitiPower
Powercor
SP AusNet
TARGETED LEVELS — RELIABILITY
MEASURES
2005
targeted
level
2006 targeted
level – as
proposed by the
distributor
2006 targeted level – Commission’s
Final Decision
Urban
Short
rural
CBD
73
113
73
113
As proposed by distributor
16
16
Reduced to 14 minutes based on
historical performance
Urban
35
35
As proposed by distributor
Urban
Short
rural
Long rural
98
118
98
145
As proposed by distributor
2005 target
297
297
As proposed by distributor
Urban
107
109
Short
rural
187
185 a
Long rural
298
300 a
As proposed by distributor
a
As proposed by distributor for 2006 – no
change over period
As proposed by distributor for 2006 – no
change over period
As proposed by distributor for 2006 – no
change over period
Urban
2005 targeted level – no change over
United
59
58
period (expenditure for reliability
Energy
improvement not provided)
Short
2005
targeted level – no change over
96
95
rural
period (expenditure for reliability
improvement not provided)
a
Changes in the targeted level between 2005 and 2006 arise from a change in methodology for counting customers
and movement of customers between network types
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Table 2:
Targeted levels for unplanned SAIFI
Network
type
AGLE
CitiPower
Powercor
SP AusNet
2005
targeted
level
2006 targeted
level – as
proposed by the
distributor
2006 targeted level – Commission’s
Final Decision
Urban
Short
rural
CBD
1.27
1.27
As proposed by distributor
2.25
2.25
As proposed by distributor
0.25
0.25
As proposed by distributor
Urban
0.80
0.80
As proposed by distributor
Urban
Short
rural
Long rural
1.63
1.63
1.80
2.10
As proposed by distributor
2005 targeted level
3.50
3.30
As proposed by distributor
Urban
1.78
1.82
Short
rural
2.75
2.73 a
Long rural
4.26
4.28 a
a
As proposed by distributor for 2006 – no
change over period
As proposed by distributor for 2006 – no
change over period
As proposed by distributor for 2006 – no
change over period
Urban
2005 targeted level – no change over
United
1.06
1.04
period (expenditure for reliability
Energy
improvement not provided)
Short
2005
targeted level – no change over
2.03
2.04
rural
period (expenditure for reliability
improvement not provided)
a
Changes in the targeted level between 2005 and 2006 arise from a change in methodology for counting customers
and movement of customers between network types
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Table 3:
Targeted levels for planned SAIDI
Network
type
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
2005
targeted
level
2006 targeted
level – as
proposed by the
distributor
2006 targeted level – Commission’s
Final Decision
Urban
Short
rural
CBD
6.0
6.0
As proposed by distributor
14.0
14.0
As proposed by distributor
5.9
5.9
As proposed by distributor
Urban
9.9
9.9
As proposed by distributor
Urban
Short
rural
16.0
16.0
As proposed by distributor
32.0
32.4
Increased to 35 mins based on historical
performance and consistency of the target
for short rural feeders
Long rural
71.0
73.5
Reduced to 70 mins based on historical
performance and consistency of the target
for long rural feeders
Urban
9.0
20.0
Increased to 16 mins relative to 2005
targeted level based on historical
performance and consistency of the target
for urban feeders.
Short
rural
21.0
60.0
Increased to 35 mins relative to 2005
targeted level based on historical
performance and consistency of the target
for short rural feeders.
Long rural
60.0
72.0
Urban
13.0
22.0
Short
rural
21.0
45.0
Increased to 70 mins relative to 2005
targeted level based on historical
performance and consistency of the target
for long rural feeders.
Increased to 16 mins relative to 2005
targeted level based on historical
performance and consistency of the target
for urban feeders
Increased to 35 mins relative to 2005
targeted level based on historical
performance and consistency of the target
for short rural feeders.
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Table 4:
Targeted levels for planned SAIFI
Network
type
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
2005
targeted
level
2006 targeted
level – as
proposed by the
distributor
2006 targeted level – Commission’s
Final Decision
Urban
Short
rural
CBD
N/A
As proposed by distributor
N/A
0.03
0.08
N/A
0.02
As proposed by distributor
Urban
N/A
0.03
As proposed by distributor
Urban
Short
rural
N/A
0.09
As proposed by distributor
N/A
0.14
Increased to 0.15 relative to distributor’s
proposal based on historical performance
Long rural
N/A
0.25
As proposed by distributor
Urban
N/A
0.13
Reduced to 0.09relative to distributor’s
proposal based on historical performance
and consistent with target for Powercor’s
urban feeders
Short
rural
N/A
0.29
Reduced to 0.15 relative to distributor’s
proposal based on historical performance
Long rural
N/A
0.34
Urban
N/A
0.11
Short
rural
N/A
0.23
Reduced to 0.30 relative to distributor’s
proposal based on historical performance
Reduced to 0.10 relative to distributor’s
proposal based on historical performance
Reduced to 0.15 relative to distributor’s
proposal based on historical performance
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Essential Services Commission, Victoria
Final Decision
Table 5:
Targeted levels for MAIFI
Network
type
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
2005
targeted
level
2006 targeted
level – as
proposed by the
distributor
2006 targeted level – Commission’s
Final Decision
Urban
0.4
0.8
As proposed by distributor, based on
historical performance
Short
rural
1.8
2.6
As proposed by distributor, based on
historical performance
CBD
0.0
0.05
Increased to 0.03 relative to targeted level
based on historical performance
Urban
0.3
0.3
As proposed by distributor for 2006 – no
change over period
Urban
5.3
2.0
Reduced to 1.5 based on historical
performance and consistency with target
for urban feeders for other distributors
(except SP AusNet)
Short
rural
12.6
3.5
Reduced to 3.1 relative to targeted level
based on historical performance
Long rural
20.1
9.7
Reduced to 9.0 relative to targeted level
based on historical performance
Urban
3.6
3.5
As proposed by distributor, based on
historical performance
Short
rural
8.6
5.9
As proposed by distributor, based on
historical performance
Long rural
15.7
13.5
As proposed by distributor, based on
historical performance
Urban
1.2
1.4
As proposed by distributor, based on
historical performance
Short
rural
3.3
3.4
As proposed by distributor, based on
historical performance
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3 SERVICE INCENTIVE MECHANISMS
A key element of incentive-based regulation is to provide adequate incentives for distributors to
achieve the level of service that is valued by customers. Mechanisms to ensure sufficient
incentives exist for distributors to achieve service levels valued by customers, and for which they
are accountable, are discussed in detail in this chapter.
Financial incentives on service are also designed to achieve an appropriate balance with
incentives to minimise expenditure. The experience to date suggests that, in most cases, the
distributors have been able to improve service performance while also undertaking less
expenditure than was forecast at the last price review.
The Commission is keen to ensure that these benefits are sustained into the future. The
Commission’s decision on the service incentive arrangements aims to ensure that the services
valued by customers are identified, measured and provided where the value of these services is
more than or at least equal to the cost of providing them.
Therefore, the Commission has reviewed the measures that are linked to the service incentive
arrangements and the value of the incentives provided to distributors under the arrangements to
ensure that they align with the value that customers place upon those services. The Commission
is of the view that this, in combination with the expanded reporting requirements being placed on
the distributors (see Chapter 2), ensures that distributors are held sufficiently accountable for the
services they provide and for which customers pay.
The service incentive mechanisms for the 2006-10 regulatory period consist of the following
elements:
•
the service incentive scheme, or S-factor scheme; and
•
the Guaranteed Service Level (GSL) payments scheme.
Under the S-factor scheme, a distributor’s allowed revenue (through average prices for all
customers) is increased (or decreased) based on changes in average performance from year to
year. Under the GSL payments scheme, payments are made directly to customers where the
performance received by those customers is worse than a specific threshold.
This Chapter sets out the Commission’s decision on service incentive mechanisms for the
2006-10 regulatory period in Section 3.1, while the decision is explained in Section 3.2. The
S-factor scheme, GSL payments scheme and other service incentive arrangements — the
directors’ sign off on regulatory accounts and the health card — are discussed in Sections 3.2.1,
3.2.2 and 3.2.3 respectively. Exclusions from the service incentive scheme are set out in
Section 3.2.4.
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3.1 Final Decision
3.1.1 S-factor scheme
The price control formula for the 2006-10 regulatory period includes a service adjustment or
S-factor term (St), which is calculated in accordance with the following formula:
St =
(1 + S t' )
(1 + S t' −6)
where
St' = St'' − Sbank ,t + S bank ,t −1 * (1 + pretaxWACCD )
r ,n
r ,n
r ,n
''
S t = ∑∑ st (GAPt − 2 − GAPt −3)
r
St' − 6
(a)
n
if calendar year t is prior to the calendar year ending 31 December 2012:
St' − 6 =
St − 6
1 − X 0, S
where:
S t −6
is the value of S t calculated for the calendar year t − 6 in
accordance with clause 2.3.8(ii) of the price controls dated
September 2000; and
X 0, S
is the value of X t for the calendar year 2006, calculated
exclusive of the impacts of the S-factor, as set out in clause
2.3.9(iii) of Volume 2;
(b)
r
if calendar year t is after the calendar year ending 31 December 2011, is
the value of S t' calculated for the calendar year t − 6 in accordance with
this clause.
refers to the following indicators for 2006 and 2007: unplanned interruption
frequency, unplanned interruption duration, and planned minutes off supply; and
from 2008: unplanned interruption frequency, unplanned minutes off supply,
momentary interruption frequency and call centre performance.
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refers to the following network types: CBD, urban and rural.
n
pretaxWACCD refers to the pretax value of the weighted average cost of capital for prescribed
distribution use of system services as set out in Chapter 9.
r ,n
is the incentive rate for indicator r and network type n in year t as set out in
Tables 3.1 and 3.2.
st
r,n
GAP t − 2
is the performance gap for indicator r and network type n in year t-2 and is
calculated as follows:
GAPt − 2 = TARt − 2 − ACT t − 2
r ,n
r ,n
r ,n
where
r ,n
is the distributor’s S-factor target for indicator r and network type
n in calendar year t-2 as set out in Tables 3.3 and 3.4.
TAR t − 2
r ,n
ACT t − 2
r ,n
GAPt −3
is the distributor’s actual performance for indicator r and network
type n in calendar year t-2, excluding the impact of excluded
events.30
is the performance gap for indicator r and network type n in year t-3 and is
calculated as follows:
GAPt −3 = TARt −3 − ACT t −3
r ,n
r ,n
r ,n
where:
r ,n
is the distributor’s S-factor target for indicator r and network type
n in calendar year t-3 as set out in Tables 3.3 and 3.4.
TAR t −3
r ,n
ACT t −3
is the distributor’s actual performance for indicator r and network
type n in calendar year t-3, excluding the impact of excluded
events.
and:
(a)
30
If calendar year t is the calendar year ending 31 December 2008, and if
indicator r is unplanned interruption frequency, unplanned interruption
duration or planned minutes off supply, and the distribution business is
Excluded events are events approved by the Commission in accordance with Clauses 2.3.13 and 2.3.14 of Volume 2, as
discussed in Section 3.2.4.
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SP AusNet,31 then ACTt −r ,3n is the value of ACTt −r ,2n determined in the
calendar year ending 31 December 2007 multiplied by 1.022;32
(b)
S bank ,t
If calendar year t is the calendar year ending 31 December 2008, and if
indicator r is momentary interruption frequency or call centre
performance, then GAPt r−,3n is zero.
is the amount of the service adjustment that is deferred from one year to the next.
The amount deferred in year t must be applied in year t+1. S bank ,t must have the
same sign as S t'' and the absolute value of S bank ,t must be equal to or less than the
absolute value of S t'' .
S bank ,t −1
is the value of S bank calculated in year t-1.
The incentive rates str ,n for incentive rate r and network type n for 2006 and 2007 are provided in
Table 3.1, and the incentive rates str ,n for incentive rate r and network type n from 2008 are
provided in Table 3.2. The S-factor targets for 2003 to 2005 that apply to the calculation of the
S-factor in 2006 and 2007 are provided in Table 3.3 and the S-factor targets for 2006 onwards
that apply to the calculation of the S-factor from 2008 are provided in Table 3.4.
Table 3.1:
Incentive rates, by distributor and network type, 2006-07
Network
type
AGLE
CitiPower
Powercor
SP AusNet
United Energy
31
32
Unplanned
interruption
frequency
Unplanned
interruption
duration
Planned minutes
off supply
(%/ 0.01 interruption)
(%/minute)
(%/minute)
Urban
0.0240
0.0371
0.0101
Rural
0.0014
0.0041
0.0006
CBD
0.0289
0.0073
0.0113
Urban
0.0343
0.0360
0.0146
Urban
0.0400
0.0655
0.0148
Rural
0.0266
0.0635
0.0078
Urban
0.0161
0.0338
0.0067
Rural
0.0244
0.0905
0.0089
Urban
0.0324
0.0515
0.0136
Rural
0.0021
0.0075
0.0011
Formerly TXU Networks.
In 2008 only, SP AusNet’s actual reliability performance for the calendar year 2005 will be adjusted by 2.2 per cent to
account for a change in the methodology for counting customers – see Section 2.2.1
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Table 3.2:
Incentive rates, by distributor and network type, from 2008
Network
type
Unplanned interruption
frequency
(%/ 0.01 interruption)
AGLE
CitiPower
Powercor
SP AusNet
United Energy
Unplanned
minutes off
supply
(%/minute)
Momentary
interruption
frequency
(%/0.01 interruption)
Urban
0.0486
0.0865
0.0042
Rural
0.0079
0.0113
0.0007
CBD
0.0524
0.1057
0.0000
Urban
0.0276
0.0479
0.0024
Urban
0.0207
0.0393
0.0017
Rural
0.0294
0.0421
0.0025
Urban
0.0200
0.0333
0.0017
Rural
0.0271
0.0446
0.0023
Urban
0.0515
0.0889
0.0043
Rural
0.0026
0.0037
0.0002
Call centre (%/per cent)
AGLE
-0.0380
CitiPower
-0.0441
Powercor
-0.0398
SP AusNet
-0.0325
United Energy
-0.0360
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Table 3.3:
AGLE
S-factor targets, by distributor and network type, 2003-05
Network
type
Year
Unplanned
interruption
frequency
Unplanned
interruption
duration
(minutes)
Planned
minutes off
supply
Urban
2003
1.32
59
6
2004
1.30
58
6
2005
1.27
58
6
2003
2.25
50
14
2004
2.25
50
14
2005
2.25
50
14
2003
0.25
63
5.9
2004
0.25
63
5.9
2005
0.25
63
5.9
2003
0.89
51
9.9
2004
0.85
48
9.9
2005
0.80
44
9.9
2003
1.67
64
18
2004
1.66
62
17
2005
1.63
60
16
2003
2.89
84
56
2004
2.76
82
53
2005
2.64
81
51
2003
1.86
60
9
2004
1.82
60
9
2005
1.78
60
9
2003
3.56
69
39
2004
3.39
69
39
2005
3.22
69
39
2003
1.26
58
13
2004
1.17
57
13
2005
1.06
56
13
2003
2.40
49
21
2004
2.24
48
21
2005
2.03
47
21
Rural
CitiPower
CBD
Urban
Powercor
Urban
Rural
SP AusNet
Urban
Rural
United
Energy
Urban
Rural
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Table 3.4:
AGLE
CitiPower
Powercor
SP AusNet
United Energy
S-factor targets, by distributor and network type, 2006-10
Network
type
Unplanned interruption
frequency
Unplanned minutes
off supply
Momentary
interruption
frequency
Urban
1.27
73.0
0.8
Rural
2.25
113.0
2.6
CBD
0.25
15.5
n/aa
Urban
0.80
35.0
0.3
Urban
1.63
98.0
1.5
Rural
2.64
213.8
5.6
Urban
1.78
107.0
3.5
Rural
3.22
222.2
8.5
Urban
1.06
59.0
1.4
Rural
2.03
96.0
3.4
Call centre performance, 2006-10
(per cent)
a
AGLE
75
CitiPower
80
Powercor
81
SP AusNet
70
United Energy
72
Momentary interruption frequency for the CBD network has not been included in the S-factor scheme
3.1.2 GSL payments scheme
As a minimum, distributors are required to make a Guaranteed Service Level (GSL) payment
where:
•
the customer experiences more than 20 hours of unplanned sustained interruptions33 in a
year ($100) or more than 30 hours of unplanned sustained interruptions in a year ($150) or
more than 60 hours of unplanned sustained interruptions in a year ($300), excluding the
impact of excluded events;34
•
the customer experiences more than 10 unplanned sustained interruptions in a year ($100)
or more than 15 unplanned sustained interruptions in a year ($150) or more than
30 unplanned sustained interruptions in a year ($300), excluding the impact of excluded
events;
33
34
A sustained interruption is an interruption of duration longer than one minute
Excluded events are events approved by the Commission (see Section 3.2.4).
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•
the customer experiences more than 24 momentary interruptions in a year ($25) or more
than 36 momentary interruptions in a year ($35), excluding the impact of excluded events;
•
the distributor is more than 15 minutes late for an appointment ($20);
•
the distributor does not supply electricity to a customer’s supply address on the day agreed
($50 per day to a maximum of $250); or
•
a person reports a faulty public light and that public light is not repaired within 2 business
days of being notified, and the person is the occupier of the immediately neighbouring
residence or business ($10).
Where a distributor makes an appointment with a customer, the distributor must specify a
window:
•
no greater than 2 hours where the customer or their representative is required, or chooses,
to be in attendance; and
•
no greater than 1 day where the customer or their representative is not required, and does
not choose, to be in attendance,
unless an alternative appointment window has been agreed to by the customer or their
representative. A request from a retailer for a special meter read relating to the move in of a new
customer to an existing premise is not considered to be an appointment for the purposes of the
GSL payments scheme unless the customer or their representative is required, or chooses, to be
in attendance.
The appointment window must be specified to the customer or their representative by no later
than 5 pm on the day prior to the appointment.
Where a connection request has been made to the distributor by a customer or their
representative, and no date for connection has been agreed between the distributor and the
customer or their representative, the distributor must connect the supply address within
10 business days.
The annual expenditure that has been included in the distributors’ revenue requirements for the
2006-10 regulatory period for GSL payments is set out in Table 3.5.
Table 3.5:
Annual expenditure for GSL payments, by distributor, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United Energy
17,250
1,000
1,283,000
4,314,500
254,000
3.1.3 Other service incentive arrangements
Long term reliability
On an annual basis, the Commission will include a “health card” on each distributor in the
Comparative Performance Report. The structure of the “health card” intended for the first
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Comparative Performance Report in the 2006-10 regulatory period is provided as an attachment
to this chapter.
When submitting the regulatory accounting statements for the distributor, the distributor’s
directors must also confirm in writing that the distributor will, for at least the next twelve
months, have available to it the financial resources and facilities and management resources
required to meet its obligations under the Electricity Distribution Code to:
•
meet reasonable customer expectations of reliability of supply;
•
use best endeavours to meet or exceed the targeted reliability levels required by the Price
Determination;
and that the underlying risks of a deterioration in reliability (that is, an increase in the probability
of an interruption) are not materially increasing.
At any time a distributor’s directors become aware that the underlying risks of a deterioration in
reliability (that is, an increase in the probability of an interruption) are materially increasing, they
must advise the Commission.
Distribution losses
The distributors must include a specific statement in each of their annual Distribution System
Planning Reports and Transmission Connection Planning Reports confirming that the cost of
distribution losses has been considered in identifying the least cost options for network
augmentations. Further, during the annual process to approve distribution loss factors, the
Commission will continue to monitor the levels of distribution losses to ensure that they remain
within an appropriate range, and assess the reconciliation between actual losses and forecast
losses as required by the National Electricity Rules.
3.1.4 Operation of the service incentive mechanisms
Distributors may apply to have the impacts of the following events excluded from the calculation
of the S-factor and from the requirement to make certain GSL payments:
•
for the reliability measures of the S-factor scheme and for the GSL payments for poor
reliability:
y
supply interruptions made at the request of the distribution customer affected;
y
load shedding due to a shortfall in generation, but not a shortfall in embedded
generation that has been contracted to provide network support except where prior
approval has been obtained from the Commission;
y
supply interruptions caused by a failure of the shared transmission network;
y
supply interruptions caused by a failure of transmission connection assets, to the
extent that the interruptions were not due to inadequate planning of transmission
connections; and
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y
where prior written approval has been obtained from the Commission, load shedding
due to a shortfall from demand side response initiatives.
•
for the reliability measures of the S-factor scheme calculated in years 2006 and 200735,
widespread supply interruptions due to rare events, which were not reasonably able to be
foreseen, to the extent that the distribution business was not reasonably able to mitigate
their impact; and
•
for the GSL payments scheme from 2006 and the S-factor scheme from 2008,36 supply
interruptions on a day where the unplanned sustained interruption frequency, summed
across all network types, exceeds the threshold as set out in Table 3.6. On these days, when
calculating the reliability measures of the S-factor scheme, the mean frequency and
duration of interruptions as set out in Table 3.6 must be substituted for that day’s actual
frequency and duration of interruptions. On these days, when calculating the call centre
performance measure of the S-factor scheme, the call centre performance data for that day
is excluded.
Table 3.6:
Daily unplanned interruption frequency threshold and mean daily duration
and frequency of interruptions, by distributor
Daily
unplanned
sustained
interruption
frequency
threshold
a
Mean daily
unplanned
sustained
interruption
frequency
Mean daily
unplanned
sustained
interruption
duration
Mean daily
momentary
interruption
frequency
Urban
CBD/
Rurala
Urban
CBD/
Rurala
Urban
CBD/
Rurala
AGLE
0.120
0.003
0.013
0.207
0.682
0.003
0.007
CitiPower
0.066
0.002
0.001
0.085
0.028
0.001
0.000
Powercor
0.110
0.004
0.007
0.287
0.582
0.004
0.015
SP AusNet
0.190
0.006
0.010
0.363
0.748
0.016
0.017
United
Energy
0.100
0.003
0.005
0.141
0.272
0.004
0.008
CBD for CitiPower, rural for AGLE, Powercor, SP AusNet and United Energy
3.2 Reasons for the Decision
3.2.1 S-factor scheme
To encourage the distributors to meet or exceed the targets set for unplanned CAIDI, unplanned
SAIFI and planned SAIDI37, the Office of the Regulator-General (ORG) introduced a financial
35
36
37
Based on actual performance prior to 2006.
Based on actual performance from 2006.
CAIDI, SAIFI and SAIDI have been defined in the Glossary and Abbreviations and described in Chapter 2.
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incentive scheme by the addition of an S-factor into the price control formula from 2001. The
S-factor rewards distributors with additional revenue through higher average prices where actual
performance improves relative to the reliability targets, and penalises them with lower revenue
through lower average prices where actual performance deteriorates relative to the reliability
targets.
The Commission has sought to refine the current scheme in light of stakeholder comments and
experience to date. It has incorporated the following measures into the S-factor scheme for the
2008-12 period, based on performance during the 2006-10 period:
•
minutes off supply measure (unplanned SAIDI);
•
sustained supply interruption measure (unplanned SAIFI);
•
momentary supply interruption measure (MAIFI); and
•
call centre performance measure (proportion of calls responded to within 30 seconds).
The S-factor that is calculated in 2006 and 2007, based on the performance during 2004 and
2005, will use the existing measures as set out in the Price Controls dated September 2000.
The reasons for including these measures in the S-factor scheme, the incentive rates and
weightings to apply to the measures, and the targets for the measures are discussed in this
section.
Measures for inclusion in the S-factor scheme
The Commission consulted on a number of refinements to the measures in the S-factor scheme:
•
Replace unplanned CAIDI with unplanned SAIDI — the Commission was concerned to
ensure that the incentive rate for a given interruption remained constant over the regulatory
period.
•
Include planned SAIDI in a total SAIDI measure — the Commission was concerned that
the inclusion of planned SAIDI as a separate measure may adversely impact line worker
safety by creating demands for increased live line work. The Commission also recognised
the balance between planned and unplanned interruptions.38
•
Include a MAIFI measure — the Commission considered sufficient historical data on
momentary interruptions was now available to establish appropriate targets for this
measure and include it within the S-factor scheme, as foreshadowed in the last price
review.
•
Include a customer service measure — the Commission considered this addition would
provide an incentive for the distributors to meet or exceed the targets set for the customer
service measure.
•
The inclusion of other measures.
38
An increase in the number of planned interruptions may lead to a decrease in unplanned interruptions, and vice versa, noting
that customers generally value a reduction in the number of unplanned interruptions more than a reduction in the number of
planned interruptions.
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Unplanned SAIDI measure to replace CAIDI measure
Each of the distributors supported replacing unplanned CAIDI with unplanned SAIDI although
CitiPower (2005b, p. 33) and Powercor (2005b, p. 34) noted that the inclusion of SAIDI has the
effect of amplifying the incentive and therefore the risk of this measure compared to CAIDI.
This is because SAIDI is a function of both interruption frequency (the fixed component) and
interruption duration (the variable component), while CAIDI is a measure of interruption
duration only. Hence the inclusion of SAIDI and SAIFI measures in the modified incentive
scheme provides an increased focus on interruption frequency when compared to the existing
scheme based on SAIFI and CAIDI.
The Commission notes this concern and considers that this is addressed through the appropriate
weighting of the interruption frequency and interruption duration measures. This is discussed
later in this section.
The Commission has retained its Draft Decision that unplanned CAIDI will be replaced by
unplanned SAIDI in the S-factor scheme for the 2006-10 regulatory period.
Planned SAIDI measure
None of the distributors supported the Commission’s proposal to include planned SAIDI in the
S-factor scheme as a total SAIDI measure.
CitiPower, Powercor, SP AusNet and United Energy were of the view that planned SAIDI
should be removed from the S-factor scheme to avoid tension with safe work practices and
increasing safety initiatives. However, given the Commission’s proposal to combine planned
SAIDI and unplanned SAIDI into a total SAIDI measure, CitiPower (2005a, p. 39) and Powercor
(2005a, p. 39) stated their preference to include planned SAIDI as a separate indicator rather than
a combined measure as the customer impact of planned interruptions is significantly less than for
unplanned interruptions, and therefore the incentive rate for planned SAIDI should be less than
for unplanned SAIDI.
On the other hand, CUAC and Origin Energy disagreed with the exclusion of planned SAIDI
from the S-factor scheme. Origin Energy (2005, p. 8) stated:
The distributors’ capex proposals should include the cost of conducting all planned work
safely as well as cost effectively. Origin is concerned that without a financial incentive on
planned SAIDI the distributors may be able to artificially lower their costs by taking
longer and more frequent outages in support of planned works rather than organising their
work plans to (safely) deliver projects while minimising supply interruptions.
CUAC (2005b, p. 1) stated that, as rural customers rely on electricity for water pumps, it was of
the view that planned SAIDI should continue to be included in the S-factor scheme. However,
the Commission notes that where there is a planned interruption, notice of that interruption is
required to be provided to customers and so customers are able to store water in advance for use
during the interruption. Conversely, unplanned interruptions are more inconvenient for
customers as they are unable to plan for the interruption in advance. Moreover, planned
interruptions are required to undertake works in the electricity network, which may lead to a
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reduction in unplanned interruptions. Accordingly, the Commission considers that customers
value a reduction in unplanned interruptions more than planned interruptions.
Given the concerns raised that an incentive on planned SAIDI may create a tension with safe
work practices and evidence that customers value a reduction in unplanned interruptions rather
than planned interruptions (KPMG 2003), the Commission’s decision is that planned SAIDI
should not be included in the S-factor scheme but that unplanned SAIDI should be included as a
separate measure.
In its Position Paper, the Commission did, however, propose that it would continue to monitor
the distributors’ actual performance against planned SAIDI targets over the 2006-10 regulatory
period. The Position Paper further stated that, should a distributor’s performance against planned
SAIDI deteriorate significantly (more than 20 per cent above the targeted level), the Commission
would reserve the right to include the measure in the S-factor scheme at any time during the
regulatory period for that distributor(s).
However, the Commission recognises that there are a number of problems and difficulties in
implementing the proposal contained in its Position Paper, for example:
•
determining the extent to which changes in planned SAIDI are appropriate responses to
changed work practices or growth in capital works;
•
the size of the potential penalty that is sufficient to act as an efficient deterrent;
•
the added complexity of the price control formula that would be required to allow the
additional measure to be introduced within a regulatory period; and
•
the regulatory uncertainty that would result from the threat to introduce such an
arrangement within a regulatory period.
Further, the Commission already has regulatory processes in place to deal with a distributor’s
systemic non-compliance with the conditions set out in its distribution licence. These processes
can be appropriately applied in respect of the specific circumstances that might arise in the
future.
Given these problems and difficulties in implementing the proposal contained in the Position
Paper, the Commission has decided not to proceed with that proposal. However, the Commission
will continue to monitor and report on planned SAIDI during the 2006-10 regulatory period, and
if any of the concerns identified by Origin Energy materialise, the Commission will address them
through its compliance program.
Momentary interruptions (MAIFI) measure
Each of the distributors supported including MAIFI in the S-factor scheme, although CitiPower
and Powercor’s support for including MAIFI was predicated on a change in the definition of
MAIFI from a less than one minute duration interruption to a less than three minute duration
interruption. As discussed in Chapter 2, the Commission has retained the one minute definition
of MAIFI.
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The Commission considers there is sufficient historical data on which to set targets and therefore
has included MAIFI in the S-factor scheme.
Customer service measure
In relation to customer service, the Commission proposed to include a measure of call centre
performance in the S-factor scheme. No other measure of customer service was suggested by
stakeholders.
CitiPower, Powercor, and SP AusNet supported the proposal. Conversely, United Energy
(2005c, p. 57) supported the inclusion of a call centre performance measure only if: first, the
scheme delivers symmetrical outcomes; second, the values placed on rewards and penalties are
appropriate; third, that performance is measured in an appropriate manner and at appropriate
intervals; and fourth, stakeholders see it as beneficial.
AGL ES&M and AGLE expressed concern that the historical data is not sufficiently robust to
support a financial incentive. Similarly, CitiPower and Powercor were of the view that the targets
and incentive rates should be set conservatively given the shortage of data.
The Commission is of the view that call centre performance should be included in the S-factor
scheme. Stakeholders generally support its inclusion, and the Commission considers that its
inclusion increases the distributors’ accountability for providing the required call centre
performance. As discussed in Section 2.2.3, historical data is available for the period 1999 to
2004, which is sufficient to set targets. Accordingly, the Commission has included a call centre
measure in the S-factor scheme.
Reliability experienced by the worst served customers measure
In the 2001-05 period, the S-factor scheme provides an incentive to maintain average reliability,
while the GSL payments scheme provides an additional incentive to improve reliability to the
worst served customers. The distributors were invited to propose an alternative S-factor scheme
for the 2006-10 regulatory period that includes service measures based on customers who receive
worse than average reliability, rather than measures based on average reliability. None of the
distributors proposed such a scheme.
Although SP AusNet provided in principle support, distributors in general did not support a
service incentive scheme based on the worst served customers. CitiPower (2005b, p. 40) and
Powercor (2005b, p. 40) were of the view that such an approach would:
… result in a cross subsidy, broadly from urban to rural customers, and establish a
perverse incentive to sacrifice the average performance of the majority of customers who
are not in the target group.
Conversely, Origin Energy supported such an approach if it could be demonstrated that all
customers are willing to pay more to increase reliability to the worst served customers. The
Energy Users Coalition of Victoria (EUCV) (2005d, p. 71) and CUAC (2005b, p. 11) also
disagreed with CitiPower and Powercor, and supported an S-factor scheme based on worst
served customers:
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CUAC does not believe that cross-subsidies are inherently problematic. Rather we see
cross-subsidising as a legitimate tool to improve the services to particular groups of
customers. Although the GSL scheme targets the worst served customers we do not believe
that the GSL payments are a strong enough incentive for the DBs to improve the service
levels in some of the state’s worst served areas.
CUAC would therefore support a S-factor scheme that targeted the worst served 15 per
cent of customers (as in South Australia) because we believe that a scheme based on
averages does not rightly reflect the discrepancy in service received by customers in East
Gippsland compared to, for example, West Gippsland.
The South Australian service incentive scheme mentioned by CUAC, based on worst served
customers, is supported by a willingness to pay study that indicated South Australian customers
are prepared to pay more to improve the reliability to others.39 In contrast, no such research has
been undertaken in Victoria.
As noted in Chapter 2, reliability for worst served customers has generally improved (over 1999
to 2004), indicating that the GSL payments scheme has been effective in delivering
improvements. However, reliability experienced by the worst served customers remains
significantly worse than the reliability experienced on average by customers in Victoria. Given
the higher cost to serve some customers, it is expected that there will always be some customers
who are substantially worse served than others.
In the absence of evidence that Victorian electricity customers are prepared to pay more to
improve the reliability of the worst served customers, the Commission has not included a
measure for the worst served customers in the S-factor scheme, but notes that the use of the
Value of Customer Reliability (VCR) in setting the incentive rates implies a cross subsidy
between customers who receive improved reliability by those who do not.40
However, notwithstanding the GSL payments to the worst served customers (refer Section 3.2.2),
the Commission remains concerned at the level of accountability that the distributors should
have for reliability provided to the worst served customers.
The Commission proposed in its Position Paper to continue to monitor the performance of the
reliability experienced by the worst served 15 per cent of customers. The Position Paper further
stated that, should the reliability for these customers of a distributor deteriorate significantly
(more than 20 per cent above the 2003 level), the Commission would reserve the right to include
reliability measures for the worst served 15 per cent of customers in the S-factor scheme at any
time during the regulatory period for that distributor.
However, CUAC (2005b, p. 2) indicated that it:
39
40
A scheme targeting worst served customers was introduced into South Australia from 1 July 2005, based on the total
minutes off supply experienced by the worst served 15 per cent of customers (ESCOSA 2004, p. 43).
All customers will pay through increased tariffs for the cost of service improvements to those customers supplied from areas
of the distributors’ networks demonstrating the highest benefits for improvement projects.
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… would like to see more reasoning for why significant deterioration (defined as 20 per
cent) is regarded as the requirement for regulatory intervention. In our view, a much
lower level of deterioration should warrant the introduction of regulatory incentive
mechanisms … We do not think the ESC should expect proof that all customers are
willing to pay more to improve reliability (of the 15 per cent worst served), before taking
action.
Conversely, some distributors (SP AusNet, CitiPower and Powercor) were uncertain about how
reliability measures for the worst served customers would be incorporated. CitiPower (2005b,
p. 3) and Powercor (2005b, p. 3) considered the proposed approach would introduce considerable
uncertainty and financial risk and noted that additional measures would double the weight on
reliability for the worst served and might be imposed on a distributor notwithstanding that it was
providing better average reliability than another distributor They further queried whether any
measures imposed would be removed subsequently if poor performance improved.
The Energy Networks Association (ENA) (2005, p. 8) considered the Commission’s proposal
would introduce regulatory uncertainty.
The Commission’s proposal to leave open the potential for effectively retrospective
penalties in the S-factor regime if service declines by more than twenty per cent in some
areas introduces asymmetric risk for distribution businesses and adversely affects
regulatory certainty. The ENA considers that regulatory certainty is best delivered through
a clear ex ante articulation of the regulatory regime that will apply at the outset of the
regulatory period, without post hoc penalties applied outside of an incentive regime.
The Commission recognises the benefit of incentivising distributors to avoid an increasing
deterioration in performance to worst served customers and has addressed this through
introducing multiple thresholds for, and increasing the level of, GSL payments. It recognises that
there are a number of problems and difficulties in implementing the proposal contained in its
Position Paper, for example:
•
determining the size of the potential penalty that is sufficient to act as an efficient
deterrent;
•
the added complexity of the price control formula that would be required to allow the
additional measure to be introduced within a regulatory period; and
•
the issues identified by distributors above.
Further, the Commission already has regulatory processes in place to deal with issues of
systemic non-compliance with the conditions set out in distributors’ licences.
Accordingly, the Commission has not included a mechanism for introducing a reliability
measure for the worst served customers into the S-factor scheme. However, the Commission will
continue to monitor and report on the reliability experienced by the worst served customers
during the 2006-10 regulatory period. If there is a significant deterioration in the reliability for
these customers, the Commission will address this through its regulatory compliance program.
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Other measures
Origin Energy suggested that the distributors should be held accountable for the service they
provide with respect to metering and have incentives to meet or exceed service targets via an
expanded S-factor and GSL payments scheme.
As considered in Section 2.2.3, the information available to the Commission does not indicate
that significant, systemic issues exist in the distributors’ provision of metering related services.
Additionally, the Commission does not have the historical data to include metering-related
measures in the S-factor scheme at this stage.
Uncle Tobys (2005, p. 1) and EUCV (2005b, p. 48) considered that the quality of supply ought
to be guaranteed and adequate compensation paid when supply targets are not reached. However,
as discussed in Section 2.2.2, there is insufficient data relating to quality of supply available at
this stage to incorporate it in the S-factor scheme in any meaningful way. Even if such a measure
could be included, it is important to note that GSL payments are not intended to compensate
customers. Rather, they provide an acknowledgement to the customer of poor service and an
incentive for distributors to improve.
Accordingly, the Commission has not included measures for metering or quality of supply in the
S-factor scheme.
Weightings and incentive rates
In the 2001-05 price review, the ORG established a set of incentive rates for each distributor that
converted the distributor’s actual performance against its reliability targets into an S-factor for
that distributor. The incentive rates were set for each distributor based on the estimated marginal
cost of bringing about service improvements for that distributor. The ORG also established
weightings for each of the measures. The weightings were 100 per cent for unplanned SAIFI, 65
per cent for unplanned CAIDI and 25 per cent for planned SAIDI.
Weightings
The weightings in the 2001-05 S-factor scheme were based on surveys undertaken by the
distributors. PB Power (2000, p. 10) reviewed these surveys and concluded that:
There is no clear indication of customer preference with respect to outage duration or
frequency of outages. … While there is much evidence to suggest that unplanned
interruption frequency is generally of more concern to customers than unplanned
interruption duration, it is not clear that this applies across all customer groups or to all
interruption durations. It is therefore proposed that the weighting given to unplanned
interruption duration be increased to 75 per cent of the full marginal cost estimate for
each distributor.
Since the 2000 review, customer research has been undertaken in South Australia which
determined the willingness to pay for a reduction in the number of interruptions (the fixed
component of an interruption) and the duration of interruptions (the variable component of an
interruption). The weighting between the variable component and the fixed component can be
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quantified for South Australian electricity customers from this data. While no similar customer
research has been undertaken in Victoria, several stakeholders referred to this study in their
submissions.
Prior to the release of the Commission’s Position Paper, AGLE and United Energy proposed
retaining the existing weightings, whilst SP AusNet proposed a weighting of 1 to 1 for SAIDI to
SAIFI. AGLE, SP AusNet and United Energy proposed a weighting of 10 to 1 for SAIFI to
MAIFI based on the results of the willingness to pay research that has been undertaken in South
Australia. SP AusNet (2005b, p. 14) supported the use of data from the South Australian study to
weight the performance measures in the absence of Victorian data. Conversely, United Energy
did not believe that it was appropriate to adopt the South Australian research until such time as
sufficient consultation has taken place to determine whether it is appropriate for Victoria.
Given the inconclusive nature of the survey data underpinning the existing weightings and the
absence of any new Victorian-specific data, the Commission’s view is that the weightings of the
reliability measures from the South Australian customer research are likely to provide a better
indication of appropriate weightings.
In its Draft Decision, the Commission proposed weightings based on the results from the South
Australian customer research, varying by distributor and by network type. No further comments
were made by stakeholders about these weightings, and so the Commission has adopted the
proposed weightings as set out in Table 3.7.
Table 3.7:
Weightings of reliability measures in the S-factor scheme
Network
type
AGLE
CitiPower
Powercor
SP AusNet
United Energy
Ratio of unplanned
SAIDI to unplanned
SAIFI
Ratio of MAIFI to
unplanned SAIFI
Urban
1.02
0.086
Rural
0.72
0.091
CBD
1.13
0.086
Urban
0.76
0.086
Urban
1.14
0.083
Rural
1.12
0.084
Urban
1.00
0.084
Rural
1.14
0.084
Urban
0.96
0.084
Rural
0.68
0.082
Incentive rates for reliability measures
In the 2001-05 period, where there is an improvement in reliability, the ORG considered that the
incentive rates should reflect the cost of reliability improvements, but be no greater than the
value that customers place on reliability. It put in place incentive rates based on each
distributor’s marginal cost of reliability improvements, varying between approximately
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$4,000 per MWh and $11,000 per MWh, depending on the distributor. At that time, the ORG did
not have any robust information regarding the level of reliability valued by customers and the
cost to achieve that reliability.
In their price-service proposals, AGLE and United Energy supported continuation of the existing
incentive rates. Conversely, CitiPower and Powercor indicated that they would work with the
Commission and stakeholders to determine an appropriate incentive rate.
SP AusNet supported using the Value of Customer Reliability (VCR) as the basis for setting
reliability incentive rates, as it is derived from a robust study conducted in Victoria. The study
was undertaken by Charles River Associates (CRA) for VENCorp and indicates that the value
Victorian customers place on reliability on average is the state-wide VCR of $29,600 per MWh
(CRA 2002). Its results remain current, and they are similar to a Monash study conducted in
1997 at a state-wide level.
ERAA (2005, p. 2) strongly supported the strengthening of incentives.
Conversely Origin Energy supported maintaining the current approach of setting incentive rates
based on the marginal cost of raising or lowering performance on a particular measure.
EUCV (2005b, p. 34) recommended:
… there be different reliability incentives related to each feeder as this would tend to
reflect the types of consumer connected.
The Commission notes EUCV’s suggestion regarding different reliability incentives for each
feeder, but as discussed in the Commission’s Final Framework and Approach paper, such an
approach is impractical at this stage (ESC 2004g, p. 40).
The Commission is concerned that there is a strong incentive in the short term for distributors to
maximise returns to shareholders which may increase the risk in the longer term that reliability
might deteriorate, and that this increasing risk is unobservable in the short term. The
Commission’s view is that distributors should be accountable for any deterioration in reliability.
In its Position Paper, the Commission proposed that the incentive rate for a deterioration in
reliability should be greater than current rates, to more closely reflect the value that Victorian
customers place on reliability. The Commission considered that VCR was an appropriate basis
for determining the incentive rate for a deterioration in reliability under the S-factor scheme.
VCR is already accepted as an industry standard. Distributors and others use it to assess
investments in the network (for reinforcements and augmentation). For example, in its
submission justifying expenditure to improve the security of supply in the CBD, CitiPower based
the benefits of the project on the VCR for commercial customers (of $56,625 per MWh).
However, such an approach is likely to result in the penalty for deterioration in reliability being
greater than the reward for improvement, if the reward continues to reflect the cost of reliability
improvements. Distributors and stakeholders did not support a scheme which would result in a
net penalty for symmetrical year on year changes due to weather conditions.
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Therefore, the Commission has decided that the incentive rates should be symmetrical and that
VCR is an appropriate basis for determining the incentive rates for the S-factor scheme where
there is an improvement or a deterioration in reliability.
The Commission notes that, even if incentive rates are symmetrical (same for rewards and
penalties), the potential opportunities provided by the incentive scheme may be asymmetrical.
That is, depending on a distributor’s current performance there may be a natural ceiling for
improvements, but penalties may be limited only by the quantitative exclusion criterion that
applies (see Section 3.2.4). Therefore, the scheme provides a strong incentive to distributors to
reduce their downside exposure by undertaking investment to reduce the risk of a deterioration in
reliability.
In its Draft Decision, the Commission proposed to round the value of the state-wide VCR from
$29,600 per MWh to $30,000 per MWh, except for CitiPower’s CBD customers. Given that
CitiPower has justified its expenditure in the CBD on a VCR for commercial customers of
$56,625 per MWh, the Commission was of the view that this VCR should be applied for
CitiPower’s CBD customers through the S-factor scheme, rounded to $60,000 per MWh.
SP AusNet (2005f, p. 15) noted that the VCR was determined in 2002 and suggested that it
should be escalated to 2004 dollars. However, given the intended use of the value and the long
term planning decisions which are expected to be based on the value, the Commission considers
a single value over the period based on VCR is appropriate. Hence rounded values of $30,000
and $60,000 per MWh seem reasonable for use in the S-factor scheme as they do not imply an
inappropriate level of precision and take account of a moderate level of escalation between 2002
and 2004.
The Commission has considered whether the incentive rates for reliability measures should be
set to VCR from 2008 or whether there should be a transition to VCR over a number of years.
Any transition period may lead to perverse incentives in the year prior to transition. For example,
if a distributor’s performance is worse that year, it would benefit from higher incentive rates
when performance improves the following year. Moreover, if the incentive rates were
transitioned over a period, this would provide a number of years in which this perverse incentive
applied. The Commission has therefore increased the incentive rates based on VCR from 2008.
The incentive rates to apply from 2008 (based on performance from 2006) are provided in
Table 3.2.
Incentive rates for the call centre performance measure
Only SP AusNet proposed an incentive rate for the call centre performance measure in its priceservice proposal. It proposed an incentive rate of 0.021 per cent (of revenue), which it stated is
consistent with the results from the South Australian willingness to pay study. SP AusNet’s
proposed incentive rate is based on the number of months in which the call centre performance
target was met less the number of months in which the call centre performance was not met.
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SP AusNet proposed to incorporate the call centre performance in the price control formula in
the form:
(1 +C t )
(1 +C t −1 )
where Ct = (NMt - NFt) * c
and where:
NMt
NFt
is the number of months, in year t, that the target was achieved
is the number of months, in year t, that the target was not achieved
c
is the incentive rate on call centre performance
The Commission is concerned that SP AusNet’s proposed formula does not ensure an incentive
for call centre performance is retained throughout the year. The proposed formula provides the
same reward (or penalty) regardless of whether the performance is close to the targeted level or
substantially better (or worse) than the targeted level.
Given the absence of information on the marginal cost of improvements in call centre
performance and the absence of Victorian specific data in relation to customers’ willingness to
pay for improvements in call centre performance, the Commission has used the South Australian
customer research (by customer type) as the basis for determining the incentive rate. In the
absence of information regarding the current average time to respond to a call, the Commission
has assumed calls not responded to within 30 seconds are responded to between 30 seconds and
2 minutes, for the purposes of applying the research to Victoria. To ensure an incentive is
retained throughout the year, the Commission has included the measure in the S-factor in a
similar way to the reliability measures — that is, measured as the actual performance over the
year less the targeted level of performance for the year.
CitiPower, Powercor and AGL ES&M supported the use of the South Australian data to
determine the incentive rate for call centre performance, although CitiPower and Powercor noted
that the incentive rates derived by the Commission and set out in its Position Paper appeared
relatively high compared to the current rates for reliability. SP AusNet stated that no more or less
than 0.25 per cent of revenue should be placed at risk. Origin Energy was of the view that the
incentive rates should be based on marginal cost and should only apply where they are less than
customers’ willingness to pay.
The specific call centre performance incentive rates for each distributor have been calculated
based on the South Australian willingness to pay study, the forecast annualised revenue and
breakdown of energy consumption by customer type (residential, small business and large
business), and are provided in Table 3.2. These incentive rates apply during the period 2008-12,
based on performance during the period 2006-10. The Commission notes that a distributor would
only have more than 0.25 per cent of its revenue at risk if there was a deterioration in call centre
performance of between 5.7 and 7.7 percentage points, depending on the distributor and its
incentive rate.
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Targets for the measures in the S-factor scheme
During the 2001-05 regulatory period, reliability performance targets were set to improve over
time and capital expenditure was provided for the distributors to achieve these improvements.
Rewards (or penalties) have been provided through the S-factor scheme where these targets have
been outperformed (or not achieved).
The Commission’s Final Framework and Approach was that there would be no targeted
improvements in the average measures of reliability during the 2006-10 regulatory period, unless
it was demonstrated that customers were willing to pay for these improvements. No robust
evidence has been provided that customers are willing to pay for improvements in the average
reliability, although discontent was expressed during public information forums in relation to the
reliability experienced by the worst served customers.
Accordingly, as discussed in Section 2.2.1, the targeted levels of reliability for the purposes of
monitoring and reporting will remain unchanged over the 2006-10 regulatory period, except
where a distributor has consistently outperformed its targets. Moreover, no expenditure has been
included in the revenue requirement for improvements in reliability. The expenditure on
reliability improvements will instead be provided through financial rewards from the S-factor
scheme and by avoiding the payment of GSL payments, when improvements are delivered.
Initially, each of the distributors indicated that the targeted levels for the service measures for the
purposes of reporting and monitoring, as provided in Chapter 2, should also apply to the S-factor
scheme. However, in response to the Issues Paper, SP AusNet (2005a, p. 50) stated:
In order to minimise the transitional issues arising from changes to the scheme, SP AusNet
Networks believes that the S-factor targets should be maintained at their current levels,
except where adjusted for issues such as revenue-funded improvements, as well as changes
in reporting and exemption methodologies. … There is no reason why these targets need to
be the same as the general network performance targets.
Additionally, United Energy (2005p, p. 13) noted that any adjustment to the targets from one
regulatory period to the next would curtail rewards.
The S-factor scheme is currently an incremental scheme based on:
[(Target – Actual) in year t - 2] – [(Target – Actual) in year t – 3].
Moreover, as stated above no improvement in average reliability has been targeted during the
2005-10 period. As the targets are unchanging, the target in year t-2 will be the same as the target
in year t-3 and the S-factor scheme becomes:
[Actual in year t – 3] – [Actual in year t – 2].
The targets for the purposes of the S-factor scheme thus become redundant and the S-factor is
based on the change in performance from one year to the next. Under such a scheme, distributors
would choose to improve reliability where it is efficient to do so. Customers would pay for these
improvements when the outcomes are delivered, through the S-factor scheme. This approach
minimises transitional issues other than to account for changes to service reliability measures, as
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it is based on relative performance from year to year rather than performance relative to targets.
It thereby avoids adjustments that would otherwise be required to ensure that adjustments to
targets do not result in windfall gains or losses. The Commission has decided to adopt this
approach and has therefore set the S-factor targets for the next regulatory period at the 2005
target level.
The targets for unplanned SAIFI for 2006 are the same as the targets for 2005.
A transition is required from the unplanned CAIDI measure in the existing scheme to the
unplanned SAIDI measure in the new scheme to enable the roll forward of the S-factor scheme
from the current regulatory period to the 2006-10 regulatory period. The transition will occur in
2008 by adopting the 2005 unplanned SAIDI targets and actuals. The 2005 unplanned SAIDI
target have been calculated by multiplying the unplanned CAIDI target by the unplanned SAIFI
target.
The 2006 targets for MAIFI and call centre performance are the same as those established for
reporting and monitoring purposes (see Section 2.2.1).
Consistent with the current price controls, targets for the reliability measures have been set for
CBD, urban and rural feeders. There will continue to be no distinction made, for the purposes of
the S-factor scheme, between short and long rural feeders so that there is no disincentive for
distributors to shorten long feeders as a reliability improvement measure.
United Energy has indicated that, under such an approach, it will be penalised for meeting its
targets. However the Commission notes that, excluding the impact of the St-6 factor, this will
only occur if the reliability during 2006-10 is worse than that experienced in 2005.
The targets for reliability and customer service measures are set out in Table 3.3, for the
calculation of the S-factor in 2006 and 2007 based on the performance in 2004 and 2005, and in
Table 3.4, for the calculation of the S-factor during the period 2008-12 based on the performance
during the 2006-10 period.
Volatility
In the 2001-05 regulatory period, some distributors experienced substantial volatility in their
S-factors. SP AusNet’s S-factors were the most volatile varying from +2.30 per cent in 2003 to
-2.56 per cent in 2004 and –2.73 per cent in 2005. United Energy’s S-factor has varied from
+1.95 per cent in 2003 to –1.39 per cent in 2004 to +0.31 per cent in 2005.
The Commission, in its Final Framework and Approach, invited distributors to propose options
for addressing any volatility in the S-factor scheme, and suggested options which included:
•
smoothing rewards and penalties over a two or three year period;
•
a deadband around the target (that is, rewards and penalties do not apply for performance
within a certain percentage of the target); or
•
a lower incentive rate around the target.
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Retailers expressed concern with volatility in distribution tariffs arising from the S-factor. Origin
Energy supported some degree of averaging and was interested in the trade off between the
number of years over which averaging takes place and the effect on the sharpness of the service
incentive.
Distributors suggested that the increased incentive rates proposed from 2008 may lead to greater
volatility in S-factors and were concerned, therefore, that natural variations in reliability
performance from year to year may lead to large fluctuations in revenues.
CitiPower and Powercor supported smoothing to reduce the volatility in tariffs. CitiPower
(2005b, p. 44) and Powercor (2005b, p. 44) proposed:
… an alternative model for smoothing which gives distributors limited discretion to select
the degree of smoothing desired by “banking” S-factor. … The distributor should be given
discretion, within prescribed limits, to manage the amount “banked” or the “overdraft”
drawn as part of this buffering process. In this way distributors could design their own
smoothing profile providing they remain within any prescribed limits. The “S bank”
should be indexed to reflect the time value of money.
The Commission consulted on the concept of an “S-bank” that would permit distributors to defer
part or all of the S-factor from one year to the next. Such an approach is simpler operationally for
dealing with the higher incentive rates than a deadband or a “normal” operating range, as
proposed in the Final Framework and Approach, and provides distributors a flexible method of
smoothing out the impact of normal variations in service performance from one year to the next
attributable to changes in weather conditions.
The concept of an “S-bank” was supported by EUCV (2005b, p. 58), AGLE (2005b, p. 15),
CitiPower (2005b, p. 12), Powercor (2005b, p. 12) and SP AusNet (2005b, p. 21).
Options to limit the amount banked each year and in aggregate or to allow averaging for one year
only were not supported by distributors, who sought maximum flexibility in the operation of the
bank. Based on the comments received by stakeholders, the Commission expressed concern in its
Draft Decision that distributors may inappropriately bank the S-factor if provided with a high
degree of flexibility.
The Commission’s analysis indicates that volatility is substantially reduced when the S-factor is
averaged over two years compared to one year (that is, performance is averaged over three
years). Volatility is not significantly reduced when the S-factor is smoothed over three years
compared to two years.
SP AusNet questioned this finding.
It is certainly possible to get two bad (or good) weather years consecutively…creating
unnecessary volatility. …Whilst SP AusNet understands the Commission’s view that there
is little extra benefit in extending this, there appears to be no cost and, therefore, any cost
benefit analysis must conclude that allowing companies to spread rewards and penalties
over additional years is desirable.
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The Commission notes that an averaging of the S-factor over more than two years further
separates the reward/penalty from the year of reliability performance, blunting the action of the
service incentive.
An “S-bank” has been introduced into the price control from 2006 which allows a distributor to
bank all or part of the S-factor from one year to the next, but not for more than one year. Further,
to ensure that the value of the change in revenue from the “S-bank” amount remains the same as
when the penalty (or reward) was incurred, and to reduce the incentive to bank negatives, the “Sbank” amount will be multiplied by the pre tax weighted average cost of capital.
Asymmetry
The current S-factor scheme is not entirely symmetric. Distributors supported adjusting the
S-factor formula to remove this asymmetry, and SP AusNet proposed an alternative formula to
do so:
n
(1 + CPI t )(1 − X t )(1 + At )
≥
(1 + At −1 )
m
∑∑ p
i =1 j =1
n
ij
t
qtij− 2
, i = 1,...n; j = 1,...m
m
∑∑ p
i =1 j =1
ij
ij
t −1 t − 2
q
where:
5
At is calculated as At = ∑ S t −i
i =0
In its Position Paper, the Commission was of the view that the asymmetry is immaterial — a
one per cent decrease followed by a one per cent increase results in an immaterial variation
(0.99 * 1.01 = 0.9999 or $20,000 on a revenue base of $200 million). Additionally, for each
S-factor the asymmetry exists only for six years, when it is removed by the St-6 term of the price
control. The Commission therefore proposed to not adjust the S-factor formula to remove the
asymmetry.
SP AusNet (2005b, p. 20) viewed the Commission’s decision to ignore an identified asymmetry
as a dangerous precedent and did not accept that it is immaterial, especially given the proposed
higher incentive rates. CitiPower (2005b, p. 13) and Powercor (2005b, p. 13) considered that
immateriality was an insufficient reason to reject correction. In contrast, EUCV and Origin
Energy did not support such an adjustment, stating that asymmetry reflects outcomes in a
competitive market (EUCV) and that the asymmetry is not material (Origin Energy).
The Commission notes that the formula proposed by SP AusNet does not entirely remove the
asymmetry and that a considerably more complex formula would be required to do so. The
Commission would be reluctant to introduce further complexity to the formula when some
stakeholders are currently of the view that the formula is already too complex.
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AGLE (2005b, p. 14) also recognised the difficulty in developing an understandable S-factor
formula that removes the inherent asymmetry. It proposed that an explicit allowance be included
in the weighted average cost of capital to address this matter.
However, any additional risk that may be introduced by the asymmetry is asset specific and
therefore diversifiable and does not affect the cost of capital. For these reasons, adjustment to the
weighted average cost of capital would be inappropriate.
In a further submission (2005h, p. 8), SP AusNet showed that the impact of the asymmetry could
be about 0.1 per cent of revenue in the current period and, given increased incentive rates, could
be as high as one per cent in the 2006-10 period.
The Commission notes that changes of this magnitude could only be associated with a significant
deterioration in reliability performance, as experienced by SP AusNet in the 2003-04 period.
Natural variations in performance from year to year due to weather impacts would be unlikely to
result in changes in performance, and revenue, of this magnitude, given that the impacts of
extreme events are removed through exclusion criteria and that variations can be smoothed under
the “S-bank”.
The Commission notes that the asymmetry in the formula can result in a net financial benefit or a
net financial loss to the distributor depending on the change in performance from year to year.
For example, if there is an improvement year on year or a deterioration year on year there is a net
financial benefit to the distributor, but if there is an improvement in one year followed by a
deterioration or vice versa, there is a net financial loss to the distributor. The year on year
changes are impacted by weather events but are also subject to the actions of the distributor.
All else being equal, the increased incentive rates, together with the removal of the efficiency
carryover mechanism on capital expenditure (which is likely to reduce the marginal cost of
improvements to all distributors), has the potential to provide significant rewards where
distributors are able to improve their service levels.
Therefore, the Commission expects that distributors will actively seek reliability improvement
projects to increase their profitability through the S-factor scheme. The potential benefits
available to the distributor are likely to be far greater than any losses arising from the asymmetry
inherent in the formula.
Given all of these considerations, the Commission has decided not to adjust the S-factor formula
to remove the existing asymmetry.
Transitional issues
There are a number of changes to the service incentive scheme that will commence in the 200610 regulatory period. There are transitional issues associated with these changes which are
considered in the following sections.
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Change in incentive rates
CitiPower and Powercor are of the view that any new S-factor scheme should take into account
any structural break with the current S-factor scheme. In particular, CitiPower’s and Powercor’s
agreement to any new S-factor scheme was stated to be predicated on resetting the starting
values of the performance base so that GAPt r−,3n is set to zero when calculating the S-factor for the
calendar year 2008. In their view, it is necessary to “restart” the scheme (with the increased
incentive rates and new performance measures) so as to avoid any perverse incentive to do
poorly in 2005.
If the scheme was reset as proposed by CitiPower and Powercor by setting GAPt r−,3n to zero, the
reliability data for 2005 would not be considered in determining the S-factor for 2008. The
S-factor for 2008 would be based on the difference between actual measures and target
measures, rather than on the incremental change from the previous year’s performance,
effectively delivering additional rewards for improvements already delivered and additional
penalties for deteriorations previously penalised. The Commission is therefore of the view that
the S-factor scheme should roll through into the 2006-10 regulatory period.
United Energy (2005p, p. 17) was concerned that should the scheme not be reset, a distributor
could face a significant penalty during this transitional period following a symmetrical change in
performance due to random variations in its reliability performance. This situation could arise,
for example, where a distributor out performs against its targets in 2005 (gaining a reward under
the current S-factor incentive scheme), followed by a return to target in 2006 (incurring a penalty
under the modified scheme in which higher incentive rates apply).
United Energy provided to the Commission worked examples to demonstrate the penalties that
may be payable as a result of the difference in incentive rates between one period and the next.
•
Example 1: Penalty of $36 million over 6 years if current outperformance against target
continues until 2005 and performance is on target in 2006. The Commission notes that the
performance in 2006 is a deterioration in performance relative to 2005, and therefore it is
appropriate that a penalty is incurred.
•
Example 2: Net penalty of $40 million over 6 years if an improvement in performance in
2005 is followed by an equal and opposite (symmetrical) deterioration in performance in
2006. The Commission notes that in this case the change in performance in United
Energy’s example was substantial — a 50 per cent change in performance from year to
year.
To address the potential net penalty that arises with symmetrical changes in reliability
performance during the transitional period, United Energy (2005p, p. 38), CitiPower (2005s,
p. 12) and Powercor (2005k, p. 18) have proposed that in 2008 the old incentive rates be applied
to GAPt r−,3n and the new incentive rates be applied to GAP tr−, n2 . Under such an approach, there is a
penalty (or reward) at the old incentive rates based on the difference between the performance in
2005 and the target, and then a reward (or penalty) at the new incentive rates based on the
difference between the performance in 2006 and the target.
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For example, if the target for a measure is 100 minutes, the performance in 2004 is 100 minutes,
the performance in 2005 is 110 minutes and the performance in 2006 is 102 minutes, then the
distributor would incur a penalty at the old incentive rates. This penalty would be based on the
difference between the performance in 2005 and in 2004 (10 minutes) and a reward at the new
incentive rates based on the difference between the performance in 2006 and in 2005
(8 minutes). With the increase in the incentive rates, the distributor would receive a reward for
the deterioration in performance from 2004 to 2006 in this example. Under the approach, the
distributor will effectively be rewarded for improvements already delivered and penalised for
deteriorations previously penalised.
Additionally, where there is no change in performance from 2005 to 2006, the distributors’
proposal would result in a reward if the distributor’s performance is better than target and a
penalty if the distributor’s performance is worse than target.
The Commission considers this to be a retrospective change as the decision to allow performance
to improve or deteriorate during the current regulatory period would have been made by the
distributor based on the old incentive rates.
The Commission discussed these issues at length with United Energy, who agreed that no single
mathematical solution could negate the transitional issue without creating other issues.
United Energy also identified that, under a roll through arrangement with increased incentive
rates, there may also be a perverse incentive for distributors to delay investments in reliability
improvements in the last year of the regulatory period, so as to benefit from the increased
incentive rates in the new period.
Given that the 2005 year is largely completed, the Commission considers that a distributor’s
ability to deliberately choose to affect its reliability outcome by altering its investment or
operating strategy is small. It is also likely that such action would be readily evident to the
industry and hence subject to a degree of public scrutiny and regulatory sanction. Furthermore, if
the scheme was to be modified in such a way as to remove this perverse incentive, then under
some circumstances, this will effectively delay the introduction of the new incentive rates. This
results in a perverse incentive over a longer period and provides the opportunity to the distributor
to choose to affect its reliability outcome.
For these reasons, the Commission has decided that the modified incentive scheme will operate
from 2008, based on the reliability performance that existed in 2005, rewarding or penalising a
change in performance as the scheme is designed to do. The Commission accepts that the
modified scheme places an increased amount of revenue at risk, however, this is the intended
outcome of increasing the incentive rates and is discussed further in a later section.
Additionally, when calculating the S-factor for 2008, to ensure performance is compared on a
like-for-like basis between 2005 and 2006, the distributor’s performance for 2005 will be
determined based on the exclusion criteria that apply to performance in the 2006-10 regulatory
period.
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For those indicators introduced into the S-factor scheme in 2006 (MAIFI and call centre
performance), GAPt r−,3n will be set to zero when calculating the S-factor to apply in 2006.
Incentive rate adjustment for 2006 and 2007
The incentive rates that apply in 2006 and 2007, based on the performance in 2004 and 2005,
were set as part of the last price review. These incentive rates were based on the marginal cost of
reliability improvements and are expressed as a function of revenue.
The distributors’ revenue requirements will be less in 2006 and 2007 than in the 2001-05
regulatory period with the P0 adjustment that applies in 2006. To ensure that the incentive rates
that will apply in 2006 and 2007 have the same impact in dollar terms as they were intended to
have when they were calculated as part of the last price review, they will be adjusted by the P0
(exclusive of the S-factor impacts) as follows:
s'
r ,n
t
=
s tr , n
1 − X 0, s
The revised incentive rates for 2006 and 2007 are provided in Table 3.1.
A similar adjustment has also been made to the S-factor for 2003-05 which are incorporated in
the distributors’ tariffs. This adjustment is made in calculating the P0 inclusive of the S-factor
impacts. This is discussed further in Chapter 11.
Adjustment to SP AusNet’s customer count
SP AusNet advised the Commission that disconnected customers are currently included in the
number of customers when calculating its reliability measures. It was agreed that disconnected
customers would be excluded from the calculation of its reliability measures from 1 January
2006. This, and a change to account for movement of customers between network types, will
result in a change to the calculated reliability performance of 2.2 per cent from 2006.
Because the S-factor targets are to remain at the 2005 levels, this change has not been reflected
in increased targets. Instead, an adjustment will be made to the actual performance measures for
2005 when calculating GAPt-3 in 2008. This offsets the corresponding increase in the GAPt-2
values in 2008 that will arise from the change in customer count methodology in 2006, and has
the same net effect as increasing the target.
Price control formula
The price control formula for 2001-05 period is of the form:
(1 +CPI t )(1 − X t )(1 + S t )
(1 + S t −6 )
where St is the service adjustment to the distribution price control in year t and St-6 is the service
adjustment to the distribution price control in year t-6.
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The formula has been updated to reflect the inclusion of the “S-bank”. The price control formula
is now of the form:
(1 +CPI t )(1 − X t ) S t
where St is defined in Section 3.1.1
Additionally, the incentive rate s within the St formula is no longer constant across the regulatory
period, changing in 2008 (based on performance in 2006). Hence, a t term has been added to give
it the form str ,n .
The indicators and the incentive rates used in calculating St and St-6 have also been updated based
on the earlier discussion and are set out in Table 3.1 and Table 3.2.
As the targets for the performance measures will not be changing from year to year, the service
incentive scheme effectively rewards or penalises incremental changes in performance.
United Energy (2005v, p. 19) has stated that:
The Commission is wrong in adopting a new flawed principle of ‘rewarding sustained
improvement’, that is demonstrated to deliver outcomes inconsistent with the
Commission’s primary objective, in order to justify retaining the original scheme.
United Energy considers that a more appropriate service incentive scheme should reward
distributors on the basis of the difference between performance and target. Under such a scheme,
a distributor would receive a net financial benefit for an improvement in performance in one
year, even if this improvement was due to weather and could not be sustained.
The Commission’s primary objective under the Essential Services Commission Act 2001, in
performing its functions and exercising its powers, is to protect the long term interests of
Victorian consumers with regard to the price, quality and reliability of essential services. This
objective requires the Commission to balance the quality and reliability of supply against the
price of providing those services.
The Commission is of the view that the S-factor scheme is consistent with its primary objective
because it is designed to provide an incentive to distributors to improve reliability to customers
where it is efficient to do so. Customers, through all public forums, strongly valued sustained
improvements in performance, and generally recognise variability in performance for year to
year based on weather effects.
Furthermore, the scheme as proposed by United Energy relies on the setting of appropriate
targets for the S-factor scheme. No customer research has been undertaken in Victoria to
demonstrate that the current targets are appropriate. An advantage of the scheme as proposed is
that it provides an incentive to the distributor to deliver the optimum level of performance, given
the cost to deliver this performance and the value that customers place on this performance. Over
time this will reveal the most appropriate targets.
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United Energy (2005c, p. 47) has also criticised the St-6 factor in the price control formula
because, in its view, it penalises the distributor.
The Commission notes that the St-6 removes a reward after 6 years rather than introduces a
penalty. Additionally, the Commission notes that any decisions made by the distributor to
improve performance during the current period, and thereby receive a reward through an increase
in average prices paid by customers, would have been made with the knowledge that this reward
only applied for 6 years.
Service incentive risk
All distributors raised concerns about the risk associated with the modified S-factor scheme.
United Energy (2005c, p. 47) indicated that the increase in the incentive rates would expose it to
the possibility of substantial penalties with only a limited prospect of reward given the
improvements in reliability it has achieved over the current regulatory period. Following the
release of the Draft Decision, SP AusNet (on behalf of all five distributors) elaborated on the
distributors’ concerns over the modified S-factor scheme.41
The concerns set out by SP AusNet were as follows:42
•
Increasing the incentive rates increases the volatility of the S-factor rewards and penalties.
•
There is a greater exposure to extreme weather events due to the change in the exclusion
criteria.
•
There is limited potential to earn rewards because of the economic limitations to further
improvements in reliability levels whilst penalties are only constrained by the exclusion
criteria.
•
The inclusion of MAIFI and fault call centre response into the S-factor scheme exposures
distributors to additional risk.
The Commission commissioned Mercer Finance and Risk Consulting (Mercer) to assist it in
analysing the variability in the S-factor and how this variability would change with the new
measures and incentive rates outlined in the Draft Decision. The analysis sought to identify
whether the changes to the S-factor scheme may result in asymmetry in the expected value of the
rewards and penalties that a distributor may earn.
The Commission set out the results of Mercer’s analysis in its Service Incentive Risk Issues
Paper (2005d). This paper also set out the Commissions’ views on the issues raised taking into
consideration the results of Mercer’s analysis.
In principle, the Commission considered that where there is an expectation that the value of
rewards and penalties under the service incentive arrangements outlined in the Draft Decision is
something other than zero, that this should be recognised in determining the revenue
41
42
These risks were outlined in a letter to the Commission from SP AusNet on 22 July 2005.
SP AusNet also raised an issue that was discussed in the previous section about the effect of the new incentive rates in the
transition on symmetrical changes in performance.
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requirement. However, the Commission must be satisfied that the estimation of that value is
reasonable and that the inclusion is consistent with standard finance theory, although the
Commission recognised that this will involve a degree of judgement rather than the use of an
empirical formula.
The Commission’s principle is that distributors should be funded for the value of asymmetric
risk which is non-diversifiable but should not be funded for normal business risks which are
symmetrical and diversifiable.
Mercer’s analysis (2005a to 2005e), which includes the impact of the new quantitative exclusion
criterion (see Section 3.2.4), supported the proposition that there is increased volatility in the Sfactor under the arrangements outlined in the Draft Decision when compared to the existing
service arrangements. Notwithstanding, it also concluded that the expected value of the rewards
and penalties for each distributor, based on the actual performance data for 2000-04, is
approximately zero.
On the basis of this information, the Commission concluded that the expected value of the
rewards and penalties for each distributor is approximately zero and that this would continue to
be true if there was an equal probability that 2005 was a good performance year or a bad
performance year.
Mercer’s analysis also addressed concerns that there is a greater exposure to extreme weather
events. The analysis excludes both events that meet the quantitative exclusion criteria and events
(based on experience in 2000 to 2004) with an impact that is not significant enough to meet the
exclusion criteria, as appropriate. In the analysis, excluded days were replaced by average
values. The conclusion that the expected value of the risk for each distributor is approximately
zero stands.
Although Mercer’s analysis did not include the impact of MAIFI and fault call centre measures,
the impact on the S-factor of these measures is expected to immaterial.
In response to the Issues Paper (2005d), all the distributors reiterated the view that the increased
value of the incentives would increase the volatility of the incentive scheme and that this
increased volatility in revenues increases risk.
CitiPower (2005z, p. 4-5) and Powercor (2005v, p. 4-5) also noted that the increased volatility
would lead to greater diversifiable risk which is valued by debt investors. They stated that,
because the S-factor scheme is not assured to exist past the next regulatory period, this risk may
not even out over time. They therefore suggested that the Commission should be conservative
with regard to the likely outcome of the scheme and should not accept it is likely that the
expected value of the risk faced by distributors under the modified incentive scheme would be
zero.
SP AusNet (2005t, p. 2) stated that it would cost more for the business to diversify against
increased symmetric risk. It stated that, given the increased risks under the modified incentive
scheme, it would require increased revenue to compensate it for the extra hedging it must
undertake.
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United Energy (2005t, p. 4) was concerned that the approach taken by the Commission in the
Draft Decision was inconsistent with other decisions taken by the Commission about
symmetrical, diversifiable risks, including allowing hedging in retail energy tariffs, setting the
benchmark level of gearing in its 2003 gas access review decision with reference to the volume
risk to which gas distributors are exposed and assuming regulated businesses use fixed rate rather
than floating rate finance.
Distributors also commented on their preferences for costing increased risk. AGLE (2005h, p. 3)
proposed that this risk be costed on the same basis as an insurance product while CitiPower
(2005z, p. 6) and Powercor (2005v, p. 6) proposed a methodology based on the value placed on
risk in the stock market.
The Commission is of the view that the distributors have not given sufficient weight to the
mitigating action of the “S-bank” when assessing the impact of increased volatility on the value
of debt investors. Analysis shows that volatility is significantly reduced though the “S-bank”
mechanism. The “S-bank” provides a vehicle to manage the volatility. Additionally, the
symmetric risk referred to by SP AusNet is business specific. There is no evidence to suggest
that investors cannot diversify this risk or that it is more costly for them to do so.
CitiPower and Powercor are concerned that the action of the scheme cannot be assured in the
next regulatory period. This is true. Decisions taken now cannot bind a future regulator’s pricing
determination. The Commission notes the current intention for the effect of any S-factor or
volatility between S-factors in adjacent years to net out to zero over a 6 year period.
Nevertheless, this does not result in increased risk.
SP AusNet also noted the limited potential to earn rewards because of the economic limitations
to further improvements in reliability levels whilst penalties are only constrained by the
exclusion criteria. The Commission acknowledges that there may be a natural ceiling to
reliability improvements where the marginal cost of making the improvement is not justified by
the value that customers place on that improvement. However, all else being equal, the increased
incentive rates, together with the removal of the efficiency carryover mechanism on capital
expenditure (which is likely to reduce the marginal cost of improvements to all distributors), has
the potential to provide significant rewards where distributors are able to improve their service
levels.
SP AusNet (2005h, p. 3) also stated that the increase in volatility could result in a downgrade in
its credit rating, which would increase the cost of debt. The Commission understands that creditratings are driven by the perceived ability of a business to pay its debts on time. While volatility
in revenues might impact short term cash flows, it is difficult to see how a symmetrical event
with equal probability of a positive or negative impact, and with only a small impact on
revenues, will affect a business's ability to pay on time. Hence, it is not apparent that the decision
to increase the rewards and penalties available under the service incentive scheme will affect a
business's credit rating. Additionally, the cost of capital should not be affected unless there is a
material increase in the risk of bankruptcy, which has not been evident in rating agencies’
literature.
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Importantly, the scheme is an incentive scheme. It is designed so that distributors respond to the
incentives and pursue the rewards. Therefore, although the expected value of this risk is
approximately zero where distributors do not respond, the expected value is significantly higher
and positive where the distributors respond and invest in the network to achieve service
improvement outcomes. This is because the value of the rewards under the scheme has increased
significantly whilst the costs of achieving them have reduced (through the removal of the
efficiency carryover mechanism on capital expenditure).
With regard to the additional risk that might be imposed on the distributors under the service
incentive scheme, the Commission considers that:
•
the expected value of rewards and penalties is approximately equal to zero;
•
that the combination of the increase in the incentive rates and the removal of the efficiency
carryover mechanism on capital expenditure will be more likely to result in the distributors
realising significant rewards.
Therefore, there will be no adjustment in relation to this issue.
3.2.2 GSL payments scheme
An important feature of the reliability measures and the existing S-factor scheme is that the
reward to the distributors from improving average reliability is the same for all customers,
irrespective of the level of service being provided to particular customers. The purpose of the
GSL payments scheme is to provide an additional incentive to the distributors to improve
reliability to the worst served customers.
Payments are already made automatically to customers. The Electricity Distribution Code
requires distributors to make a GSL payment to a customer where:
•
the customer experiences an interruption of duration greater than 12 hours ($80);
•
the customer experiences more than 9 interruptions in a year (urban customer) or
15 interruptions in a year (rural customer) ($80);
•
the distributor is more than 15 minutes late for an appointment ($20); or
•
the distributor does not supply electricity to a customer’s supply address on the day agreed
($50 per day to a maximum of $250).43
In addition, the Public Lighting Code requires distributors to make a GSL payment of $10 to the
first person reporting a faulty public light where a public light is not repaired within 2 business
days of being notified and that person is the occupier of the immediately neighbouring residence
or business.
43
The GSL payments for supply restoration time and frequency of interruptions are only payable for sustained interruptions
(that is, interruptions of duration longer than one minute) and to customers who consume less than 160 MWh per annum.
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In its Final Framework and Approach, the Commission sought proposals from the distributors for
a GSL payments scheme to apply in the next regulatory period. The Commission indicated that it
would not consider additional customer service measures in the GSL payments scheme unless
information was provided to support the proposal.
The Commission further indicated that it would consider a reduction in the targets for the GSL
payments scheme, the introduction of multiple threshold levels at which GSL payments apply,
the inclusion of MAIFI and an increase in the magnitude of the payments. The Commission
stated that it would agree to changes in the targets or thresholds for GSL payments where they
are consistent with the following principles:
•
The GSL payments for reliability should target those customers with the worst reliability.
•
It may not be efficient to improve the reliability for particular customers. Where reliability
is not improved, the GSL payments are an acknowledgement to these customers that this
may be the case.
•
GSL payments should reflect, where possible, variations in customers’ willingness to pay
based on their current level of service.
•
The distributors’ IT systems must be able to identify the customers to whom payments are
to be made and ensure that the payments are made.
•
The administrative costs of the GSL payments scheme must not exceed the benefits of the
scheme.
The GSL payments schemes proposed by the distributors in their price-service proposals are
summarised in Table 3.8. Following consultation on these proposals, the Commission has
decided to revise the GSL payments so that:
•
payments for long duration interruptions are based on the aggregate minutes off supply per
year, rather than the length of each interruption, and for multiple thresholds;
•
payments for an excessive number of interruptions per year are based on multiple
thresholds that are the same for all customers;
•
payments for late appointments are based on an agreed appointment window;
•
payments for late new connections are based on a reduced standard connection timeframe
of 10 business days; and
•
payments for late public lighting repairs are not changed.
Additionally, the amount payable for each GSL has been reviewed and a new GSL payment
based on momentary interruptions has been introduced.
The reasons for the Commission’s decision on the GSL payments scheme are discussed in the
following sections.
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Table 3.8:
GSL payments schemes proposed by the distributors
Description of GSL
payments measure
Current
GSLs
AGLE
CitiPower
Powercor
√a
√a
SP
Aus
Net
United
Energy
>4 unplanned interruptions
(urban)
$40
>7 interruptions (urban)
$80
>9 interruptions (urban)
$80
>9 unplanned interruptions
(rural)
$40
>11 interruptions (rural)
$80
>13 interruptions (rural)
$80
>15 interruptions (rural)
$80
Interruption longer than 10 hours
$80
Interruption longer than 12 hours
$80
Interruptions >10 hours per
annum
$40
>15 minutes late for
appointment
$20
√
$40
√
√
√
√
$50/day,
$250 max.
√
√
√
√
√
√
Public light not repaired within 2
days
$10
√
$20
√
√
√
√
4 days notice not given for
planned interruption
$20
Connection not made on day
agreed
a
Payment
√
√
√
√
√
√
√a
√
√
√
√
√
√
√
√
√
√
√
√
√
√
Proposed in enhanced offer only
GSL payments for poor electricity supply reliability
Currently, customers consuming less than 160 MWh per year receive payments for poor supply
reliability when:
•
the customer experiences an interruption of duration greater than 12 hours ($80);
•
the customer experiences more than 9 sustained interruptions in a year (urban customer) or
15 sustained interruptions in a year (rural customer) ($80).
AGLE and United Energy proposed reductions to the threshold at which these reliability
GSL payments are payable. AGLE proposed that the threshold for the GSL payment for rural
customers be reduced from 15 interruptions to 11 interruptions per annum. United Energy
proposed that the threshold for the GSL payment for urban customers be reduced from
9 interruptions to 7 interruptions per annum and the threshold for the GSL payment for rural
customers be reduced from 15 interruptions to 13 interruptions per annum. CitiPower, Powercor
and SP AusNet proposed additional GSL payments of $40 for:
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•
urban customers experiencing more than 4 interruptions per annum (CitiPower and
Powercor, enhanced offerings);
•
rural customers experiencing more than 9 interruptions per annum (Powercor, enhanced
offering); and
•
an interruption longer than 10 hours (SP AusNet).
None of the distributors proposed a GSL payment for MAIFI.
EWOV (2005, p. 1) supported a high level of consistency in the GSL payments of distributors
but identified that:
... differences in geographical areas covered by each electricity distributor may warrant
some differences in the supply restoration payment GSL and the low reliability payment
GSL.
In contrast, during public information forums, stakeholders queried why thresholds for rural
customers are higher than those for urban customers.
Origin Energy submitted that the minimum level of service proposed and the quantum of
GSL payments should be referenced to willingness to pay studies.
The thresholds for GSL payments were set for the 2001-05 regulatory period on the basis of the
reliability experienced by the worst served one per cent of customers. The Commission has
examined data on feeder performance data for 1999 to 2004 and observes that the performance
experienced by the worst served customers has improved — there were very few interruptions
longer than 12 hours and far fewer than one per cent of customers experienced reliability worse
than the GSL payment thresholds. The Commission’s view is that GSL payments should
continue to be made on the basis of reliability experienced by the worst served one per cent of
customers and thresholds should therefore be reduced accordingly.
In its Position Paper, the Commission proposed new thresholds for the worst served one per cent
on the basis of feeder performance data to 2003. Noting stakeholders’ comments that the same
thresholds should apply to rural and urban customers and that the proposed thresholds were
similar to the existing thresholds for urban customers, the Commission also proposed that the
same thresholds would apply to urban and to rural customers.
Moreover, the Commission proposed a GSL payment based on the annual aggregate duration of
interruptions consistent with the GSL payment proposed by SP AusNet. In this regard, the
Commission notes that stakeholders had expressed concern regarding the annual aggregate
duration of interruptions, but not where the duration of each interruption was less than 12 hours.
CUAC (2005c, p. 3) strongly supported a GSL payment based on the total duration of
interruptions over a year.
However, AGLE (2005b, p. 11) opposed a GSL payment based on the cumulative interruption
duration over a year rather than the duration of a single interruption. It claimed that its systems
are not capable of providing this information and that it had not allowed for expenditure on its
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systems to provide this functionality. AGLE has since advised that the cost will be $100 000 to
provide this functionality plus $110 000 per annum to administer this GSL payment. This
expenditure has been considered as a step change in operating and maintenance expenditure (see
Chapter 6).
Distributors also noted that the proposed thresholds would be likely to capture more than one per
cent of customers.
The Commission also consulted on the amount of each GSL payment. Given the Commission’s
view that the accountability of the distributors for service outcomes should be increased, the
Commission proposed to increase the GSL payments for the duration and frequency of sustained
interruptions from $80 to $100. This would enhance the incentive for the distributors to improve
reliability for those customers in pockets of poor reliability. Further, the Commission considered
that a multi-level GSL payment would more closely reflect study results that show customers’
willingness to pay increases as the number of interruptions increases or the duration of
interruptions increases.
Additionally, given the level of concern raised during public information forums at Lilydale and
Colac regarding outlier performance, the Commission proposed three levels of payment, with the
second level of payment being an additional $50 and the third payment (an additional $150)
being double the payments at the lower thresholds combined.
AGL Retail (2005, p. 1) supported an increase in payments for GSLs for poor reliability and
considered that an extra $50 payment provides further incentive to contain supply failure. In
contrast, CitiPower (2005b, p. 5-6) and Powercor (2005b, p. 5-6) considered there was no
evidence for willingness to pay for GSLs and therefore no foundation for increasing the payment
level.
Customers also proposed extensions of the GSL scheme. Johanna Seaside Cottages (2005b, p. 1)
proposed an additional threshold of 72 hours off supply ($450) to provide increased
compensation for prolonged power outages. Gilbert (2005, p. 1) proposed that GSLs should
cover power interruptions that last all night through the off-peak electricity period (generally
between 11pm and 7am for hot water heating) to reflect the greater inconvenience caused.
Gilbert also proposed that a payment should be made for not adhering to scheduled planned
interruption times.
The Commission notes the specific nature of these proposals. Importantly, the GSL payments
scheme is not intended to provide compensation to customers receiving poor reliability. The
value of payments would not be sufficient to achieve this outcome. Similarly, given that different
customer groups are likely to place different values on the impacts of various types and timing of
supply interruptions, the Commission considers that the GSL payments should not be focused on
the impacts on particular customers or groups of customers. Rather, the reliability-based GSL
payments provide an incentive to distributors to improve reliability to worst served customers.
Nevertheless, these proposals support that a three level GSL payment is preferred over a two
level payment.
Additionally, United Energy (2005c, p. 47) considered that planned interruptions should be
excluded from reliability GSL payment thresholds as these are not considered to be poor
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reliability by customers. The Commission understands that this concern arose because, if a
customer experienced one planned interruption, a subsequent interruption could result in that
customer exceeding the threshold for the annual duration of interruptions. CitiPower and
Powercor also proposed that planned minutes should be removed from GSL payments for
consistency with its removal from the S-factor scheme. Further discussions with ETU indicated
support for this approach, given the incentives for the distributor to undertake unsafe work
practices to avoid GSL payments.
The Commission recognises the potential impacts on safe working practices of including planned
interruptions in the service incentive mechanism and has removed planned interruptions from the
S-factor scheme for this reason. While retaining planned interruptions in the GSL payments
scheme encourages distributors to consider the impacts of planned work on worst served
customers, it might also incentivise distributors to defer such work to avoid potential payments.
The Commission has, therefore, based the GSL payments for the duration and frequency of
sustained interruptions on unplanned interruptions only.
EUCV was of the view that there should be an incentive to reduce the frequency of short term
outages and voltage dips which cause production plant outages. Given stakeholders’ concerns on
the number of momentary interruptions and the Commission’s view that the distributors’
accountability for service outcomes should be increased, the Commission has introduced a GSL
payment for MAIFI. The Commission considered that distributors have sufficient data to define a
MAIFI threshold and therefore proposed a GSL payment for MAIFI based on approximately a 9
to 1 ratio between SAIFI and MAIFI. Data provided by distributors confirms that thresholds of
24 and 36 momentary interruptions per year are appropriate to capture about one per cent of
customers.
The Commission considers that GSL payments should continue to be paid by distributors to
customers experiencing the worst one per cent of reliability with respect to the duration and
frequency of interruptions. Based on updated information provided by distributors the
Commission has therefore decided that, as a minimum, the distributors are required to make a
GSL payment to customers where:
•
the customer experiences more than 20 hours of unplanned sustained interruptions in a
year ($100) or more than 30 hours of unplanned sustained interruptions in a year ($150) or
more than 60 hours of unplanned sustained interruptions ($300), excluding the impact of
excluded events;
•
the customer experiences more than 10 unplanned sustained interruptions in a year ($100)
or more than 15 unplanned sustained interruptions in a year ($150) or more than 30
unplanned sustained interruptions ($300), excluding the impact of excluded events; and
•
the customer experiences more than 24 momentary interruptions in a year ($25) or more
than 36 momentary interruptions in a year ($35), excluding the impact of excluded events.
The Commission requires GSL payments to automatically be made to customers where their
supply does not meet the thresholds specified.
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GSL payments to large customers for poor electricity supply reliability
GSL payments for poor reliability are currently only made to customers with annual
consumption less than 160 MWh. In its Final Framework and Approach, the Commission asked
distributors to consider whether GSL payments for poor reliability should be made to all
customers, not just those with an annual consumption less than 160 MWh. Only AGLE
supported making GSL payments to customers with annual consumption greater than 160 MWh,
but only to those without a specific supply agreement. CitiPower, Powercor, SP AusNet and
United Energy did not support making GSL payments to customers with annual consumption
greater than 160 MWh on the basis that:
•
$80 payments are not meaningful to large customers;
•
larger customers have scope to improve their reliability through an enhanced level of
network connection or through equipment installed on the customer side of the meter; and
•
larger customers had indicated to the distributors that there would be greater benefit to
them by the distributors concentrating on improving reliability rather than making
GSL payments.
EUCV (2005b, p. 37) did not support making GSL payments to customers with annual
consumption greater than 160 MWh. It stated:
The losses experienced by large industrial consumers for failure of the network supply are
much greater than the GSLs. However, large customers are entitled to receive a quality of
supply consistent with the network average, thus imposing an obligation on the businesses
to upgrade the supply quality to reflect this right.
EUCV (2005d, p. 74) also suggested that, as customers consuming more than 160 MWh per year
are ineligible to receive reliability GSL payments, they should not fund these payments to other
customers.
However, at public forums held in Melbourne, some large business customers noted that not all
customers consuming more than 160 MWh per year were able to negotiate effectively with
distributors and that they would prefer to receive GSL payments for poor reliability so as to
incentivise distributors to improve supply reliability to them.
In seeking to clarify the extent to which GSL payments are not made to large customers who
would otherwise be entitled to them, AGLE and CitiPower advised that no payments would have
been made to larger customers if they were so entitled. In contrast, SP AusNet advised that it
makes payments to all customers as it is cheaper than to exclude specific classes of customers.
Given some support for GSL payments to large customers, that some distributors currently make
payments to large customers, and that the determination of the expenditure for the GSL
payments scheme did not exclude large customers, the Commission has decided to require GSL
payments to be made to all customers including those with annual consumption greater than 160
MWh.
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GSL payments for appointments
There is currently a $20 GSL payment made where a distributor is more than 15 minutes late for
an appointment, although AGLE currently pays $40 rather than $20. Performance data for
2001 to 2004 indicate that few GSL payments for appointments have been made.
Under the current GSL payment for appointments, there is no requirement on the distributor as to
the length of the appointment window provided to the customer. The Commission therefore
invited the distributors to propose an appointment window that it considered appropriate for
customers. AGL Retail (2005, p. 1) supported the introduction of appointment windows as
appropriate to manage customers’ expectations of timely service delivery.
The length of the appointment window proposed by each distributor in response to the
Commission’s request in its Final Framework and Approach is summarised in Table 3.9 along
with the forecast cost impact of the proposal.
Table 3.9:
Proposed length of appointment window and cost impact, by distributor
Appointment window
Cost impact
($2004)
AGLE
2 hour window
Nil
CitiPower
Continue standard half day window, negotiated specific time
appointments
Nil
Powercor
Continue standard half day window, negotiated specific time
appointments
Nil
SP AusNet
Continue to nominate a specific appointment time
Nil
United Energy
15 minute or 1 hour window
Nil
CitiPower, Powercor and United Energy considered their current appointment windows to be
appropriate. Furthermore, SP AusNet (2005a, p. 52) noted that:
… appointments are appropriate where there is a requirement for customers or other
contractors to be on site. There are a number of situations where co-ordination is not
required and making specific appointments is both unnecessary and inefficient, for
example, new connections where the site is open and all electrician work completed in
advance.
Origin Energy supported the short appointment windows, such as those proposed by United
Energy and SP AusNet. EWOV supported a two hour appointment window, whilst AGL ES&M
supported an appointment window no greater than half a day.
In its Position Paper, the Commission therefore proposed an appointment window of:
•
a maximum of 2 hours where the customer or their representative is required, or chooses,
to be in attendance; and
•
a maximum of one day where the customer or their representative is not required, and does
not choose, to be in attendance.
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In response to the Commission’s Position Paper, CitiPower (2005b, p. 7) and Powercor (2005b,
p. 7) expressed concern that a limited ability to fully utilise the flexibility many customers have
in making appointments would reduce the efficiency and increase the costs of distributors’
resource management. They noted that they currently offer choice to customers for appointments
for special meter reads or connection services between a 2 hour time-band of attendance for
certain works, an am or pm band or an all-day time-band for certain works.
Conversely, EUCV (2005b, p. 1) supported the Commission’s proposal regarding maximum
appointment windows.
Subsequently, distributors raised concerns about the types of activities associated with
appointments, particularly same day fuse insertions and special meter reads, both associated with
a change of occupancy. Normally, neither activity requires the customer to be in attendance,
unless there are access problems, but the revised definitions would classify these activities as
appointments. United Energy (2005d, p. 11) states:
…United Energy supports same day fuse inserts being classified as same day
appointments. However, the application of “day appointments” to Special Read Requests
would have significant cost impact on UED.
The Commission acknowledges the need to allow some flexibility, provided this is acceptable to
the customer. Because special meter reads associated with a change of occupancy are usually
requested by a retailer on behalf of a customer and are subject to agreed transfer arrangements,
the Commission will not require this activity to be classified as a same day appointment for the
purposes of the GSL payments scheme unless the customer or its representative is required, or
chooses, to be in attendance.
The Commission therefore requires distributors, as a minimum, to make a GSL payment where
the distributor is more than 15 minutes late for an appointment ($20). Where a distributor makes
an appointment with a customer, the distributor must specify a window to the customer or their
representative by no later than 5 pm on the day prior to the appointment of:
•
no greater than 2 hours where the customer or their representative is required, or chooses,
to be in attendance; and
•
no greater than one day where the customer or their representative is not required, and does
not choose, to be in attendance;
unless an alternative appointment window has been agreed to by the customer or their
representative. A request from a retailer for a special meter read relating to the move in of a new
customer to an existing premise is not considered to be an appointment for the purposes of the
GSL payments scheme unless the customer or their representative is required, or chooses, to be
in attendance.
GSL payments for connections
The Electricity Distribution Code currently requires the distributors to use best endeavours to
connect a customer by the date agreed, or where no date has been agreed, within 20 business
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days. A GSL payment of $50 per day to a maximum of $250 is made where the customer is not
connected on the date agreed.
The Commission invited distributors to base their price-service proposals on a customer
connection time that was shorter than the current 20 business days, and which could be
demonstrated to be considered appropriate by their customers — for example, a standard
10 business day or 15 business day connection time. The Commission expected that this standard
connection time may vary to cater for, for example, remote locations, complex connections and
connections in inaccessible areas.
The connection time proposed by each distributor in its price-service proposal, with the forecast
cost impact of the proposal, is summarised in Table 3.10.
Table 3.10:
Proposed connection times and cost impact, by distributor
Connection time
Cost impact ($2004)
20 business days
Nil
10 business days
Connection fee 50 per cent higher
CitiPower
Enhanced offering – 10 business days
$0.1 million per annum
Powercor
Enhanced offering – 10 business days
$0.1 million per annum
SP AusNet
15 business days for GSL payments,
20 business days in Electricity Distribution
Code
$0.2 million p.a. if GSLs based on 15
business days, $0.7 million p.a. if the
Electricity Distribution Code is based on
15 business days
15 business days
Additional GSL payments
AGLE
United Energy
EWOV, AGL ES&M and Origin Energy were of the view that the standard connection time
could reasonably be reduced, with Origin Energy noting that it would be difficult to accept that
there should be a cost impact for moving to a tighter standard. The National Electrical and
Communications Association (NECA) is an industry organisation representing approximately
1200 Victorian electrical contracting businesses which interact with the distributors and retailers
on a daily basis, generally on behalf of the electricity customer. Based on its experience dealing
with the distributors, NECA supported a 10 business day connection time.
Based on comments from stakeholders, the Commission proposed a reduced standard connection
time from 20 business days to 10 business days in its Position Paper. The Commission noted that
information provided by the distributors in their regulatory audit reports indicates that
10 business days is reasonably achievable. As this timeframe is already being achieved, the cost
of achieving it is already included in the out-turn expenditure. However, it was proposed that a
small expenditure allowance be provided to the distributors to make the additional
GSL payments that may arise from such a reduction.
SP AusNet (2005b, p. 16) stated that it is not currently meeting the 10-day timeframe and would
require an additional expenditure allowance to do so. CitiPower (2005b, p. 7), Powercor (2005b,
p. 7) and United Energy (2005c, p. 48) considered the 10 day threshold to be achievable where
supply is available adjacent to the site and connection is to a single-phase service at a single
premise, but that a higher threshold or additional expenditure allowance would be required if
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more complicated services were included. The Commission notes that a 10 day connection
timeframe applies only where an alternative date has not been agreed. The Commission expects
that the distributors would largely be successful in obtaining customers’ agreement to a date for
connection of more complex sites, rather than relying on the default timeframe.
AGLE (2005b, p. 12) accepts the 10 day timeframe but expects that it will make GSL payments
rather than improve its service delivery to customers.
AGL Retail (2005, p. 2) and EWOV (2005b, p. 2) supported the proposed reduction, as did the
Energy Action Group (2005, p. 2) and EUCV (2005b, p. 52), although they did not agree that a
revenue allowance is required. Given that the Commission has not included expenditure in the
revenue requirement for the distributors to reduce their standard connection times, the
Commission is of the view that an amount should be included in the expenditure requirement
based on the estimated number of GSL payments. The information available in the regulatory
audit reports indicates that the number of GSL payments that will be made is likely to be small.
The distributors can choose to connect customers within the required time or make the
GSL payment.
Accordingly, the Commission requires distributors, as a minimum, to make a GSL payment
where the distributor does not supply electricity to a customer’s supply address on the day agreed
($50 per day to a maximum of $250). Where a connection request has been made to the
distributor by a customer or its representative, and no date for connection has been agreed
between the distributor and the customer or its representative, the distributor must connect the
supply address within 10 business days. The Commission has included a small amount in the
expenditure requirement for additional GSL payments that may arise.
GSL payments for public lighting
All distributors have proposed to continue to make a GSL payment where a public light is not
repaired within 2 business days of being notified by the occupier of the immediately
neighbouring residence or business. Whilst AGLE has proposed to continue to pay $20, the other
distributors have proposed to continue to pay $10.
The Commission notes that the distributors make very few GSL payments for public lighting.
EWOV, the Streetlight Group of Councils (SLG) and EUCV supported an increase in the
GSL payment to $20. Additionally, the SLG believed that the GSL payment for public lighting
should be made accessible to all Victorians (not just to adjoining properties), and be reissued for
each occasion that repairs are not completed within the required time frame. As a minimum,
SLG recommends that payments be extended to Public Lighting Customers such as municipal
councils and VicRoads.
The SLG’s proposals seek to bring the Victorian GSL payment into line with the South
Australian scheme. However the schemes are not directly comparable as there is a fundamental
difference between the operating environments in Victoria and South Australia. In Victoria, the
Public Lighting Code, developed in conjunction with the councils, requires that public lights are
replaced under a bulk replacement program or are patrolled on a regular basis to identify faulty
lights. In South Australia the payment scheme is the primary method for identifying faulty lights
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(at least on minor roads, where the majority of lights are located) and therefore has to provide
sufficient incentive for people to identify and report faulty lights. Accordingly, the Commission
does not propose to amend the scheme as suggested by the SLG.
Origin Energy was of the view that the GSL payment was anomalous given that the activity is
now contestable. However, while the repair of public lighting could be a competitive activity, the
recent review of public lighting-excluded service charges indicates that the market for the repair
of public lighting is not effectively competitive and there is an insufficient threat of potential
competition to mitigate the monopoly power of the distributor.
Indeed, the distributors generally supported continuation of the public lighting GSL payment.
The number of lights maintained by alternative service providers is currently small and they are
able to differentiate payments for lights maintained by them. United Energy (2005c, p. 17)
identified that:
… as public lighting becomes more contestable, the Commission through regulation must
transfer responsibility for the GSL to the owner of the assets.
If the market for public lighting becomes more competitive over the 2006-10 regulatory period,
it may be appropriate to remove the obligation for the distributors to make a GSL payment for
public lights that are not repaired.
Given the high proportion of public lights maintained by the distributors, the Commission has
therefore decided that the public lighting GSL payment should continue to be paid — by the
distributor where it is responsible for operating and maintaining the public lights — to a person
who reports a faulty public light in circumstances where that public light is not repaired within
2 business days of the distributor being notified and the person is the occupier of the immediately
neighbouring residence or business.
Given the transition to a more contestable market for public lighting, the Commission does not
support an increase in the minimum GSL payment from $10, as a minimum standard, at this
stage. However, distributors may choose to pay more, as AGLE has done.
Other GSL payments proposed
United Energy proposed an additional GSL payment of $20 where four business days notice is
not given for a planned interruption. This was proposed in conjunction with removing planned
SAIDI from the S-factor scheme on the basis that:
•
planned interruptions affect less than 5 per cent of its customers each year; and
•
few complaints are received when the current four-business-day notice period for planned
interruptions is adhered to (United Energy 2004e, p. 47).
The Commission sought comment as to whether customers would value the inclusion of a GSL
payment where four business days notice is not given for a planned interruption.
Whilst United Energy and AGL ES&M supported the introduction of a GSL payment for not
providing notice of planned interruptions, CitiPower, Powercor, SP AusNet and Origin Energy
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did not. EWOV was of the view that, if it was introduced, then it needed to be introduced by all
distributors.
The Commission has decided not to introduce a GSL payment for not providing notice of a
planned interruption. This is because firstly, customers do not appear to have a consistent view
as to an appropriate notice period for planned interruptions; secondly, the customer’s concern
relates to receiving the notice rather than the distributor giving the notice, and this is difficult to
measure; and thirdly, it has not been demonstrated that customers would value the introduction
of this GSL payment. However this does not preclude the distributors choosing to introduce this
GSL payment as a show of good faith or to demonstrate customer service.
Additionally, Origin Energy (2005, p. 7) suggested that there should be GSL payments for
metering:
As the Commission has decided to continue to define metering for small customers as a
prescribed service, it is appropriate that the distributors be held accountable for the
service that they provide and be incentivised to meet or exceed the service targets (via
expanded S-factor and GSL payment schemes).
Participants in the Commission’s Information Forums held in December 2004 also raised this
issue.
As discussed in Chapter 13, metering services for customers who consume less than 160 MWh
per annum and have a manually read meter will be a prescribed service during the
2006-10 regulatory period. In its Position Paper, the Commission proposed to introduce two new
GSL payments of $20 where the distributor is the Responsible Person and:
•
a special meter read is not undertaken on the scheduled date for reasons within the control
of the distributor; or
•
a customer requests that a meter be tested and it fails the meter test.
CitiPower, Powercor and United Energy opposed these proposed GSL payments and highlighted
the significant practical difficulties in apportioning responsibility between the distributor, retailer
and customer where a meter read has not occurred. Distributors also raised the issue of access to
a meter as a major barrier to obtaining a special meter read on time.
CitiPower (2005b, p. 8) and Powercor (2005b, p. 8) noted that in 2004, only 15 and 19 of their
meters respectively failed a meter test, and that in this event, they waive the meter testing charge.
United Energy (2005c, p. 48) noted that there is little effective action a distributor could
undertake to reduce the number of failed meter tests.
The Commission notes that very few meters fail meter tests, and considers that the proposed
GSL payments of $20 would be insufficient relative to the cost of a meter test if it passes. The
Commission has therefore decided not to introduce GSL payments for metering.
The Commission also considered the introduction of a GSL payment based on a quality of
voltage measure. However, it has concluded that this is currently infeasible as the existing
voltage monitoring is based on a sample of feeders only, rather than all feeders. The Commission
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has provided expenditure for distributors to improve the quality of supply over the next
regulatory period so that they improve the level of compliance with the Electricity Distribution
Code. At the next review, consideration may be given to the introduction of a GSL payment in
relation to one or more measures of quality of supply.
Forecast expenditure on GSL payments
In the 2001-05 regulatory period forecast expenditures for GSL payments were included in the
distributors’ revenue requirements in the first year and scaled to zero (for urban distributors) or
50 per cent (for rural distributors) in the last year of the regulatory period. Capital expenditure
was also provided to improve reliability, including to worst served customers.
In its Position Paper, the Commission indicated that forecast expenditure for making GSL
payments in the 2006-10 regulatory period would be included in the distributors’ revenue
requirements. Under the Commission’s proposed approach, distributors would be provided with
sufficient revenue to make GSL payments that are implied by the existing standards of service.
Because costs associated with improving performance can be recovered through foregone
payments, an incentive is provided to improve service standards, where the cost of improvement
is less than the level of GSL payments that would otherwise be made. It reflects an assumption
on the Commission’s part that customers receiving average levels of service are ‘willing to pay’
for service improvements for the worst served customers. Information gained at public forums
indicated that, whilst not all customers agreed that they should pay more, strong support was
shown for improving service to worst served customers.
Additionally, because expenditure for any additional GSL payments payable due to a
deterioration from the current level of performance has not been included in the revenue
requirement, an incentive is also provided to at least maintain service levels to worst served
customers.
EUCV (2005b, p. 55) did not support the distributors receiving any such funding. However, the
Commission notes that if no funding was provided to the distributors for GSL payments, funding
to enable the distributors to deliver a minimum level of service implied by the GSL payments
would need to be provided.
For the reasons outlined, the Commission has decided to include expenditure for making GSL
payments in the revenue requirement. The forecast expenditure associated with the modified
GSL payments scheme, based on information provided by distributors about the expected
number of payments, is set out in Table 3.5.
3.2.3 Other proposed service incentive arrangements
Other proposed service incentive arrangements discussed in this section, are incentives to protect
reliability in the long term and a loss incentive mechanism.
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Incentives to protect reliability in the long term
The distributors were required to demonstrate that the service incentive arrangements proposed
by them will provide the appropriate incentives in both the short term, that is, within the
regulatory period, and the long term, for example, a 20 year horizon. The Commission is
concerned that the impact of decisions taken now by the distributors may not be evident in the
short term, but may affect the reliability of the network in the longer term through an increase in
the probability that an interruption occurs. In particular, the average reliability measures are
lagging measures, that is, a change in outcome lags a change in behaviour.
EUCV (2005b, p. 55) also expressed concern regarding the “short termism” of the distributors:
Over recent years, the life time of a CEO in Australian business has becoming shorter,
the mobility of senior executives has increased and the level of ownership of public
companies by fund managers has also increased. These factors all point towards a need
of stakeholders, CEOs and senior executives to look at performance over a shorter time
horizon, and particularly they lead to focusing on short term profits at the expense of
longer term viability of the enterprise.
None of the distributors addressed the long term reliability issue in their price-service proposals.
To address long term reliability, and in the absence of proposals from the distributors to address
this issue, the Commission considered the inclusion of leading measures in the service incentive
mechanisms, that is, the inclusion of measures that will identify a change in behaviour which
may lead to a deterioration in reliability over time.
One option raised by the Commission in its Issues Paper was the inclusion of an operational
measure. The operational measure would be based on the plans already developed by the
distributors to support their business, and their adherence to the plans over time.
In response to criticisms about the practicality of such an operational measure, the Commission
modified its approach and proposed the introduction of a “health card” for each distributor that
would be included in the annual Comparative Performance Report in a traffic light form —
measures would be displayed as green (highest rating), orange or red (lowest rating). The “health
card” would consist of measures to provide an indication where a distributor may not necessarily
be implementing its long term strategy and/or plans. It would seek to identify changes that may
indicate a deteriorating “health” of the business which may lead to an increase in the underlying
risks assumed by the distributor.
In response, SP AusNet (2005b, p. 17) reiterated that it considered the proposed price control and
S-factor scheme were sufficient to ensure long term network health. Further, SP AusNet warned
of the risk that management focus would turn from delivering desired efficient outcomes to
obtaining a “green light” and considered the benefits of the health card to be unclear, at best.
CitiPower (2005b, p. 9) and Powercor (2005b, p. 9) also considered the identification of effective
indicators problematic and were not convinced of the benefits from the more intrusive reporting
implied.
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The Commission is aware of the need to retain an output focus in the measures proposed and to
avoid attempts to micro-manage the distributors’ businesses. However, the Commission remains
of the view that measures to provide an indication to the Commission that a distributor may not
necessarily be implementing its long term strategy and/or plans are necessary to maintain
accountability for reliability of the network in the longer term.
The Commission has discussed the measures and ratings that should be included in the ‘health
card’ with the distributors. The aim of these discussions was to ensure that, where possible, the
measures and ratings adopted were a reasonable indicator that the distributors’ plans are effective
and being implemented, including asset management plans, network augmentation plans,
electricity safety management plans, vegetation management plans, asset maintenance plans,
inspection and condition monitoring plans and workforce plans. Additionally, the Commission
sought to ensure that, where possible, the proposed measures were able to be based on currently
reported and available data.
With regard to specific measures proposed, EWOV noted that, for the purposes of the health card
there is a need for consistency in how ‘complaints’ is defined by the distributors. The
Commission shares this concern and is therefore proposing to define complaints in terms of the
number of complaints referred to EWOV. EWOV also considered that the thresholds proposed
for complaints were too low and suggested a green light be set at an increase in complaints of
less than 50 per cent, orange light at an increase of between 50 and 100 per cent and red light at
an increase of greater than 100 per cent. The Commission concurs with this view and has
amended the “health card” accordingly.
In meetings with the Commission, the ETU recommended new measures based on the number of
electrical incidents notified to Energy Safe Victoria (ESV)44 and the number of incidents reported
to the Victorian WorkCover Authority. The Commission is of the view that such measures
should be included in the health card and will discuss suitable measures with ESV and the
Victorian WorkCover Authority in due course. The Commission has discussed the other
proposed safety related measures with ESV and has updated them to reflect the type of
information provided by distributors to ESV.
CitiPower (2005s, p. 9) and Powercor (2005k, p. 14) were concerned about the inclusion of the
regulatory and safety audit scores as measures.
The Regulatory Audit and the OCEI (ESV) Audit adhere to a prescriptive process whereby
the audit results provide a clear independent assessment of the distributors’ compliance to
the various licence conditions… It is not helpful to provide further assessment on Audit
scores that have already evolved through the application of stringent assessment criteria.
In the event that audit scores remain as a measure in the “health card”, it is important
there is a transparent process for consultation with stakeholders on the methodology used
for developing audit scores. Such weightings would also need to be reviewed each year as
the audit scope changes.
44
Energy Safe Victoria incorporates the former Office of the Chief Electrical Inspector.
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CitiPower and Powercor also commented on the proposed measure for the Bushfire Mitigation
index.
… the Commission has proposed that a result of zero at the start of the bushfire season will
obtain a “green light” on the “health card” and any other result other than zero will
obtain a “red light”. Such a target is simply unbeatable and any other result, however
small, results in a “red light”. Also, the draft decision proposes that the indicator must be
zero “at the start of the bushfire season”. This is problematic as the bushfire season is not
uniformly declared across the regions of Victoria.
The Commission considers that the health card is best structured by aggregating available
information and that the use of audit scores and distributors’ reporting on Bushfire Mitigation is
an appropriate way of assessing distributors’ long term performance capability. Considering
distributors’ comments, the measures for audits and bushfire mitigation have been altered to
reflect ESV’s assessment of the level of compliance against the audited items. This approach
allows a graduated assessment for bushfire mitigation, depending on the successful completion
of each component of the distributors’ mitigation plans.
The Commission has decided that, from 2006, it will include a health card for each distributor in
the annual Comparative Performance Report. The Commission may review the health card
annually. The health card intended for the first Comparative Performance Report in the next
regulatory period is provided in the attachment to this chapter.
In its Position Paper, the Commission also proposed that the distributors’ directors sign off on an
annual basis that nothing had come to their attention that would reasonably lead them to believe
that:
•
the distributors’ plans and processes will not ensure that the reliability of the network will
be maintained or improved over the next 20 years; and
•
the underlying risks of a deterioration in reliability are increasing.
It was also proposed that, when submitting the regulatory accounts for a distribution business,
the distributor’s directors would be required to sign off that nothing had come to the directors’
attention that would reasonably lead them to believe that expenditure incurred will not ensure
that the reliability of the network will be maintained or improved over the next twenty years and
that the underlying risks of a deterioration in reliability are increasing.
In response, the distributors stated it was unreasonable to expect a sign off based on a 20 year
horizon. CitiPower and Powercor considered that directors simply would not have a view in
relation to such a long time frame, and SP AusNet noted that such a statement would require
material caveats so extensive that the sign-off would become meaningless. Stakeholders were
also confused by the negative assurance that was sought.
The Commission notes these concerns and also notes that, as part of their financial statements,
UK water companies are required to submit a certificate signed by the directors stating that the
company has sufficient financial resources and facilities, management resources and systems of
planning and control to comply with its investment program. However, such a certification is
based on a shorter period than the 20 year period proposed by the Commission.
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In its Draft Decision, the Commission therefore modified its proposed requirement based on a
shorter timeframe, and clarified what it meant by an increasing underlying risk of a deterioration
in reliability. Thus, in its Draft Decision, the Commission proposed to require the distributors’
directors to sign off on an annual basis that the distributors’ plans and processes will, for at least
the next twelve months, ensure that the reliability of the network will meet or exceed the targeted
reliability levels and that the underlying risks of a deterioration in reliability (that is, the
probability of an interruption) are not materially increasing.
Additionally, the Commission proposed that at any time a distributor’s directors became aware
that the underlying risks of a deterioration in reliability (that is, the probability of an interruption)
are materially increasing, they must advise the Commission accordingly.
Distributors were of the view that the requirement to meet or exceed reliability targets was
unreasonable because variability about average performance means that out performance of
targets cannot be assured in every year. Additionally, CitiPower (2005s, p. 11) stated:
Should ESC decide to proceed with the sign-off arrangement, prudent directors would
increase the scope of audit and compliance programs to provide assurances to them prior
to these sign-offs. The ESC should allow further operational costs of at least $100,000 in
its Final Decision to allow distribution businesses to fund such programs.
The Commission notes these issues arise from the wording relating to achieving a certain level of
reliability performance and has therefore decided that the sign-off should adopt the same
wording in (and therefore refer to the existing obligations of the distributors under) the
Electricity Distribution Code.
In summary, the Commission requires that, when submitting the regulatory accounting
statements for the distributor, the distributor’s directors must also confirm in writing that the
distributor will, for at least the next twelve months, have available to it the financial resources
and facilities and management resources required to meet its obligations under the Electricity
Distribution Code to:
•
meet reasonable customer expectations of reliability of supply; and
•
use best endeavours to meet or exceed the targeted reliability levels required by the Price
Determination;
and that the underlying risks of a deterioration in reliability (that is, an increase in the probability
of an interruption) are not materially increasing.
At any time a distributor’s directors become aware that the underlying risks of a deterioration in
reliability (that is, an increase in the probability of an interruption) are materially increasing, they
must advise the Commission.
Distribution losses
The Commission has also been concerned about distribution losses. Distribution losses consist of
electrical losses, metering errors and theft. Distribution Loss Factors (DLFs) are used in the
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National Electricity Market to assign a share of distribution losses to each connected customer.
Concerns in relation to the DLF are in regard to:
•
the loss levels; and
•
the accuracy with which the DLF is estimated.
In relation to loss levels, distributors currently have an obligation under the Electricity
Distribution Code to consider the cost of distribution losses in identifying the least cost options
for network augmentations. The Commission notes that there is a trade off between utilisation
and losses — as assets are driven harder and asset utilisation improves, losses will increase.
In its Position Paper, the Commission therefore proposed that the distributors provide a specific
statement in each of their annual Distribution System Planning Reports and Transmission
Connection Planning Reports that the cost of distribution losses was considered in identifying the
least cost options for network augmentations.
The Commission considered the inclusion of a loss incentive mechanism, similar to that
proposed in the UK and Ireland. Under such a scheme, the distributor would have an incentive to
maintain losses at the target level. Additionally, if the actual losses are higher or lower than the
DLF target, the distributor would be penalised.
Whilst AGLE and SP AusNet initially supported an incentive regime on DLF in principle,
distributors opposed the proposed scheme. They identified a range of issues, including:
•
a nationally accepted approach to estimating DLF is not yet agreed;
•
the efficient level of losses should be revealed through the incentive mechanism;
•
the UK scheme is an incentive on actual losses rather than an incentive on ex-ante loss
estimates and therefore should be not be transposed directly; and
•
distributors should not be penalised on the difference between actual and target as the
actual losses are largely outside the control of the distributor.
PB Power reported to the Commission on the loss levels of other countries in 2000 (PB Power
2000b). Based on the findings of this report, the Commission considers that the economic levels
of distribution losses for Victorian distributors should be in the range of 3 to 5 per cent of sales
for urban-based networks and could be as high as 10 per cent of sales for distributors with
predominantly rural networks. The Commission notes that distribution loss levels in Victoria are
consistent with the information provided by PB Power about distribution losses levels in other
countries with similar network characteristics.
The Commission therefore considers there is no evidence that distribution loss factors are at
inappropriate levels, and so has not set targets for distribution losses for the 2006-10 regulatory
period.
With regard to the accuracy with which the DLF is estimated, the National Electricity Market is
currently settled on the basis of the forecast DLF. The local retailer bears the risk associated with
any error in the DLF forecast. The risk to the local retailer increases when customers transfer
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away from it. Hence, the risk is small at the early stages of competition in the retail energy
market but increases as the market becomes more competitive.
Retailers (AGL ES&M and Origin Energy) supported an incentive for the distributors to
accurately forecast DLFs, as it would decrease the risk faced by local retailers. Origin Energy
suggested consideration of the equivalent loss incentive scheme in the gas industry. EUCV
(2005b, p. 57) supported such a mechanism on the basis that accurate forecasting of losses is an
essential step in identifying the optimal solution to the level of losses.
AGLE (2005b) and SP AusNet (2005b, p. 19) strongly opposed the loss incentive mechanism.
They stated that the risk under the scheme is asymmetric and that this extra risk needed to be
provided for through the weighted average cost of capital or cash flows.
United Energy (2005c, p. 49) considered it unlikely that distributors would systematically
underestimate or overestimate DLFs year after year. Similarly SP AusNet stated that, if the
forecast inaccuracy is symmetric over time, the host retailer is not disadvantaged.
United Energy (2005c, p. 49) was also concerned that methodologies for forecasting DLFs not be
constrained by the Commission if penalties apply and that a reward should exist to encourage
distributors to invest to improve DLF forecasting. Further, SP AusNet (2005c, p. 3) was
concerned that the proposed mechanism may create incentives to ensure investment decisions do
not change actual losses from those forecast or even to avoid investment decisions, which would
lead to a loss reduction, being taken before the DLFs can be re-forecast.
Distributors also commented that any variance between actual and forecast losses is largely
driven by exogenous factors rather than factors within the distributors’ control.
The Commission notes that the actual variances between the distributors’ forecast DLFs and
actual DLFs have been immaterial over the last few years. There has only been one distributor
who has had a material variance between its forecast and actual DLF and that issue was
discovered and corrected through the processes set out in the National Electricity Rules. The
Commission therefore considers that there is no evidence to suggest that the reconciliation
between actual losses and forecast losses as required by the National Electricity Rules is not
sufficient to ensure distributors make accurate forecasts of losses.
Taking all of these considerations into account, the Commission has accordingly decided not to
introduce a loss incentive mechanism.
However, the Commission does require a specific statement in each of the distributors’ annual
Distribution System Planning Reports and Transmission Connection Planning Reports that the
cost of distribution losses has been considered in identifying the least cost options for network
augmentations. Further, during the annual approval process, the Commission will continue to
monitor the levels of distribution losses to ensure that they remain within an appropriate range,
and to assess the reconciliation between actual losses and forecast losses as required by the
National Electricity Rules.
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3.2.4 Exclusion criteria
An important feature of the existing service incentive arrangements is the ability of the
distributors, with the approval of the Commission, to have the impact of certain events excluded
from the calculation of the S-factor and from the requirement to make certain GSL payments.
The distributors can currently apply to have the impacts of the following events excluded:
•
supply interruptions made at the request of the distribution customer affected;
•
load shedding due to a shortfall in generation;
•
supply interruptions caused by a failure of the shared transmission network;
•
supply interruptions caused by a failure of transmission connection assets, to the extent that
the interruptions were not due to inadequate planning of transmission connections; and
•
widespread supply interruptions due to rare events, which were not reasonably able to be
foreseen and, to the extent that the distributor was not reasonably able to mitigate their
impact.
In its Final Framework and Approach, the Commission proposed to continue to allow
interruptions caused by transmission and generation to be excluded from the calculation of the
financial incentives, with the exception of load shedding due to a shortfall in embedded
generation.
Widespread supply interruptions due to rare events
The Commission noted that the criteria for the qualitative exclusion (that is, the widespread, rare
and unforeseeable exclusion) were somewhat broad and that there remained a level of
subjectivity in their application. The Commission’s preferred approach was to continue to
exclude abnormal events, including force majeure events, but add clear quantitative criteria to
facilitate the assessment of these events and to limit the distributors’ risk exposures. The
Commission also proposed to exclude all events, not just those outside the control of the
distributor, but to set the quantitative criterion sufficiently high to limit the events to those that
are abnormal. This recognises that the existing scheme is administratively complex and costly for
distributors and the Commission.
The distributors generally supported a quantitative exclusion criterion rather than the existing
qualitative criterion for widespread, rare and unforeseeable events. However, EUCV (2005b,
p. 38) submitted that:
Rare events have the same impact on consumers as frequent events and so should not be
excluded.
Origin Energy (2005a, p. 11) also noted that:
… the main criteria should be to hold the distributors accountable for events that were
within their control or direct influence or can be better managed (in terms, say, of time of
interruption) with the appropriate balance of approved capital and operating expenditure.
While it may be pragmatic to exclude events based on a statistical outlier analysis, it does
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not follow that just because an event is extreme that it is also outside a distributor’s
control.
Whilst AGLE, CitiPower, Powercor and SP AusNet proposed a quantitative criterion based on
SAIDI, United Energy (2004c, p. 46) was of the view that a criterion based on SAIDI could
wrongly exclude poor fault response times. It proposed that the criterion be based on the
proportion of customers affected or the proportion of customers off supply for 1 hour.
SP AusNet proposed a more statistical approach, adopted by Ofgem as part of its recent price
review for the UK distributors. SP AusNet proposed to calculate the mean and standard deviation
of the daily unplanned SAIDI, exclude any day where unplanned SAIDI is greater than
4 standard deviations from mean unplanned SAIDI, and replace all reliability measures for the
excluded day with the mean result for each measure. The Commission notes, however, that the
Ofgem scheme is based on SAIFI for severe weather events (Ofgem 2004a, p. 21)
or SAIDI, but includes a qualitative assessment that the distributor must have taken all
appropriate steps to prevent the event and to mitigate the impact.
In its Position Paper, the Commission proposed to base its quantitative criterion on SAIFI.
However, SP AusNet (2005f, p. 20), CitiPower (2005b, p. 11) and Powercor (2005b, p. 11)
proposed that daily SAIDI not SAIFI should be the trigger as SAIFI does not follow a lognormal
distribution and therefore the application of a statistical approach may not be appropriate. In
addition, SP AusNet (2005b, p. 20) claimed that with SAIDI, outages of lengthy duration but low
frequency are excluded, and CitiPower and Powercor noted that SAIDI included both numbers of
customers affected and duration.
Distributors also noted that national reporting requirements agreed by the Utility Regulators
Forum are based on excluding events using a SAIDI threshold. As a member of the forum, the
Commission accepted this exclusion threshold, but notes the exclusion is for a different purpose
— comparing reliability performance on a nationally consistent basis. National reporting
requirements also require that the excluded events be itemised so that users of the information
can assess the relevance when making performance comparisons.
The Commission considers that the quantitative exclusion criterion should be based on SAIFI
rather than SAIDI. As pointed out by United Energy, a criterion based on SAIDI could wrongly
exclude events where there was a poor response time. In the Commission’s view, SAIFI, rather
than SAIDI, is a better indicator that a large number of events have occurred which will stretch
the distributors’ resources to restore supply. Additionally, it is consistent with Ofgem’s approach
for severe weather events.
Having decided that the qualitative exclusion criterion will be based on SAIFI, the exclusion
criterion must be quantified. The principle applied by the Commission in quantifying all
exclusion criterion is that it should exclude outlier events. Prior to the Draft Decision, the
Commission considered:
•
using a lognormal distribution of the distributors’ daily SAIFI data over the
2000-04 period, with a threshold that was 2.7 standard deviations from the mean; and
•
the impact of the February 2005 storms.
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The distributors were concerned that thresholds set on the basis proposed by the Commission
were too high and were inconsistent in application. CitiPower and Powercor proposed that the
thresholds should be set by considering the number of customers affected — 25,000 customer
interruptions or 2 million customer minutes,45 with the exclusion proposed in the Draft Decision
being equivalent to 90,000 customer interruptions for Powercor. AGLE proposed that the
modified scheme should provide a similar level of exclusions as the current scheme. United
Energy proposed that the exclusion should be based on a 2.5 beta SAIDI methodology.
Powercor noted that there have been no days in the last five years that would have triggered its
threshold, proposed in the Draft Decision, whereas seven days were approved by the
Commission for exclusion from the calculation of the S-factor in the 2001-05 period . However,
the Commission notes that of these exclusions, five related to a single pole fire event that
occurred over a period of months; one related to storms over Melbourne where the impact of the
event on other distributors was the prime consideration; and one related to localised damage due
to a tornado. In all of these events, the SAIFI impact on Powercor’s network was small. While
these events met the exclusion criterion that applied to them at that time, they are not
significantly different from other events that did not meet the exclusion criterion.
The Commission considers that the quantitative exclusion criterion is unlikely to result in the
same outcomes as the criterion that applies to the 2001-05 regulatory period due to the different
basis of the criterion.
In assessing the risk of the new S-factor scheme, Mercer developed a complex distribution
function to model the daily SAIFI for each distributor over the 2000-04 period. Subsequent to the
Draft Decision, the Commission engaged Mercer to assist it to quantify the exclusion criterion by
determining the daily SAIFI for a one-in-five year event and a two-in-five year event using the
distribution function for each distributor. Mercer’s reports (2005f to 2005j) are published on the
Commission’s website.
Mercer’s analysis indicated that CitiPower and SP AusNet had experienced outlier events during
the 2000-04 period, whilst AGLE, Powercor and United Energy did not. The location of the
Powercor and United Energy distribution areas is such that these distributors do not generally
experience storms that impact a large proportion of their customers.
Therefore, a one-in-five year event and a two-in-five year event based on the distribution
function of the 2000-04 daily SAIFI data is likely to understate an appropriate exclusion criterion
for AGLE, Powercor and United Energy and may over-state it for CitiPower and SP AusNet.
The results of the Commission’s analysis based on a lognormal distribution of daily SAIFI, the
impact of the storms on 3 February 2005 and a one-in-five event using the distribution function
to model the daily SAIFI during the 2000-04 period, are provided in Table 3.11. The
Commission has exercised its judgement to quantify the exclusion criterion (or threshold) using
this information. For those distributors that have not experienced an outlier event during 2000-04
(AGLE, Powercor and United Energy), the threshold is set above the SAIFI corresponding to a
45
The Commission notes that Ofgem use these thresholds for certain events such as transmission-related events, but not for
severe weather events.
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one-in-five year event. For CitiPower and SP AusNet, the threshold is based on the lognormal
distribution consistent with the Draft Decision.
Table 3.11:
Daily unplanned interruption frequency threshold, by distributor
Lognormal
distribution
Storms on 3
February 2005
Mercer – 1-in-5
year event
Final Decision
Threshold
AGLE
0.243
0.139
0.109
a
0.120
CitiPower
0.066
0.135
0.154
0.066
a
0.110
Powercor
0.140
0.056
0.098
SP AusNet
0.190
0.430
0.208
0.190
United Energy
0.337
0.163
0.085
a
0.100
a
Given that AGLE, Powercor and United Energy did not experience any outlier events during the 2000-04 period, a one-in-five year event based
on this period will understate an appropriate exclusion criterion.
When the SAIFI for a particular day exceeds the threshold, that day’s reliability data will be
substituted with the mean annual reliability data for the purposes of the S-factor scheme and
GSL payments scheme. The call centre performance data for that day will be excluded from the
calculation of the S-factor.
In its Draft Decision, the Commission set out the mean daily unplanned interruption duration and
frequency based on daily data provided by the distributors for 2000 to 2004 which was to be
substituted on an excluded day. The data provided by AGLE was incorrect at that time as it
included both planned and unplanned interruptions. The mean daily unplanned interruption
duration and frequency has subsequently been recalculated and the revised data is set out in
Table 3.6.
The Commission also notes that the exclusion criterion would apply to all events, not just those
outside the distributors’ control as is the intent of the exclusion criteria that apply in the current
period.
EUCV (2005b, p. 58) did not support such an approach as it is not:
…in keeping with the expectation that the DBs should be penalized for not performing
their tasks correctly.
However, to do otherwise would re-introduce a subjective element and may incentivise a
distributor to “gold plate” its network, with consequential inefficient funding requirements, to
ensure no major events would occur which could be considered to be within its control.
The quantitative criterion for widespread and rare events will apply to events that occur from
1 January 2006. The criterion set out in the 2001-05 Volume II — Price Controls will continue to
apply in the calculation of the S-factors in 2006 and 2007, based on events in 2004 and 2005.
Accordingly, distributors will be able to apply to have the impacts of the following events
excluded from the calculation of the S-factor and from the requirement to make certain GSL
payments:
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•
for the S-factor scheme calculated in the years 2006 and 200746, widespread supply
interruptions due to rare events, which were not reasonably able to be foreseen, to the
extent that the distributor was not reasonably able to mitigate their impact; and
•
for the GSL payments scheme for 2006, and for the S-factor scheme calculated from
200847, supply interruptions on a day where the unplanned interruption frequency exceeds
the threshold as set out in Table 3.6. On these days, the mean frequency and duration of
interruptions, as set out in Table 3.6, must be substituted for that day’s actual frequency
and duration of interruptions. On these days, when calculating the call centre performance
measure of the S-factor scheme, the call centre performance data for that day is excluded.
Shortfall in embedded generation or demand side response initiatives
In its Final Framework and Approach, the Commission proposed that the impact of supply
interruptions due to a shortfall in embedded generation should not be excluded from the service
incentive mechanism. By exempting these supply interruptions, reliability to customers could
worsen without the distributor or generator being held accountable.
The Commission was of the view that distributors should be accountable for delivering targeted
reliability, including when seeking to address required network augmentations by entering into
network support agreements with generators. Customers’ reliability should not be negatively
affected by how the distributor chooses to augment its network.
AGLE and United Energy did not support that these supply interruptions could not be excluded
from the service incentive scheme. United Energy (2004e, p. 46) indicated that the penalty
associated with the S-factor scheme is too great for embedded generation to be commercially
viable. United Energy considered this to be inconsistent with the Commission’s encouragement
for distributors to consider embedded generation as an alternative to traditional network
solutions.
Whilst the distributors and demand side response proponents supported the exclusion of supply
interruptions due to a shortfall in embedded generation, other stakeholders did not. EUCV did
not believe that a lack of embedded generation should be an excuse for failure to deliver service.
Origin Energy was of the view that the distributor should be held accountable for its procurement
decision and its ongoing management of the arrangement with the embedded generator.
The Commission continues to be of the view that supply interruptions due to a shortfall in
embedded generation should not be excluded. The distributors should continue to be held
accountable for delivering the targeted levels of reliability, including when seeking to address
required network augmentations by entering into network support agreements with generators.
Customers’ reliability should not be affected by how the distributor chooses to provide
distribution services.
However, following discussions with demand side response proponents and distributors, the
Commission better understands the tension between trialling demand side response initiatives
46
47
Based on actual performance prior to 2006
Based on actual performance from 2006
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and the operation of the service incentive mechanisms. The Commission also understands the
importance of demand side initiatives to reduce peak demand which will in turn reduce
expenditure required to provide the capacity for these peak demands for a relatively short period
each year.
Therefore, for a trial period only, an exclusion criterion for embedded generation or other
demand side initiatives has been included. The Commission will require approval to be provided
by it prior to the commencement of the period during which load shedding due to a shortfall in
embedded generation or other demand side initiative is to be excluded from the service incentive
mechanisms. When seeking approval, the proponent must demonstrate that customers likely to
be impacted have been appropriately identified and have agreed to an exclusion over a defined
period.
The Commission may provide initial approval for a three month or longer period as agreed by
the Commission and a distributor is required to apply for an exclusion on each occasion an event
occurs. This period may be extended to a maximum of three years where customers have agreed
to a longer period and subject to the administrative burden placed on the Commission and
distributors during the initial three month period. That is, if the exclusion does not place an
administrative burden on the Commission or the distributor the trial will be extended, but if the
exclusion places an administrative burden on the Commission or the distributor, the trial period
will not be extended.
Therefore, the exclusion criterion enables distributors to apply to have the impacts of the
following events excluded from the calculation of the S-factor and from the requirement to make
certain GSL payments:
•
load shedding due to a shortfall in generation, but not a shortfall in embedded generation
that has been contracted to provide network support, except where prior approval has been
obtained from the Commission; and
•
where prior approval has been obtained from the Commission, load shedding due to a
shortfall from demand side response initiatives.
These exclusion criteria apply to the calculation of the S-factor scheme for the reliability
measures from 2008 (based on the performance from 2006) and to the GSL payments scheme
from 2006.
Additional exclusion criteria
Distributors proposed a number of additional exclusion criteria in their original price-service
proposals:
•
failure of national carrier (priority 13 phone services);
•
inability to access Melbourne (CitiPower) or Bendigo (Powercor) contact centre building;
•
state of emergency;
•
supply interruptions caused by a failure of inter distributor services;
•
industrial relations force majeure; and
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•
terrorist activity.
In relation to these, CitiPower (2005b, p. 43) and Powercor (2005b, p. 43) agreed that:
… the failure of the national telephone carrier, failure of inter-distributor services and
inability to access a call centre can be influenced by commercial arrangements with
suppliers. The alternative proposal that these events are not excluded is acceptable
provided that adequate consideration is given in setting the allowable revenue and service
targets.
United Energy supported all these exclusion criteria whilst SP AusNet supported all of them,
with the exception of the inability to access contact centre control buildings. EUCV and Origin
Energy did not support these exclusion criteria.
The Commission considers that setting exclusion criteria for industrial relations force majeure
and terrorist activity is problematic. For instance, how is vandalism separated from terrorist
activity? The Commission notes that where such events have a large impact, they would be
excluded under the quantitative exclusion criterion for widespread and rare events.
Given the comments from stakeholders and given the need to avoid administrative complexity in
the scheme, the Commission has not adopted the additional exclusion criteria proposed by
distributors. The Commission is of the view that the targeted levels have been set considering all
data and not data that excludes these events. To do so would remove the incentive for the
distributors to mitigate their risks through commercial agreements with suppliers.
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ATTACHMENT: ANNUAL HEALTH CARD
Measure
Green lighta
Orange lighta
Red lighta
Reliability
Equal or better than targeted level of
reliability for unplanned SAIFI and
unplanned SAIDI
Worse than targeted level of reliability for
unplanned SAIFI or unplanned SAIDI during the
year
Worse than targeted level of reliability for
unplanned SAIFI or unplanned SAIDI during
the last two years
Voltage quality
Decreasing or flat trend in the total number
of voltage variations (steady state, 1 minute
and 10 seconds) over the five year period, or
part thereof where records are available (flat
trend represents a less than 5 per cent
increase in the number of voltage variations
over the period)
or voltage quality improvement projects
implemented as forecast
Increasing trend in the total number of voltage
variations (steady state, 1 minute and 10 seconds)
over the five year period, or part thereof where
records are available (increasing trend represents a
5 per cent or more, but less than 50 per cent,
increase in the number of voltage variations over
the period)
or more than 20 per cent but less than 50 per cent
of cumulative forecast voltage quality
improvement projects not implemented
Increasing trend in the total number of voltage
variations (steady state, 1 minute and 10
seconds) over the five year period, or part
thereof where records are available (increasing
trend represents a 50 per cent or more increase
in the number of voltage variations over the
period)
or 50 per cent or more of cumulative forecast
voltage quality improvement projects not
implemented
Planning
Decreasing or flat trend, over a 5 year
period or part thereof, in the annual load at
risk due to late completion of projects which
were planned by the distributor to provide
capacity to meet the expected maximum
demand in winter or summer (flat trend
represents a less than 5 per cent increase in
the annual load at risk)
Increasing trend, over a 5 year period or part
thereof, in the annual load at risk due to late
completion of projects which were planned by the
distributor to provide capacity to meet the expected
maximum demand in winter or summer (increasing
trend represents a 5 per cent or more, but less than
50 per cent, increase in the annual load at risk)
Increasing trend, over a 5 year period or part
thereof, in the annual load at risk due to late
completion of projects which were planned by
the distributor to provide capacity to meet the
expected maximum demand in winter or
summer (increasing trend represents a 50 per
cent or more increase in the annual load at risk)
Service orders
Based on the B2B report card completed by
the distributors and retailers – to be
developed after B2B report card developed
Based on the B2B report card completed by the
distributors and retailers – to be developed after
B2B report card developed
Based on the B2B report card completed by the
distributors and retailers – to be developed after
B2B report card developed
Complaints
Number of complaints referred to EWOV
no greater than 1.5 times the average annual
number of complaints referred during the
period 2002-2004
Number of complaints referred to EWOV greater
than 1.5 times but no greater than 2 times the
average annual number of complaints referred
during the period 2002-2004
or number of complaints referred to EWOV equal
to or greater than 0.20 per 1,000 customers and
less than 0.30 per 1,000 customers
Number of complaints referred to EWOV
greater than 2 times the average annual number
of complaints referred during the period 20022004
or number of complaints referred to EWOV
equal to or greater than 0.30 per 1,000 customers
A direction issued under section 141 of Electricity
Safety Act is outstanding for more than 3 months
A direction issued under section 141 of
Electricity Safety Act is outstanding for more
and number of complaints referred to
EWOV less than 0.20 per 1,000 customers
Safety regulations
No directions issued under section 141 of
Electricity Safety Act are outstanding for
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Measure
Green lighta
more than 3 months during the year
Orange lighta
but no more than 9 months during the year
Red lighta
than 9 months during the year
Bushfire mitigation plan
No work outstanding at the start of the
bushfire season
One of the seven categories of work reported on is
not completed at the start of the bushfire season
More than one of the seven categories of work
reported on is not completed at the start of the
bushfire season
Regulatory auditsb
Score of more than 75 per cent for audit,
based on level of non-compliance reported
and the likely impact of that noncompliance
Score of more than 50 per cent, but 75 per cent or
less, for audit, based on level of non-compliance
reported and the likely impact of that noncompliance
Score of 50 per cent or less for audit, based on
level of non-compliance reported and the likely
impact of that non-compliance
Safety audits (if
undertaken)
No significant areas of non-compliance as
determined by Energy Safe Victoria
Of the areas audited, one significant area of noncompliance as determined by Energy Safe Victoria
Of the areas audited, more than one significant
area of non-compliance as determined by
Energy Safe Victoria
Environmental (EPA)
No infringement notices for environmental
regulations during the year
One infringement notice for environmental
regulations during the year
Two or more infringement notices for
environmental regulations during the year
Excluded service charges
No occasions where excluded service
charges are revised by the distributor
following contact by the customer with the
Commission
No more than five occasions where excluded
service charges are revised by the distributor
following contact by the customer with the
Commission
More than five occasions where excluded
service charges are revised by the distributor
following contact by the customer with the
Commission
Electrical Incidents
relating to a distributor’s
distribution system
Number of incidents reported to ESV is less
than 1.25 times the number of incidents
reported in the previous year
and number of incidents reported to ESV is
less than 0.5 per 1,000 customers
Number of incidents reported to ESV is equal to or
greater than 1.25 times but less than 1.5 times the
number of incidents reported in the previous year
or number of incidents reported to ESV is equal to
or greater than 0.5 per 1,000 customers and less
than 1.0 per 1,000 customers
Number of incidents reported to ESV is equal to
or greater than 1.5 times the number of incidents
reported in the previous year
or number of incidents reported to ESV is equal
to or greater than 1.0 per 1,000 customers
Green light (only)
Quality systems
certification (AS9000
series)
Distribution business and/or its related party (where that related party undertakes a significant proportion of the distribution business’s obligations
under its licence) certified with no major non compliances from most recent audit
Environmental systems
certification (AS 14000)
Distribution business and/or its related party (where that related party undertakes a significant proportion of the distribution business’s obligations
under its licence) certified with no major non compliances from most recent audit
a
The Commission may use its discretion to improve a rating from orange to green or red to orange, but may not move a rating from green to orange or orange to red. The “health
card” will include a comments column which will explain the reasons for an orange light or a red light, and where the rating has been improved at the discretion of the Commission,
will provide the rationale for this improvement. b Each compliance item is to be rated on a scale of 1 to 5 for compliance and a scale of 1 to 5 for the impact of non-compliance. Score
for each compliance item is the product of the compliance rating and the impact rating.
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4 GROWTH FORECASTS
Energy consumption, peak energy demand and customer numbers are important inputs into the
derivation of the new price controls. Future expenditure requirements are driven partly by
expected growth in peak demand and customer numbers while the translation of the revenue
requirement into a cap on distribution prices relies on forecasts of energy consumption, customer
numbers and contract demand.
The distributors have an incentive to understate the prospects for future growth since out-turn
growth above that forecast will result in higher revenue than anticipated in setting prices. Over
the current regulatory period, the distributors earned higher than expected revenues partly as a
result of higher than forecast growth in energy consumption and customer numbers.
The Commission has therefore undertaken an assessment of the distributors’ proposed growth
forecasts so as to ensure that prices reflect a best estimate of those necessary to deliver the
distributors’ revenue requirements.
This Chapter sets out the Final Decision on the growth forecasts that have been used to
determine the distributors’ revenue requirements and price controls, and the reasons for that
decision.
4.1 Final Decision
The Final Decision in relation to energy consumption, customer numbers and peak demand is set
out in Tables 4.1, 4.2 and 4.3. These forecasts use National Institute of Economic and Industry
Research’s (NIEIR’s) alternative base case growth scenario as revised by NIEIR in August 2005.
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Table 4.1:
Energy consumption forecasts by distributor (GWh), including compound
annual growth rate, 2004-10
AGLE
CitiPower
Powercor
SP AusNet
a
United
a
2005
2006
2007
2008
2009
2010
2004-10
growth rate
(per cent)
Residential
1,156
1,169
1,191
1,211
1,228
1,248
1.45
Non-residential
3,028
3,044
3,073
3,091
3,098
3,109
0.49
Residential
1,212
1,237
1,271
1,310
1,342
1,367
2.21
Non-residential
4,433
4,465
4,532
4,590
4,618
4,647
0.83
Residential
3,271
3,308
3,355
3,415
3,462
3,500
1.40
Non-residential
6,551
6,716
6,873
7,004
7,143
7,304
2.14
Residential
3,094
3,165
3,251
3,326
3,390
3,472
2.58
Non-residential
4,086
4,209
4,337
4,459
4,577
4,701
2.70
Residential
2,790
2,814
2,863
2,906
2,936
2,972
0.81
Non-residential
4,755
4,851
4,954
5,037
5,109
5,189
1.70
Formerly TXU
Table 4.2:
Total customer number forecasts by distributor, including compound annual
growth rate, 2004-10
2005
2006
2007
2008
2009
2010
2004-10
growth rate
(per cent)
Residential
256,649
260,822
265,156
269,170
273,260
277,641
1.70
Nonresidential
29,771
30,245
30,763
31,276
31,752
32,234
2.22
Residential
234,712
238,469
244,194
248,749
252,331
255,603
1.65
Nonresidential
46,693
46,786
47,089
47,116
47,142
47,174
0.48
Residential
538,254
547,727
557,949
568,808
578,908
588,422
1.77
Nonresidential
101,129
102,140
103,116
103,959
104,761
105,610
0.91
Residential
496,855
506,184
515,781
526,000
536,312
547,005
1.56
Nonresidential
70,780
71,844
72,603
73,514
74,385
75,253
0.90
United
Residential
548,414
553,894
559,974
566,286
571,934
577,245
1.06
Energy
Nonresidential
61,425
66,342
66,607
67,426
68,132
68,867
2.15
AGLE
CitiPower
Powercor
SP
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Table 4.3:
Peak demand (non coincident) forecasts at the zone substation level by
distributor (MVA), including compound annual growth rate, 2005-10
2005
2006
2007
2008
2009
2010
2005-10 growth rate
(per cent)
AGLE
1,106
1,151
1,193
1,224
1,254
1,285
3.05
CitiPower
1,699
1,732
1,758
1,794
1,833
1,874
1.98
Powercor
2,394
2,477
2,481
2,508
2,559
2,610
1.74
SP AusNet
1,777
1,846
1,922
1,987
2,050
2,120
3.58
United Energy
2,392
2,471
2,550
2,617
2,682
2,754
2.86
4.2 Reasons for the Decision
In preparing their October 2004 price-service proposals, each distributor commissioned NIEIR to
develop four sets of growth forecasts. These scenarios were referred to as a base case, an
alternative base case, a high case and a low case.
The NIEIR reports provided the key factors underlying the projections for the base scenario.
However, the information provided on the high and low scenario was limited to a high level
qualitative description and the variation in forecast GSP for each scenario.
The base and alternative base cases had the same economic and non-economic assumptions
underlying them, except that the base case factored in a downside risk to manufacturing that
resulted in slower growth rates in energy consumption than forecast by the alternative base case.
NIEIR considered that it was appropriate to include a downside risk to manufacturing in the base
case due to a combination of higher land prices and falling rates of return on the capital stock
invested in Victorian manufacturing creating an incentive for manufacturing production to shut
down and sell land and seeing the industry relocate operations to Asia and China in particular.
The base and alternative base case scenarios factored in a slowing in the rate of growth in energy
consumption over the period. The historic and forecast growth rates for energy consumption for
both scenarios are set out in Table 4.4.
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Table 4.4:
Electricity consumption growth rates (per cent per annum), 2000-04 historic,
alternative base case forecasts and base case forecasts (pre-Draft Decision)
Alternative base
case
Base case
2000-04
2004-10
2004-10
AGLE
0.75
0.88
0.37
CitiPower
1.95
0.82
0.62
Powercor
2.05
2.15
1.61
SP AusNet
2.90
2.65
2.42
United Energy
1.89
1.61
1.15
Note: 2000-04 historic growth rates based upon historic data made available through the annual tariff approval process, the distributors’ audited
regulatory accounts and the Comparative Performance Reports. 2004-10 forecast growth rates are based on the NIEIR forecasts prepared in
September 2004.
Following the receipt of the distributors’ proposals in October 2004, the Commission engaged
MMA to review the distributors’ forecasts. MMA reviewed the distributors’ forecasts, NIEIR
forecasts and supporting information set out in the NIEIR reports and historic information, and
reached the following conclusions:
•
While MMA considered the NIEIR customer number forecasts a reasonable basis for the
distributor’s forecasts, it noted that none of the distributors had translated NIEIR forecasts
directly into its own forecasts.
•
MMA had reservations about the methodology and quantification of the downside risk to
manufacturing and Victorian Government 5-star standard.
•
NIEIR’s energy consumption forecasts prepared for the distributors appeared inconsistent
with those it had prepared for VENCorp in June 2004 (MMA 2005, pp. i-xii)
The Commission had some reservations over MMA’s findings. While MMA noted concerns
over some of the methodology and quantifications that NIEIR had used, it was not always clear
what information or considerations MMA had relied on to make its judgement. For example,
MMA stated that NIEIR’s economic assumptions appeared reasonably consistent with those of
other economic forecasters and Governments and with the NIEIR forecasts used for VENCorp.
However, it was not clear what other economic forecasters and Governments MMA had relied
on to make this conclusion nor did they provide a comparison of the estimates.
MMA also developed its own forecasts to assess the reasonableness of the distributors’ forecasts.
However, the forecasting techniques used by MMA were reasonably simplistic (employing
simple regression methods based on a small set of historic data) when compared to the integrated
model that it was understood NIEIR used. Due to these concerns, the Commission was not
confident about placing a significant amount of weight on the forecasts that MMA prepared.
As a result, the Commission undertook its own analysis of the distributors’ forecasts and the
methodology and assumptions used by NIEIR. To inform this analysis, the NIEIR reports
submitted in support of the NIEIR forecasts were reviewed, the consistency of the distributors’
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forecasts with the forecasts set out by NIEIR in these reports was assessed and both NIEIR’s and
the distributors’ forecasts (where these differed) were compared with the historic data that were
available.
This analysis confirmed that the forecasts provided by the distributors to the Commission were
not always consistent with the forecasts prepared by NIEIR. Some distributors had different
numbers, some distributors had different growth rates and others had both different numbers and
different growth rates.
Some distributors also revised their forecasts prior to the Draft Decision, which only increased
the inconsistencies with NIEIR’s forecasts.
As noted in the Draft Decision, CitiPower and Powercor submitted revised customer numbers
due to an assumption of an increase in the number of embedded networks in their areas. While
CitiPower and Powercor provided a verification letter from NIEIR, it was not clear that NIEIR
was asked to verify the methodology and assumptions that CitiPower and Powercor used to
derive their estimates of the proportions of their customers that would change to an embedded
network tariff. Rather, it appeared that NIEIR was only asked to verify the methodology that
CitiPower and Powercor applied to adjust their customer number and energy forecasts.
The Commission did not allow any adjustments for embedded networks because the regulatory
framework provides sufficient flexibility for the distributors to respond to competitive pressures
by allowing them to rebalance their tariffs so that customers do not bypass the network (ESC
2005c, p. 138). CitiPower and Powercor did not comment on this issue in response to the Draft
Decision and thus the Commission has not provided for any adjustments due to embedded
networks in its Final Decision.
On reviewing the reasons given for forecast lower growth over the next regulatory period, the
Commission could not find information that corroborated those reasons. In particular, the
Commission could not find evidence or information that supported an assumption of a downside
risk to manufacturing. As a result, the Commission was of the view that the forecasts produced
under the base case scenario (which incorporated the downside risk to manufacturing) were not a
fair representation of likely growth over the next regulatory period.
The Commission also noted that the forecasts of Victorian GSP under NIEIR’s high case
scenario were consistent with those published in the Victorian State Budget Papers. The State
Budget Papers indicated that, over the 2006-10 period, Victorian GSP was expected to grow by,
on average, 3.3 per cent per year. This was consistent with the rate of GSP growth assumed in
the high case growth scenario (on average, 3.3 per cent), and contrasted with the GSP forecast
(2.6 per cent) underlying the alternative base case scenario.
As a result, the Commission in its Draft Decision considered that NIEIR’s high case growth
scenario would better reflect the most likely growth outcomes for the 2006-10 regulatory period
than the alternative base case scenario. The high case scenario resulted in customer number and
energy consumption growth over the 2005-10 period of 1.83 per cent and 2.58 per cent
(unadjusted for elasticity effects) respectively.
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Following the Draft Decision, the distributors (CitiPower & Powercor 2005a) raised several
issues with the use of the high case growth scenario, namely, in their view:
•
The reliance on the Department of Treasury and Finance’s (DTF) forecasts was
unreasonable and the prevailing weight of expert opinion supported the NIEIR base case
economic forecasts.
•
NIEIR unequivocally recommended use of the base case and NIEIR’s high case was
optimistic on a range of economic and non-economic variables.
•
Rejection of the manufacturing downside scenario was unreasonable.
•
The forecasts were inconsistent with:
y
VENCorp and NEMMCO’s forecasts;
y
historic growth rates;
y
the use of base case forecasts in the last price review; and
y
the use of the base case forecasts by other Australian regulators.
In response to these concerns, the Commission has undertaken further analysis and review of the
NIEIR forecasts and forecasting methodology as well as the information that the distributors
provided NIEIR to develop the forecasts. This further review has focused on:
•
identifying and reconciling the difference between the historic growth rates calculated by
NIEIR and those calculated by the Commission; and
•
understanding the impact and variance of the different assumptions used in each scenario.
4.2.1 Historic growth rates
When comparing forecasts to historic growth rates, the Commission has relied on the historic
data available to it from the annual tariff approval models, regulatory accounts and Comparative
Performance Reports. Using this information, the Commission calculated that the growth rate in
energy consumption over the 2001 to 2004 period was 2.3 per cent. In contrast, NIEIR calculated
that the growth rate over this period was 1.8 per cent (NIEIR 2005b). Similar discrepancies were
found in the historic customer number data.
This variation prompted the Commission to seek to reconcile the historic data available to the
Commission and that made available to NIEIR. Table 4.5 sets out the 2000-04 growth rates in
energy consumption for each distributor using the Commission’s historic data and that provided
by NIEIR.
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Table 4.5:
Total energy consumption growth rates, 2000-04
Commission historic
NIEIR historic
AGLE
0.75
0.76
CitiPower
1.95
1.59
Powercor
2.05
2.43
SP AusNet
2.90
3.13
United Energy
1.89
1.59
Note: Commission 2000 to 2003 historic data compiled from tariff approval models and 2004 historic data from regulatory accounting
statements. NIEIR historic data compiled from information provided by NIEIR.
NIEIR (2005c) stated that it believed the discrepancies in the data were due to:
•
separation and integration of information systems due to changing industry and
organisational structure (for example full retail competition);
•
reliance on retail billing systems without distinct network billing functionality;
•
real world effects such as weather;48 and
•
differences between accrued positions and underlying positions for distinct periods.
NIEIR’s historic data was provided to it by the distributors. The Commission understands that
this data is derived from the distributors’ (non-weather normalised) customer billing data.
However, NIEIR (2005b) indicated that it did not rely solely on the information provided by the
distributors but tried to reconcile it with weather normalised VENCorp data (adjusted for losses,
transmission customers and embedded generation).
NIEIR (2005c) stated that the Commission should place more weight on the VENCorp data in its
assessment of historic growth rates given the anomalies and inconsistencies that exist between
the data that the Commission has available to it and the data made available to NIEIR.
When making comparisons with the forecasts of energy consumption and customer numbers, the
Commission has relied on the historic data available to it from the annual tariff approval models
and regulatory accounting statements. These are the data that are provided by the distributors for
regulatory purposes, principally to demonstrate their compliance with the price controls
established at the last price review. The growth forecasts used to determine the price and revenue
outcomes set out in this Determination should be consistent with the data provided to ensure
compliance with those outcomes.
48
Energy consumption varies with the weather. For example, energy consumption in one year may be higher than the previous
year because the weather may be hotter and thus greater use of air conditioning is made. In the short term, energy
consumption data must be adjusted to remove the effects of abnormally hot or cold years so that it is more representative of
the overall trend in energy consumption. Over the long term, weather effects will cancel themselves out — that is,
abnormally hot years will be offset by abnormally cool years — and thus no adjustment is required.
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4.2.2 Assumptions underpinning the different scenarios
In response to the Draft Decision, the distributors commented that the high case growth scenario
was an extreme case generated by factoring into the modelling optimistic assumptions on a range
of economic and non-economic factors. The distributors (CitiPower & Powercor 2005a) stated
that the high case assumes, for example, the following:
•
Iraq stabilising, peace in the Middle East and oil prices returning to $US15 to $US25;
•
EuroAsia expansionary monetary policies leading to above average European growth rates
for 10 to 15 years; and
•
China opening up, becoming democratic and world trade expanding at 6-9 per cent per
annum.
These assumptions were not documented in the NIEIR reports submitted to the Commission
prior to the Draft Decision. The only items of information available at the time of the Draft
Decision on the high case scenario were the Victorian GSP forecasts underpinning the growth
forecasts and a broad description of the economic circumstances assumed under the high case.
This description was set out in the Commission’s Issues Paper and is as follows:
In contrast to the base case, the high scenario expects strong Asian economic growth,
including in China, over the projection period. The structural imbalances in the United
States economy are gradually corrected without any further shocks to consumers,
businesses and investor confidence. Stronger United States growth reduces their current
account deficit. Global conflict, including terrorism, abates. Commodity prices remain
high for a sustained period and that Australia secures a significant number of major
resource processing projects in the mining and energy sectors. Business investment and
Australian exports surge, supporting stronger growth in the Australian economy to 201314.
In response to the distributors’ concerns over the use of the high case, the Commission has
further reviewed the assumptions used under the high, alternative base and base case scenarios,
the methodology that NIEIR used to develop these assumptions and how the assumptions were
then factored into the growth forecasts.
In undertaking this review, the Commission has met with NIEIR and visited its premises to view
the NIEIR model and assessed the assumptions that NIEIR has used against other publicly
available information sources.
While a summary of the main economic forecasts used to develop the electricity forecasts is
provided in the NIEIR reports, there does not appear be a similar description of the assumptions
that were used to develop these economic forecasts. In order to understand the methodology, the
Commission queried how assumptions such as peace in the Middle East were factored into the
modelling. NIEIR indicated that these were the assumed circumstances needed for the oil price
to return to the $US15 to $25 range.
It does not appear that the assumptions underlying each scenario are documented, nor how the
assumptions vary from one scenario to another. Instead, an understanding of the assumptions
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requires investigation of the values inputted into the model and investigation of how the
assumptions made impact upon the outputs produced.
NIEIR (2005b) indicated that, in their view, the high case is a high energy growth scenario.
Under the high case, NIEIR increases the intensity at which electricity is used in the
manufacturing, commercial and residential sectors relative to the base and alternative base
scenarios and assumes that real electricity prices fall by some 20 per cent over the period to
2011, reflecting lower wholesale and distribution prices.
As a result of the assumptions used in formulating the high case, NIEIR considers that there is
only a 5 per cent chance that the forecasts produced under this scenario will be exceeded.
The distributors (CitiPower & Powercor 2005a) noted that the high case growth scenario results
in forecasts that are higher than historic outcomes. This is shown in the Table 4.6.
Table 4.6:
Total energy consumption growth rates — NIEIR high case scenario,
September 2004
2000-04
2004-10
AGLE
0.75
1.80
CitiPower
1.95
1.67
Powercor
2.05
2.86
SP AusNet
2.90
3.47
United Energy
1.89
2.45
Note: Commission 2000 to 2003 historic data compiled from tariff approval models and 2004 historic data from regulatory accounting
statements.
The Commission is of the view that the high case growth scenario may over-estimate growth
over the next regulatory period because it appears to adopt assumptions that may result in it
being an extreme high case.
As a result, the Commission has further reviewed the assumptions underlying the base and
alternative base case to assess the appropriateness of using either of these scenarios as the basis
for the growth forecasts. In reviewing these assumptions the Commission has focussed on the
reasons that NIEIR has forecast a slowing in growth over the next regulatory period, namely:
•
a slowing of Victorian GSP growth relative to that experienced in the current period;
•
the impact of federal and state government energy conservation policies; and
•
a downside risk to Victorian manufacturing activity.
Each of these assumptions is discussed in turn below.
It should be noted that, in August 2005, NIEIR revised its forecasts under the base and
alternative base case scenarios at the request of the distributors to reflect 2004 actual data rather
than the estimate used in the 2004 forecasts (see Table 4.7). These revised forecasts replaced
those produced in September 2004.
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Table 4.7:
Total energy consumption growth rates — NIEIR base and alternative base
case scenarios, August 2005
Alternative base
Base
2000-04
2004-10
2004-10
AGLE
0.75
0.75
0.24
CitiPower
1.95
1.14
0.92
Powercor
2.05
1.90
1.54
SP AusNet
2.90
2.52
2.31
United Energy
1.89
1.49
1.17
Note: Commission 2000 to 2003 historic data compiled from tariff approval models and 2004 historic data from regulatory accounting
statements.
However, NIEIR did not revise the high case scenario. United Energy provided an explanation
for the limited revision. According to United Energy:49
NIEIR has not been asked (nor have they provided) high and low case scenarios. Given the
incorrect application of these scenarios in the draft decision, UED has limited NIEIR's
scope of work to those scenarios that they consider to be the most appropriate outcome
and have asked NIEIR to provide their independent recommendation as to the most
appropriate.
The revised forecasts produce slower growth rates than the growth rates implied by the forecasts
produced in September 2004 (see Tables 4.4 and 4.7), despite the actual level of sales in 2004
being higher than the estimate for four of the five distributors. The Commission assumes that the
2005 high case forecast would also have produced slower growth rates than the high case
forecast in 2004.
GSP forecasts
In their submissions in response to the Draft Decision, the distributors raised concerns over the
reliance that the Commission had placed on DTF’s GSP forecasts. In particular, United Energy
(2005, p. 4) commented that the reliance on Department of Treasury and Finance (DTF) GSP
forecasts was a change of approach by the Commission:
The Commission also markedly changed its approach regarding the relevance of the State
Government’s DTF forecasts. In particular, in its Guidance Paper, the Commission did not
make any reference to the State Government’s DTF’s macroeconomic assumptions or its
forecast of Gross State Product. Instead, the Commission suggested that the distributors
were free to adopt assumptions, key input data and forecasting methods providing that
these were reasonable. The Commission did not provide any direction to use the DTF’s
macroeconomic forecasts.
49
Email to Dianne Shields from Andrew Schille 1 September 2005.
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The Commission has always had regard to the key inputs and assumptions used to determine the
components of the regulatory framework. The Commission is concerned to ensure that the
assumptions used to determine each component are consistent with other available sources or,
where assumptions do differ, to have sound reasons for why there should be differences.
The distributors consider that DTF’s GSP forecasts are high in the short term and that DTF’s
longer term estimates of GSP are ‘projections’ that are little more than a technical assumption
that over those years of the forecasting horizon the Victorian economy will return to what DTF
considers to be a long-run growth rate. Further, they claim DTF’s forecasts do not consider the
impacts of economic cycles and imply that the Victorian economy will grow in line with the
national average which is contrary to NIEIR and EconTech.
The Commission has considered the accuracy of the short and long term GSP forecasts provided
by a number of agencies, including DTF, NIEIR, Access Economics and Econtech.
The distributors claim and the Commission concurs that, compared with NIEIR’s base case and
Econtech, DTF’s short term GSP forecasts appear high. The Commission also notes that DTF’s
short term forecast are high compared with Access Economics’ forecasts (see Table 4.8).
Table 4.8:
Annual average GSP growth rate — DTF, NIEIR base case, Econtech,
Access Economics 2004-05 to 2005-06
GSP growth rate
DTF
2.9%
NIEIR base case
2.2%
Econtech
2.1%
Access Economics
2.4%
Source: CitiPower & Powercor 2005a, p. 3; Access Economics 2005
However, to properly assess the credentials of an agency’s short term forecasts, the forecasts
must be compared with historic outcomes rather than other available forecasts. Comparing one
forecast against another will not provide an indication of which forecast is more accurate without
considering the accuracy of past forecasts against historic outcomes.
DTF’s and NIEIR’s base case short term GSP forecasts have been assessed against actual GSP
growth. The Commission does not have this information for Access Economics and Econtech.
This analysis suggests that DTF’s short term forecasts have been more accurate against actual
growth in GSP when compared with the GSP forecasts included in the NIEIR base case scenario
(see Table 4.9). The average bias in the short term forecasts prepared by DTF for these years is
0.42 percentage points while NIEIR’s average bias for these years is 1.47 percentage points.
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Table 4.9:
Forecast and actual annual average GSP growth — DTF, NIEIR base case
DTF
NIEIR base case
Forecast in 1999-2000 for 2000-01
3.00
1.00
Actual in 2000-01
2.50
2.50
Forecast in 2000-01 for 2001-02
3.50
1.70
Actual in 2001-02
3.90
3.90
Forecast in 2001-02 for 2002-03
3.75
2.60
Actual in 2002-03
3.30
3.30
Source:
Victorian Government State Budget Papers and VENCorp Planning Reports 2000, 2001 and 2002.
While the accuracy of a forecaster’s short-term forecasts needs to be considered, the Commission
must make a judgement about expected growth over the medium to long term. Consequently, the
Commission is more concerned with an agency’s medium to long term forecasting capabilities
than with its short term credentials.
The performance of DTF’s ‘projections’ and NIEIR’s ‘dedicated forecasts’ has been assessed
against actual economic GSP growth over the last few years. The forecasts are compared with
actual levels of Victorian GSP growth as published by the Australian Bureau of Statistics. The
information available only allows comparisons to be undertaken for three year periods at a time.
The results of the analysis suggest that NIEIR’s base case scenario under-estimated growth in
Victorian GSP in two out of the three forecasting periods assessed (Tables 4.10, 4.11 and 4.12).
Table 4.10:
GSP forecasts prepared midway through the financial year 1999-2000
2000-01
2001-02
2002-03
Ave. over
period
Ave.
biasa
Rank
DTF
3.00
3.25
3.25
3.17
-0.07
1
Econtech
n.a.
n.a.
n.a.
Access Economics
2.50
2.88
3.20
2.86
-0.38
2
NIEIR Base Case
1.00
1.60
3.20
1.93
-1.30
3
Actual growth
2.50
3.90
3.30
3.25
a
This measures how much the estimates have, on average across the period, over or underestimated growth. It is calculated by taking the
difference between the forecast and actual growth in each year and averaging across the period.
Source:, Vencorp – Electricity Annual Planning Review 2000 (p. 19), Victorian Dept. of Treasury and Finance – 1999-2000 Mid-Year Budget
Review (p. 13), ABS Cat. No. 5220.01
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Table 4.11:
GSP forecasts prepared midway through the financial year 2000-01
2001-02
2002-03
2003-04
Ave. over
period
Ave.
biasa
Rank
DTF
3.50
3.50
3.50
3.50
-0.13
1
Econtech
n.a.
n.a.
n.a.
Access Economics
2.98
3.21
3.18
3.12
-0.51
2
NIEIR Base Case
1.70
2.40
3.70
2.60
-1.03
3
Actual growth
3.90
3.30
3.70
a
This measures how much the estimates have, on average across the period, over or underestimated growth. It is calculated by taking the
difference between the forecast and actual growth in each year and averaging across the period.
Source: Vencorp – Electricity Annual Planning Review 2001 (p. 19), Victorian Dept. of Treasury and Finance – 2000-01 Budget Update (p. 17),
ABS Cat. No. 5220.01
Table 4.12:
GSP forecasts prepared midway through the financial year 2001-02
2002-03
2003-04
2004-05
Ave. over
period
Ave.
biasa
Rank
DTF
3.75
3.50
3.50
3.58
0.33
2
Econtechb
3.20
2.30
n.a.
2.75
-0.75
4
Access Economics
3.60
2.40
2.20
2.73
-0.52
3
NIEIR Base Case
2.60
3.50
3.20
3.10
-0.15
1
Actual growth
3.30
3.70
2.75
c
a
This measures how much the estimates have, on average across the period, over or underestimated growth. It is calculated by taking the
b
c
difference between the forecast and actual growth in each year and averaging across the period. Forecast significantly later than others. ABS
data not yet available for 2004-05 actual growth, substituted with DTF latest estimate from Victorian Dept. of Treasury and Finance – 2005-06
Budget Paper No. 2 (p18)
Source: Vencorp — Electricity Annual Planning Review 2002 (p 22), Victorian Dept. of Treasury and Finance — 2000-01 Budget Update (p31),
EconTech — Australian State and Industry Outlook June 2002 (p13), ABS Cat. No. 5220.01
The Commission has also assessed DTF’s current long term projections of GSP against historic
growth in GSP and GDP, GSP forecasts prepared by other forecasters and forecasts of GDP
prepared by the Commonwealth Government. This is in response to statements made by the
distributors that DTF’s long term forecasts do not consider the impacts of economic cycles and
imply that the Victorian economy will grow in line with the national average which is contrary to
NIEIR and EconTech.
The results of this analysis indicate that:
•
Victorian GSP has grown, on average, 3.9 per cent per annum in the 10 years to 2003-04,
3.3 per cent per annum in the five years to 2003-04 and 3.6 per cent in the three years to
2003-04 (ABS cat. no. 5220.0).
•
Australian GDP has grown, on average, 3.9 per cent per annum in the 10 years to 2003-04,
commensurate with the growth in Victorian GSP (ABS cat. no. 5220.0).
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•
Commonwealth Treasury is forecasting GDP growth of 3.2 per cent over the next
regulatory period (Commonwealth Government 2005).
These results suggest that assuming that the Victorian economy will grow in line with the
national average is not unreasonable. It is expected that Victorian GSP will grow broadly in line
with Australian GDP over time given that Victoria is the second largest Australian state
economy, comprising approximately a quarter of the national figure.
The GSP forecasts included in the NIEIR base case have tended to under-estimate GSP growth
under its base case scenario. The Commission also notes that NIEIR’s current base and
alternative base case scenarios have assumed a GSP growth rate of 2.4 per cent over the
2006-10 regulatory period.50 This contrasts with DTF, Access Economics and Econtech who are
forecasting average growth of 3.3 per cent, 3.16 per cent and 2.94 per cent respectively
(Victorian Budget Papers 2005, Access Economics 2005, EconTech 2005).
This information would suggest that the growth forecasts under the base and alternative base
case scenarios have factored in an overly-conservative forecast of Victorian GSP which is likely
to result in underestimation of growth over the period.
Federal and state energy conservation policies
The NIEIR (2005b) forecasts anticipate that electricity consumption growth over the next
regulatory period will be slower due to the effects of the 5-star energy rating policy and the
Natural Gas Extension Program. NIEIR also stated that their forecasts of energy consumption are
impacted by the possible adoption of Recommendation 24 of the Mandatory Renewable Energy
Target Review Panel by the Federal Government.51 This latter assumption has only been revealed
since the release of the Draft Decision.
The 5-star energy rating policy requires new homes to be built with a five star energy rating for
building fabric and requires the installation of a rain water system or a solar hot water system.
NIEIR lists the following areas in which electricity consumption will fall due to the 5-star policy
— space cooling; space heating; water heating; cooking; lighting; refrigeration; other appliances
and equipment. NIEIR (2004b, p. 41) indicates that the largest impact of the 5-star policy will be
felt on energy consumption in water heating and space conditioning.
NIEIR (2004b, p. 41) estimates that the policy will result in a fall in average annual electricity
consumption of between 0.2 to 0.4 per cent per annum for metropolitan distributors, and a fall of
between 0.4 to 0.8 per cent per annum for distributors with a mix of both metropolitan and rural
customers.
50
51
Email to Dianne Shields from Tony O’Dwyer (NIEIR) 13 September 2005.
The Mandatory Renewable Energy Target was established in 2001 by the Renewable Energy (Electricity) Act 2000 and is
supported by the Renewable Energy (Electricity) (Charge) Act 2000 and the Renewable Energy (Electricity) Regulations
2001. The measures require the generation of 9500 GWh of extra renewable energy per year by 2010. Recommendation 24
stated that all solar water heater systems installed, including replacement systems, be eligible for renewable energy
certificates to the full extent of their energy displacement capacity. Renewable energy certificates are tradeable and are
earned by generators with each certificate equivalent to 1 MWh of renewable generation.
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The Commission has reviewed the information provided by NIEIR which includes the NIEIR
reports prepared for the distributors in September 200452 and a Regulatory Impact Statement
prepared by the Plumbing Industry Commission for the Plumbing (Water and Energy Savings)
Regulations 2004.
It is unclear why NIEIR has included efficiencies arising from appliance use in its modelling of
the 5-star policy. The Sustainable Energy Authority of Victoria (SEAV) informed the
Commission that the 5-star policy does not apply to appliances and is restricted to building
fabric, energy saving tap ware, solar hot water or rainwater systems.
SEAV engaged Energy Efficient Strategies (EES) to undertake a cost-benefit analysis of the
policy. In contrast to NIEIR, EES estimated that the State-wide reduction in electricity usage
would be between 26 000 and 37 000 Gigajoules per annum (EES 2002, p. 13) — 7 to 10 GWh
per year or 0.09 per cent of residential usage in 2004. This impact is expected to occur in space
conditioning.
SEAV indicated to the Commission that large reductions in electricity usage in water heating as
a result of the policy were not expected because most hot water usage is currently gas and the
intent of the policy is to install gas boosted solar water heating in areas where reticulated gas is
available. The EES cost-benefit analysis also only estimates electricity savings resulting from the
policy impact on space conditioning and did not consider the impact on electricity used in water
heating.
The Regulatory Impact Statement accompanying the Plumbing (Water and Energy Savings)
Regulations 2004 indicates that:
•
The 5-star policy for water heating only applies to new homes (PIC 2003, p. 4).
•
New home owners have the choice of installing either a rainwater tank to replace mains
water flow to the toilet or a solar hot water system (PIC 2003, p. 4). The report stated that
rainwater tanks are cheaper to install than solar hot water systems (PIC 2003, pp. 15 & 16).
•
Where new home owners choose rainwater tanks, there will be no effect on electricity
usage because electricity will be needed to heat potable water supplies.
•
In regard to solar hot water systems, the report notes that
52
y
the majority of Victorian homes currently use gas conventional water heaters (PIC
2003, p. 16);
y
for new homes built in gas-reticulated areas, solar hot water heaters will be largely
replacing conventional gas heaters (PIC 2003, p. 16 & 23);
y
for new homes built in non-gas reticulated areas, solar systems will replace
conventional electric heaters but these homes are allowed to install electric boosters
to support their solar systems (PIC 2003, p. 23);
The 2005 reports were not available prior to the release of this Final Decision.
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y
•
the requirement to limit households to gas-boosted solar systems in gas-reticulated
areas represents an initial cost to householders because gas-boosted systems are more
expensive than electric-boosted models (PIC 2003, p. 18).
The impact of the policy will be lessened where households elect to install a rainwater tank
rather than a gas boosted solar system (PIC 2003, p. 29). The unknown factor is how many
of each system will be installed (PIC 2003, p. 28).
This information suggests that, in gas-reticulated areas, solar hot water systems will largely be
replacing conventional gas hot water systems, not electric. In non-gas reticulated areas where the
majority of electric hot water systems are likely to be, new dwellings installing solar water
heaters are permitted to use electric boosters and so the impact of the policy on electricity
consumption is likely to be small.
NIEIR told the Commission that it anticipated that households would choose to install solar hot
water systems because of their lower running costs even though their installation is more
expensive than a rainwater tank. The RIS (PIC 2003, p. 22) also noted that:
Since the installation costs of a solar heated water appliance is more expensive than a
conventional heated water appliance yet the consumption of gas or electricity for a solar
heated water appliance is less, the householder who installed a solar heated water
appliance receives an economic benefit within the lifetime of the solar water heater.
SEAV informed the Commission that, given the similar pricing between installed solar hot water
and rainwater tank, it is expected that the installation of solar hot water systems and rainwater
tanks will be relatively evenly split. The Commission notes that EES did not estimate the impact
of the policy on electric water heating when undertaking its cost-benefit analysis.
The Productivity Commission (2005, p. 106) found that the initial capital cost of energy saving
devices can act as a barrier to their take up:
Energy-consuming fixtures — such as water heaters — are often selected by a building or
landlord who is primarily concerned about the capital cost, whereas users also have an
incentive to reduce running costs.
EES estimated that the impact of the policy on electricity consumed in space conditioning would
be around 0.09 per cent per annum. EES expected that the majority of the impact would be on
gas used in space heating while the effect on electricity used in space cooling would be minor
(EES 2002, p. 13).
NIEIR (2004b, p. 41) factored in a reduction of 0.03 per cent per annum in electricity usage in
space cooling and heating. While this is smaller than the impact on usage in space conditioning
estimated by EES, NIEIR is factoring in a larger impact from the policy overall due to its view
that the policy will also impact on water heating and use in electrical appliances.
The impact that the 5-star policy will have on electricity consumption is uncertain because it is
unclear how the 5-star policy will impact upon electricity usage in water heating. However,
NIEIR appears to have assumed a much larger reduction in usage for space conditioning than the
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original cost-benefit study for the policy estimated suggesting that its assumptions in this regard
are overly-conservative.
On balance, the 5-star policy will impact on electricity consumption over the next regulatory
period. However, the Commission is of the view that NIEIR may have over-estimated its impact
primarily due to its overly-conservative estimate of the effect the policy will have on electricity
usage in space conditioning. Over-estimating this impact is likely to result in the underestimation of growth in electricity consumption over the next regulatory period.
Downside risk to Victorian manufacturing
Under the base case scenario, the growth forecasts incorporate a downside risk to Victorian
manufacturing activity.
Information provided (CitiPower & Powercor 2005a) to the Commission since the Draft
Decision indicated that NIEIR initially prepared forecasts incorporating a downside risk to
manufacturing for the South Australia distribution price review by the Essential Services
Commission of South Australia (ESCOSA). The downside risk was incorporated into the South
Australian forecasts partly in response to the announced closure in 2004 of the Mitsubishi engine
plant and Mobil refinery. According to NIEIR, these closures had a significant impact on
electricity use.
In 2004, NIEIR prepared a report at the request of the distributors entitled “An Assessment of the
Downside Risk to Manufacturing in Victoria”. This report set out NIEIR’s analysis of the
downside manufacturing risk in Victoria and the econometric analysis underpinning the
incorporation of this risk into the distributors’ forecasts.
NIEIR indicates that their modelling53 estimates that, as a result of the 1998-2004 house price
boom, by 2010 manufacturing gross product (output less inputs) will be 14.5 per cent below the
level that otherwise would have prevailed had the house price boom not occurred. NIEIR states
that a reasonable estimate would be that approximately 5 percentage points of the 14.5 per cent
adjustment would have already occurred at the time NIEIR prepared its report, leaving 9.5 per
cent still to occur over the 2004 to 2010 period.
NIEIR states that the current poor gross product outcomes are a good indicator of future lower
electricity demand growth because gross product is a key driver of investment, capital stock
growth and hence future electricity demand. Further, they conclude that the rate of return on
capital has fallen over the last three years suggesting that the rate of growth in the Victorian
manufacturing capital stock may fall to a low level over the 2005 to 2008 period. Combined with
an ageing capital stock, the incentive for investors to continue investing in Victorian
manufacturing will reduce and instead their activities will be transferred overseas.
53
NIEIR developed a non-linear regression equation that models manufacturing real gross product for all Australian states,
including Victoria, based on a ratio of real manufacturing gross product and real net capital stock in manufacturing against,
amongst other things, a ratio of real medium established house prices and gross rate of return for the manufacturing sector in
a particular State. NIEIR indicated that the coefficient between these two ratios is high (-0.263) and highly correlated with a
t-statistic of 22. NIEIR stated that this suggested that land prices have played an important role in explaining the decline in
the share of manufacturing in GDP, both in Australia and Victoria (NIEIR 2004a, p. 13).
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The Commission contacted other agencies on the outlook for Victorian manufacturing activity
over the next five years.
DTF commented that, in developing its GSP forecasts, it undertakes extensive consultation with
industry groups, including the manufacturing sector. Throughout this consultation, there has been
no indication given to it of a downside risk to Victorian manufacturing activity.54 The Australian
Industry Group also predicted that there would be continued growth in manufacturing, although
lower than that experienced in previous years, and that any forecast of a decline in manufacturing
would have to be premised on a significant recession in the economy.
Forecasts of Australian manufacturing activity prepared by Access Economics also suggest that
while manufacturing is expected to slow over the next couple of years, it is also expected to
rebound over the 2006-10 regulatory period (see Figure 4.1).
Figure 4.1:
Actual and forecast Australian manufacturing growth — manufacturing
income, 1996 to 2010
7.00%
6.00%
5.00%
4.00%
3.00%
2.00%
1.00%
0.00%
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Historic growth
Source:
Access Economic forecast
Access Economics 2005; ABS Cat. No. 5676.0
While forecasting manufacturing activity will always contain some level of uncertainty, the
Commission is not of the view that a downside risk to manufacturing should be factored into the
growth forecasts. The other information available suggests that while manufacturing activity may
slow, there is no alternative evidence to support the case that manufacturing in Victoria will
decline over the next five years.
As a result, the Commission has not accepted NIEIR’s base case growth forecasts (and hence the
distributors’ growth forecasts which were based on the NIEIR base case).
The distributors have pointed out that VENCorp in its latest Annual Planning Report has used
NIEIR’s base case scenario which incorporates the downside risk to manufacturing in its
54
Email to Dianne Shields from Rob Brooker 22 July 2005.
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planning of the transmission network. The distributors state that the Commission should consider
consistency with VENCorp when making its decision.
VENCorp indicated to the Commission that its primary focus when forecasting electricity growth
is on peak demand and that energy consumption is only a secondary concern. This is due to the
continual worsening of the Victorian load factor. The Commission also understands that the
manufacturing downside risk affects energy sales but not peak demand. Therefore, the inclusion
of the manufacturing downside risk is of less importance to VENCorp. This is confirmed by
NIEIR where the peak demand forecasts prepared for the distributors did not incorporate the
downside risk to manufacturing.
As the forecasts used for the price review directly impact revenue, the Commission considers
that the assumptions that drive the forecasts require careful review. Although consistency with
VENCorp’s forecast may be desirable, the Commission must be satisfied that the forecasts
adopted for the price review are the best estimate of likely outcomes for growth at the
distribution level. If the forecasts are too low, customers will pay more than they should.
Conversely, if they are too high, distributors may not earn sufficient revenue.
Conclusion
An analysis of the assumptions used in the base and alternative base case suggests that there is
support for a lower growth rate than has occurred over recent years. For example, the 5-star
standard for housing suggests that energy consumption growth will be slower in the next
regulatory period.
The Commission must adopt forecasts that represent its best estimate of growth over the
2006-10 regulatory period. Although it considers the high case may over-estimate growth, it also
considers that the base and alternative base case scenarios are likely to under-estimate growth.
This is an issue that appears to arise as a result of the NIEIR high case being developed on the
basis of an extreme high case.
Nevertheless, the Commission must come to a view on the forecasts and considers that it would
be difficult to rely on a simplistic methodology that considers a downward adjustment to historic
growth rates, even though, in the Commission’s view, such an adjustment would be more
reflective of the likely outcome on growth.
Therefore, the Commission has decided to adopt forecasts that use NIEIR’s alternative base case
scenario as revised by NIEIR in August 2005. In the Commission’s view, the alternative base
case scenario may under-estimate growth and this is likely to provide the distributors with more
revenue over the period than the revenue requirement — a similar outcome to this period.
However, on balance, this is a more preferable outcome than not earning the revenue
requirement, which might be the case if the Commission were to adopt NIEIR’s high case.
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4.2.3 Price elasticity of demand
The price elasticity of demand is a measure of the extent to which the quantity of a product
demanded by customers responds to a price change, other things being equal. It is a unit-less
coefficient, obtained by dividing the percentage change in quantity demanded by the percentage
change in price.
For almost all commodities, a price increase is accompanied by a decrease in the quantity
demanded, resulting in the traditional downward sloping demand curve. Thus, the price elasticity
of demand is a negative number. If the percentage changes in price and quantity demanded are
exactly equal, the price elasticity equals -1. If the percentage change in quantity is less than the
percentage change in price, the elasticity is between 0 and -1. Such commodities are considered
to be relatively price inelastic.
In general, the demand for electricity is relatively inelastic in the short run which is the period of
time during which customers can modify their usage primarily through behavioural changes. In
the long run, customers can change their appliance stock or install insulation to their homes and
thus the price elasticity is greater than in the short run.
Elasticity effects were not incorporated in NIEIR’s base and alternative base case scenarios for
the 2006-10 regulatory period. Instead, NIEIR assumed that the price to both residential and nonresidential customers would stay approximately constant in real terms over the period. MMA
(2005, p. 64) have suggested that:
… the price assumptions made by NIEIR in its forecasting for the DBs […] may be
somewhat high, implying an increase in forecast demand beyond that estimated by NIEIR.
However, the high case included a response to a 20 per cent price reduction.
In the Draft Decision, the Commission considered that the price elasticity impacts resulting from
the price variations arising from the new price controls should be recognised. As a result, the
Commission modelled the first order effects of each distributor’s P0 for DUoS services on the
quantity of electricity consumed for residential and non-residential customers. Separate demand
elasticities for residential and non-residential customers were applied because the price elasticity
literature has demonstrated that elasticities are different for residential customers and small to
medium business customers (ESC 2002a, p. 66).
The quantities calculated from the price elasticity assumptions used were adjusted by forty per
cent in recognition that distribution use of system charges were equal to approximately forty per
cent of a customer’s total electricity bill.
The Commission used the price elasticity estimates that were used in its cost-benefit analysis for
the interval meter roll-out decision (ESC 2002a, p. 85), as set out in Table 4.13.
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Table 4.13:
Price elasticities of demand used in the analysis
Customer type
Elasticity estimates resulting
from Time of Use Pricing
Residential
-0.1
Non-residential
-0.025
In submissions to the Draft Decision, the distributors raised concerns over the application of
elasticities to the growth forecasts. The distributors did not consider that applying an elasticity
effect was an acceptable regulatory approach because:
•
the adjustment assumes all retail tariffs will change immediately when distribution tariffs
change. Retail price caps and market contracts will ensure that this does not happen;
•
the adjustment assumes no other components of retail tariffs will change. The distributors
believe generation costs are facing significant upward pressure, which will reduce or even
outweigh the effects of the distribution price review outcomes on retail tariffs;
•
the adjustment assumes that price elasticity is symmetrical and linear and evidence
suggests that it is not;
•
the adjustment ignores a host of non-economic considerations such as the 5-star building
standard which are likely to reduce not increase consumption;
•
the value of the elasticity used was inappropriate;
•
the adjustment may give distributors the incentive to adopt tariff strategies that mitigate
any revenue risk as a result of the elasticity adjustment; and
•
the adjustment is unprecedented and unanticipated.
The Commission recognises that there is a level of uncertainty over the extent to which price
changes will impact upon energy consumption.
The extent to which retailers pass through the changes in distribution prices to their customers is
uncertain. However, with full retail competition as exists in Victoria, there is more likelihood
now than in the past that price changes will be passed through.
The Commission notes that distribution price reductions should be passed through immediately
to non-residential customers. These customers are generally on retail contracts that require the
immediate pass through of changes in distribution prices. Hence, 2006 distribution price changes
are required to be passed through by retailers in 2006.
In regard to residential customers, the high rate of switching amongst residential electricity
customers suggests that the retail electricity market is effectively competitive and thus residential
customers will be more likely to see the price change. At the end of December 2004, the
annualised switching rate amongst residential electricity customers was 20 per cent. This
represents a 91 per cent increase in transfers in the electricity market since 2003. By comparison,
at December 2002, one year into full retail competition, less than five per cent of electricity
customers were involved in transfers (ESC 2005e, p. 21-22).
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In addition, there is uncertainty over the quantum of the impact on consumption from any decline
in prices. This uncertainty arises from the extent to which price changes in other sectors of the
industry offset the distribution price change and the elasticity figure that is used.
In this regard the distributors state that increases in generation prices will increase the generation
costs and government policies designed to promote the use of renewable energy may increase
retail electricity prices and thus mitigate any reduction in distribution prices. For example, SP
AusNet55 (2005e, p. 2) commented that:
… many concerns, global and local, environmental, social and economic are driving calls
for greater internalisation of external costs, greater efficiency in the use of non-renewable
energy sources and larger contributions to overall energy consumption from, often more
costly, renewable sources. The majority of the developments touched upon above will drive
up costs that determine much of the generation and retail costs making up the 60 per cent
non-distribution related costs.
In the Commission’s judgement, applying an elasticity adjustment to the growth forecasts is
appropriate because elasticity impacts have a sound basis in economic theory and it is likely that
a price change will have some impact upon consumption. Stakeholders have not questioned the
fundamental principle that a price change will result in a change in consumption.
However, stakeholders questioned the quantum of the elasticity impact. In particular, the
distributors note that the elasticity estimates used in the Draft Decision measure the extent of the
shift between peak and off-peak use and not the effect of a price change on total usage. The
Commission has found it difficult to find an appropriate elasticity estimate to use. For this
reason, the growth forecasts have not been adjusted for elasticity impacts.
The Commission also notes that, while the adoption or otherwise of this approach elsewhere is of
interest, this should not drive the Commission’s own approach.
55
Formerly TXU
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PART B2:
REVENUE REQUIREMENT — DUOS
In this Part, the Commission sets out its Final Decision and reasons regarding the components
that go into determining the revenue requirements for the provision of distribution use of system
services over the 2006-10 regulatory period. The revenue requirement for prescribed metering
services is discussed in Part B4.
The Commission uses a ‘building blocks’ approach to determine the revenue required by a
distributor. Under this approach, the Commission builds up revenue from an assessment of the
key cost components comprising operating and maintenance expenditure, cost of capital
financing requirements (return on and of capital), forecast tax liability and any efficiency
carryover amounts resulting from efficiency gains earned in the preceding regulatory period. The
return on capital is determined by rolling forward the value of the regulatory asset base taking
into account, among other things, capital expenditure requirements and then applying a weighted
average cost of capital to the rolled forward asset value.
The distributors have outperformed the building blocks benchmarks set at the last price review.
The level of operating and maintenance expenditure undertaken has been below that forecast as
has the level of capital expenditure. The rates of return that the distributors have earned on their
invested capital have also been higher than forecast at the last price review.
The level of underspending by the distributors has also provided them with further financial
benefits in the form of efficiency carryover amounts that will be added into the revenue
requirements for the 2006-10 regulatory period.
The incentive-based framework that the Office of the Regulator-General (ORG) set in place at
the last price review provided for these outcomes. The framework was designed to give the
distributors incentives to achieve efficiency gains and so earn higher returns by outperforming
the expenditure forecasts while also maintaining or delivering improvements in service levels
(see Part B1). It was intended that customers would benefit from these efficiency gains in the
medium to longer term as efficiency gains were passed through to them in the form of lower real
prices which reflect the delivery of service standards that are maintained or improved over time
at lower cost.
The efficiency carryover mechanism (in combination with the service incentive arrangements)
was a key feature of this incentive-based framework. It allows the distributors to retain the
benefits of the efficiency gains they made in the current period for a limited time into the next
regulatory period before those gains are passed through to customers. The intention was to
maintain a continuous incentive for the distributor to achieve cost efficiencies throughout the
period by allowing them to retain the benefits for five years irrespective of the years in which
they are earned. These benefits would then flow through to customers in the form of lower real
prices in the next regulatory period. However, in order to claim the efficiency carryover
amounts, the distributors would be required to reveal the more efficient costs of providing the
service and those revealed costs would then inform the Commission’s assessment of the
expenditure proposals for the 2006-10 regulatory period.
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Assuming that it could rely on the incentive properties of the efficiency carryover mechanism,
the Commission at the commencement of this price review considered that it could use the levels
of expenditure reported by the distributors as a starting point for determining the expenditure
forecasts for the 2006-10 regulatory period. Based on this assumption, the Commission gave
weight to the level of expenditure reported for the year 2004 as its starting point for determining
the requirements for the 2006-10 regulatory period. Having determined its starting point, the
Commission’s assessment of the distributors’ price-service proposals could then focus on the
reasons why future expenditure was likely to vary from the reported levels of expenditure that
the Commission had available to it.
This approach was the key to ensuring that the benefits of the efficiency gains achieved in the
2001-05 regulatory period were passed through to customers in the form of lower real prices in
the 2006-10 regulatory period. It should also have allowed the Commission to be satisfied that
real prices in the next regulatory period reflected the distributors’ efficient expenditure levels
with any variation from 2001-05 expenditures due to changes in functions or legislative
obligations or asset management policies.
However, a review of the information contained in the distributors’ Regulatory Accounting
Statements has raised concerns over the application of this approach in practice. The use of
related party contracts, the outsourcing of a large proportion of services and sometimes
substantial increases in expenditure reported in these accounts means that the Commission has
had cause to question whether the information reflects the costs incurred in providing
distribution services. The Commission is also concerned that its intended use of revealed 2004
cost levels as its starting point for assessing the 2006-10 expenditure proposals may have
provided distributors with an incentive to ‘ramp up’ expenditure in 2004. For example, one
distributor alone has increased reported expenditure in 2004 by 63 per cent over the level
reported in 2003.
This has led the Commission to make adjustments to the reported expenditure, and in some
cases, produce estimates, particularly for 2004. This has been necessary to ensure that the
regulatory framework operates as intended by enabling customers (as well as the distributors) to
benefit from the efficiency gains made in the current regulatory period.
Operating and maintenance expenditure and capital expenditure forecasts
For the purposes of setting the expenditure forecasts for the next regulatory period, the
Commission has made an assessment of the levels of operating and maintenance expenditure and
capital expenditure during the 2001-05 period that it considers reflects the cost of service
provision and therefore represents an appropriate starting point for determining the distributors’
revenue requirements for the next regulatory period. Specifically, the Commission made
adjustments to the information contained in the distributors’ reported Regulatory Accounting
Statements relating to, among other things, allocations of costs between retail and distribution
services and between prescribed and excluded services, movements in provisions and contractual
arrangements. The Commission’s reasons for and approach to making adjustments to this
information are presented in Chapter 5.
Having determined these starting points, the Commission then assessed the distributors’
proposed expenditure. For operating and maintenance expenditure, the Commission has had
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regard to the level of historical expenditure and the reasons the distributors have given for
forecasting future expenditure requirements that differ from past trends (referred to as step
changes) (see Chapter 6). For capital expenditure, the Commission considered a range of
information, using historical information as a starting point in its analysis (see Chapter 7). The
Commission has received assistance in making these assessments from its technical consultant
Wilson Cook and Co.
The forecasts of operating and maintenance expenditure and capital expenditure that the
Commission has used to determine the revenue requirements for the next period represent real
increases over the level of expenditure that was incurred in the 2001-04 period (see Figures B2.1
and B2.2). The increased levels of expenditure have been assessed by the Commission as being
necessary to provide the distributors with sufficient revenue to meet changed functional and
legislative obligations.
Figure B2.1: Total gross capital expenditure, industry aggregate, out-turn capital
expenditure 2001-04,a distributor proposed 2005-10 and Final Decision
2006-10, $million, real 2004
900
800
700
600
500
$M
400
300
200
100
0
1996
1997
1998
1999
Actual capex (inc meters)
a
2000
2001
2002
2003
2004
Commission Final Decision CAPEX (ex meters)
2005
2006
2007
2008
2009
2010
Commission Final Decision CAPEX (inc meters)
Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs
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Figure B2.2: Total operating and maintenance expenditure, industry aggregate, out-turn
operating and maintenance expenditure 2001-04,a distributor proposed
2005-10 and Final Decision 2006-10, $million, real 2004
600
500
400
$M 300
200
100
0
2001
2002
2003
2004
2005
2006
Commission Final Decision
a
2007
2008
2009
2010
Actual opex
Exclusive of operating and maintenance expenditure associated with prescribed metering services.
Regulatory asset bases and cost of capital financing component
The Commission has rolled forward the value of the distributors’ regulatory asset bases in
accordance with the requirements set out under clause 2.1 of the Tariff Order. In determining the
opening value of the asset bases, the Commission has not reviewed the prudency of the capital
expenditure undertaken by distributors nor sought to identify and remove stranded or partly
stranded assets. Instead, it has relied on the incentives of the regulatory framework.
To roll forward the opening value of each distributor’s regulatory asset base, the Commission
has used forecasts of capital expenditure, customer contributions, regulatory depreciation and
disposals. The resulting estimated value of the regulatory asset base in each year is then used to
determine the distributor’s return on and of capital components of the revenue requirements for
the 2006-10 regulatory period. The Commission’s approach to determining the distributors’
regulatory asset bases is set out in Chapter 8.
To determine the return on capital component of the revenue requirement, the Commission has
applied a real after-tax weighted average cost of capital of 5.9 per cent to the rolled forward
values of the regulatory asset base. The change in the weighted average cost of capital from that
used in the last price review (6.8 per cent) is due in the main to a forecast decline in real interest
rates from 3.5 to 2.64 per cent. Chapter 9 discusses the cost of capital financing requirements.
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The return of capital component (or regulatory depreciation) of the revenue requirement has been
determined using the straight-line depreciation schedules set out by the distributors in their priceservice proposals (see Chapter 8).
Efficiency carryover mechanism
In calculating the efficiency carryover amounts to apply in the 2006-10 regulatory period, the
Commission has applied a net present value approach to determining any net negative carryover
amounts.
In accordance with the Appeal Panel findings following the last price review, the Commission
has adjusted the expenditure forecasts set at the last price review for the cost impacts arising
from any differences between forecast and actual growth over the period. The benchmarks have
also been adjusted to reflect variations in policies regarding the capitalisation of indirect
overheads.
The Commission has also changed the operation of the efficiency carryover mechanism in the
2006-10 regulatory period. The mechanism will continue to apply to operating and maintenance
expenditure, but will no longer apply to capital expenditure.
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5 RELEVANT COSTS
The Commission's framework and approach for the 2006-10 price review is based on the
presumption that distributors have an incentive to operate efficiently and that reported costs are
properly due to the provision of distribution services. The robustness (or otherwise) of this
presumption is important because, in determining the expenditure requirements of the
distributors for the 2006-10 regulatory period, the Commission is seeking to place considerable
weight on the distributors' historical expenditure and, particularly in the case of operating and
maintenance expenditure, the distributors' 2004 expenditure.
In addition to the need to establish forward looking expenditure requirements, the regulatory
framework (as enshrined by the Tariff Order) requires there to be a fair sharing of the benefits of
efficiency gains between customers and distributors. The question of whether reported costs
accurately reflect the costs of providing distribution services is fundamental to the measurement
of such efficiency gains and to decisions on the extent of their sharing.
To calculate the efficiency carryover amounts that give effect to this sharing, the Commission
must also be able to compare the out-turn costs during the 2001-05 regulatory period to the
benchmark expenditure requirements established for the 2001-05 regulatory period. This requires
the Commission to understand the basis on which the distributors’ out-turn costs have been
calculated so that it is possible to compare out-turn costs on a like-for-like basis with the
appropriate benchmarks.
Given the Commission’s regulatory approach as described above, there is a risk that if a
distributor's historical, reported expenditure is not efficient, or if it includes costs that are not
properly due to the provision of distribution services, then:
•
any inefficiencies or misallocations will be carried forward into the revenue requirement
for the 2006-10 regulatory period; and
•
the measurement, and therefore sharing, of efficiency gains will be distorted.
The need to carefully review reported expenditure and make adjustments arises in the context of
all forms of monopoly regulation that rely on business-specific cost information because of the
associated incentive to report or represent that costs are greater than can properly be said to be
the case. These incentives may manifest themselves in a number of ways:
•
the allocation of costs to prescribed distribution services where those costs are not properly
associated with the provision of those services, for example, costs associated with any
retail interests, excluded services and other activities;
•
changes in capitalisation policies so that the allocation of costs as between operating and
maintenance expenditure, on the one hand, and capital expenditure, on the other hand,
differs from the policy on which the corresponding expenditure benchmarks was based;
•
the use of accounting or operational adjustments that affect the timing with which costs are
reported, such as through provisioning for future expenditure in such a way that the
expenditure is reported for one year even though the cash outlay is to take place over
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several years, or the bringing forward or delaying of expenditure so that it falls into one
accounting year or another;
•
where regulated distribution activities are conducted within the same legal entity as other
activities, the use of methods that provide for a disproportionate allocation of joint or
common costs to the regulated business; and
•
the establishment of prices or the entering into of contracts for the supply of services that
have not been verified by reference to a market price for those services.
Accordingly, the Commission has reviewed in detail the regulatory accounting information
provided by the distributors for the 2000-04 period and has made a number of adjustments to the
information for the reasons outlined above. Additionally, errors in the Regulatory Accounting
Statements have been identified and corrected. The adjustments that the Commission has made
means that the Commission can proceed with a greater degree of confidence that out-turn cost
information (as adjusted) reflects the cost of providing distribution services and the economic
circumstances of the distribution businesses and can be used for the determination of:
•
the efficiency carryover amount (as measured through the variation of actual expenditure
compared to the benchmark) arising in respect of the 2001-05 regulatory period for capital
and operating and maintenance expenditure;
•
the base operating and maintenance expenditure forecasts to apply for the
2006-10 regulatory period; and
•
the starting point for determining capital expenditure forecasts to apply for the
2006-10 regulatory period.
This has also allowed the Commission’s review process to focus on the basis for, and cost impact
of, any step changes or variations in the distributors’ functions or other obligations that are
relevant for the forthcoming regulatory period, as well as the expected rate of change in
operating and maintenance expenditure.
5.1 Final Decision
The out–turn operating and maintenance expenditure and capital expenditure over the
2000-04 period to be relied on by the Commission are set out in Table 5.1. The adjustments by
category and distributor are provided in Table 5.2.
The information set out in these tables includes adjustments to reported expenditure to reflect the
underlying costs incurred in providing distribution services and to ensure a like-for-like
comparison with 2001-05 benchmarks. In addition, the Commission has made further
adjustments to estimate the efficient recurrent operating and maintenance expenditure for United
Energy, CitiPower and Powercor where the reported information could not be relied upon for on
this purpose.
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Table 5.1:
Historical operating and capital expenditure, 2000-04, all distributors,
$million, real $2004
2000a
2000b
2001
2002
2003
2004
AGLE
53.7
49.6
43.3
44.5
50.0
48.4
CitiPower
36.4
31.3
30.2
20.5
24.9
31.7
99.2
89.7
81.7
87.6
101.1
103.5
96.8
93.1
86.9
90.3
86.1
93.4
79.4
73.4
76.8
72.6
74.6
74.9
AGLE
34.0
31.5
38.3
28.0
32.0
33.4
CitiPower
79.0
74.6
75.0
65.5
56.8
68.4
Powercor
132.9
128.7
132.7
107.2
110.9
124.9
SP AusNet
75.3
75.1
100.0
56.1
78.2
100.8
United Energy
90.7
90.0
65.0
77.8
79.3
77.3
Operating expenditure
Powercor
SP AusNet
c
United Energy
Capital expenditure
a
Includes metering data services and public lighting which were classified as prescribed services prior to 2001.
Excludes metering data services and public lighting which were classified as excluded services from 2001.
c
Formerly TXU
b
The following tables summarise the adjustments that have been made by category and
distributor.
Table5.2:
Adjustments to reported operating and maintenance expenditure, 2000-04,
all distributors, $million, real $2004
2000
2001
2002
2003
2004
Provisions
-0.7
-1.9
-3.0
2.0
0.8
Excluded services
0.0
0.0
0.0
-0.1
0.0
Retail
-1.4
-0.6
-0.1
-0.3
0.0
Capitalisation
-0.5
-1.2
-1.5
-1.6
0.0
Contractual arrangements
0.0
0.0
0.0
0.0
-0.2
Provisions
0.0
0.6
-11.8
-0.3
0.1
Excluded services
0.0
-4.4
0.0
0.2
-0.1
Retail
-4.2
-1.8
-1.3
0.0
0.0
Capitalisation
0.0
0.0
0.0
0.0
-6.6
Errors
0.0
0.0
0.0
0.8
-2.4
Contractual arrangements
0.0
0.0
0.0
-5.3
-6.5
AGLE
CitiPower
(continued next page)
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Table5.2:
Adjustments to reported operating and maintenance expenditure, 2000-04,
all distributors, $million, real $2004
2000
2001
2002
2003
2004
Provisions
-2.4
-30.1
-6.0
1.1
3.8
Excluded services
-0.1
-9.5
3.2
0.0
0.0
Retail
-1.3
-0.6
0.0
0.0
0.0
Errors
0.0
0.9
0.0
0.0
0.0
Contractual arrangements
0.0
0.0
0.0
0.0
-5.0
Further adjustments
0.0
0.0
0.0
0.0
-5.5
Provisions
-3.2
-0.3
1.4
-0.8
-0.6
Excluded services
0.0
-1.2
0.4
-6.8
0.0
Retail
-3.6
-5.2
-6.2
-4.0
0.0
Errors
0.0
0.5
-3.8
-4.5
0.6
Contractual arrangements
0.0
0.0
0.0
0.0
-0.6
Provisions
-4.7
4.7
-1.7
-1.1
1.6
Contractual arrangements
0.0
-6.6
-4.2
-8.9
-12.3
Powercor
SP AusNet
United Energy
Table 5.3:
Adjustments to reported capital expenditure, 2000-04, all distributors,
$million, real $2004
2000
2001
2002
2003
2004
Excluded services
0.0
-1.4
-1.2
-0.9
-1.4
Capitalisation
6.2
9.7
5.9
1.0
1.4
Contractual arrangements
0.0
0.0
0.0
0.0
-0.1
Provisions
0.1
0.1
0.0
-0.5
-0.4
Excluded services
0.0
-1.7
0.0
0.0
0.0
Retail
0.0
0.0
-31.9
0.0
0.0
Capitalisation
0.0
0.0
0.0
0.0
8.3
Contractual arrangements
0.0
0.0
0.0
-5.0
-6.4
AGLE
CitiPower
(continued next page)
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Table 5.3:
Adjustments to reported capital expenditure, 2000-04, all distributors,
$million, real $2004
2000
2001
2002
2003
2004
Provisions
-1.1
-0.3
-0.9
-0.3
-1.8
Excluded services
0.0
-3.8
-4.5
0.0
0.0
Errors
0.0
-9.2
0.0
-9.5
0.0
Excluded services
0.0
-0.9
-2.8
0.0
0.0
Errors
-1.3
-0.7
1.8
-1.4
0.0
Excluded services
0.0
-3.5
-0.5
0.8
0.0
Errors
20.1
-22.2
-14.2
-8.5
-5.9
Powercor
SP AusNet
United Energy
5.2 Reasons for the Decision
The distributors submit audited regulatory accounting statements to the Commission on an
annual basis and these are prepared based on the Regulatory Information Requirements
Guideline No. 3 (Regulatory Accounting Guideline).
The Regulatory Accounting Guideline indicates that the information reported is to be used for a
number of purposes by the Commission including to inform Electricity Distribution Price
Determinations. The Guideline is a principle-based document requiring principles and policies to
be disclosed in a manner which ensures the Commission understands the information and can
make comparisons over time. The Regulatory Accounting Guideline provides considerable
discretion to the distributors, particularly in terms of the allocation of shared costs, capitalisation,
provisions and related party transactions. However, the requirement to disclose policies
regarding the allocation or accounting treatment of costs incurred is designed to ensure that the
information can be compared by making adjustments to account for variations in policies and
procedures across distributors and over time. This approach provides flexibility to the regulator
or distributor in terms of adopting an appropriate policy or procedure to apply for a particular
purpose at any point in time, and it is considered preferable to prescribing rules for this purpose.
Further, the Guideline requires that, where substance and form differ, the substance rather than
legal form of a transaction or event must be reported and that, in determining the substance of a
transaction, all its aspects and implications must be considered, including the expectations of and
motivations for the transaction.
In July 2004, the Commission commenced a review of the information provided in the
distributors’ regulatory accounting statements for 2000, 2001, 2002 and 2003 to ensure that it
understood the information and was in a position to make any appropriate adjustments for the
purpose of the 2006-10 price review. The Commission has also reviewed the regulatory
accounting statements submitted for 2004 at the end of April 2005.
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The Commission has identified a number of issues arising out of the distributors’ regulatory
accounting statements and has made adjustments for matters such as variations in allocation
policies, movements in provisions and for charges that may not have been established by
reference to a market price. It has also considered variations in allocation policies across
distributors and over time.
These issues bear directly on the Commission’s ability to compare the costs of providing
distribution services with the benchmark expenditure estimates established in 2000 for the
2001-05 regulatory period, and to establish future estimates against which future efficiencies can
be assessed.
The Appeal Panel considered that, to calculate the efficiency carryover amounts for the 19952000 regulatory period, the Office of the Regulator-General (ORG) should ensure that:
•
there is a consistent approach between distributors; and
•
the approach is as consistent as is feasible, given the available information, with regard to
the benchmark forecasts of expenditure (ORG 2000c, p. 8).
In its statement of reasons, the Appeal Panel made the following observations which are
particularly pertinent to this matter:
•
to obtain a measure of efficiency for the purposes of incorporation in the efficiency
carryover mechanism, it is necessary that accounts which are being compared are produced
on a comparable basis, and that these accounts cover a comparable range of operations;
•
where actual amounts include or exclude items that are included in benchmarks, this is a
serious problem which limits the accuracy of measuring efficiency; and
•
consistency between distribution businesses is also important since it should not be the
case that some distribution businesses are credited with efficiency improvements whilst
others are not, solely because of their fortuitous choice of accounting base (ORG 2000c,
p. 8).
In its re-determination, the ORG made adjustments to the calculation of the efficiency carryover
amounts for the 1995-2000 regulatory period where the approach adopted by one or more
distributors disadvantaged them relative to other distributors. These adjustments were for bad
debts, shared costs, redundancy costs, and the proportion of management fees that related to a
transfer of profits (rather than fees paid for corporate services provided). Such adjustments were
made in preference to imposing a particular accounting methodology on all distributors.
This highlights the importance of clearly establishing the basis for the estimated expenditure for
the 2006-10 regulatory period. It is also consistent with the Commission requiring adequate
disclosure so that adjustments can be made to compare information on a ‘like for like’ basis over
time, across businesses and with benchmarks.
The basis for the allocation underpinning the operating and maintenance expenditure
benchmarks for the 2001-05 regulatory period was the KPMG (2000) and UMS (2000) reports
and the basis of the capital expenditure benchmarks was the PB Power (2000) report. In
considering the information reported in the Regulatory Accounting Statements during this
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current period, the Commission has therefore made adjustments where required to ensure
consistency with these benchmarks and to clearly represent the costs of providing the services.
5.2.1 Allocation between retail and distribution services
The review of the distributors’ regulatory accounting statements considered whether the basis of
allocation between the retail and distribution businesses (where applicable) was consistent with
the allocation assumed in the benchmarks for the 2001-05 regulatory period and provided a fair
representation of the costs incurred for the provision of distribution services. This was a key
issue at the time of the last price review and the operating and maintenance expenditure
benchmarks established were based on the allocation outlined in the KPMG report. In fact,
Powercor resubmitted its 1999 regulatory accounting statements in August 2000 to reflect these
bases of allocation. This was referred to specifically by the Appeal Panel.
Applying the allocation bases outlined in the KPMG report, the Commission has identified the
following adjustments that need to be made to the information reported in the distributors’
regulatory accounting statements for the purposes of this price review.
•
For AGLE, the reallocation of some retail-related costs, particularly for billing and revenue
collection.
•
For CitiPower, the Commission identified that, although the magnitude of costs allocated
to the distribution business had remained consistent with the benchmark level outlined in
the KPMG report, there had been a change in the allocation policy such that the policy
became inconsistent with the allocation basis outlined in that report. Notwithstanding,
CitiPower had stated that the basis of allocation was the KPMG report.
•
y
The Commission requested CitiPower to demonstrate through its working papers
why its allocation is consistent with the allocation in the KPMG report. CitiPower
has not provided the information. The Commission has therefore made an adjustment
to ensure consistency with the basis of allocation outlined in the KPMG report.
y
CitiPower considers that it is inappropriate to make adjustments to the information
reported in 2000 because the allocation methodology only applied from 2001.
Although the methodology did only apply from 2001, the purpose of these
adjustments is to compare the costs of providing the distribution services over time
on a like for like basis. Because the adjustment in 2000 is only relied on for
comparison purposes and does not affect the calculation of the efficiency carryover
amounts, the Commission continues to consider this adjustment to be appropriate to
compare the information on a ‘like for like’ basis.
For Powercor, some retail related costs were removed in years prior to it divesting itself of
the retail activities, particularly for bad and doubtful debts. Powercor does not agree with
the adjustments for bad and doubtful debts and considers these costs to be a reasonable cost
for the distribution business to incur. The Commission notes that the benchmarks include a
nominal amount for bad and doubtful debts (approx $40,000). However, these costs would
be expected to directly attributable to the distribution business. Therefore, where the costs
recorded result from an allocation rather than a direct attribution, they have been removed.
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•
For SP AusNet,56 the removal of some retail costs that appeared to have been
inappropriately allocated to the distribution business, particularly in relation to customer
service.
It should also be noted that, where errors in the Commission’s adjustments for the Draft Decision
have been pointed out by the distributors, these have been corrected.
The forecasts of the distributors’ expenditure for the 2006-10 regulatory period are exclusive of
the costs associated with any retail functions. Therefore, the Commission anticipates that these
adjustments may continue to be required for price review purposes to enable out-turn
expenditure to be compared with estimates on a consistent basis in future regulatory periods
where a distributor continues to operate a retail business (as is the case with, for example,
AGLE).
5.2.2 Allocation between prescribed and excluded services
Prior to 2001, metering data services and the repair, maintenance and replacement of public
lighting were classified as prescribed services. However, these services were reclassified as
excluded services as part of the last Price Review and were therefore not included in the
2001-05 expenditure benchmarks.
During its review of the distributors’ Regulatory Accounting Statements, the Commission
identified that some of the distributors had continued to allocate operating and maintenance
expenditure for metering data services and public lighting, and capital expenditure for public
lighting, to prescribed services during this current regulatory period. The Commission has
therefore made adjustments to the information reported in the relevant distributors’ regulatory
accounting statements to address these allocations.
In response to the Draft Decision AGLE and United Energy identified some errors with the
adjustments the Commission had made regarding this allocation of costs. These businesses have
re-submitted work papers to support the allocation errors and the adjustments have been updated
accordingly.
5.2.3 Capitalisation of indirect (corporate) overheads
While the Commission does not prescribe the capitalisation policy adopted by distributors, it
does require disclosure of that policy in the distributors’ regulatory accounting statements. The
Commission notes that the capitalisation policy impacts the classification of these costs rather
than their level, although it does impact the timing as to how these costs are recovered. Further,
the different treatment of rewards for capital and operating efficiencies under the efficiency
carryover mechanism requires consideration of changes in capitalisation policies compared to the
capitalisation policy included in the 2001-05 benchmarks.
56
Formerly TXU
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The regulatory accounting statements submitted by the distributors indicate that they adopted
different capitalisation policies to those assumed in the 2001-05 benchmarks and that, in the case
of AGLE, the policy has varied over the 2001-05 regulatory period. In 2000-03, changes to
AGLE’s capitalisation policy have resulted in a movement of operating and maintenance
expenditure to capital expenditure.
A specific issue relating to the distributors’ capitalisation policies is the capitalisation of indirect
(corporate) overheads. Some distributors (namely, AGLE, CitiPower and Powercor) capitalise
some of these costs whilst others expense them in total.
The review of the distributors’ Regulatory Accounting Statements has revealed that the policy
adopted by some distributors on the capitalisation of indirect (corporate) overheads differs from
the policy assumed in the setting of their 2001-05 expenditure benchmarks. The benchmarks for
the 2001-05 regulatory period were based on an assumption that all indirect (corporate)
overheads would be expensed. Therefore, the Commission has made adjustments to the
benchmarks for the purposes of determining the efficiency carryover amounts to correct for the
variation in the capitalisation policies.
In establishing the forecasts for the 2006-10 regulatory period, the capitalisation policies
assumed in the forecasts need to be explicitly identified and, if a different approach is
foreshadowed, incorporated in the forecasts. This is discussed further in Chapter 7.
5.2.4 Movements in provisions
Provisions are taken by the distributors in order to recognise a future liability now. The
distributors have a range of provision accounts for, for example, employee entitlements,
environmental obligations, safety obligations, doubtful debts and obsolete stock. Each year the
distributors assess the balance of these provisions. They pay liabilities from the provision
accounts, increase the balance of the provision accounts through a charge to profit and make
other adjustments to the provision accounts.
In the Draft Decision, the Commission reversed all movements in provisions charged to the
profit and loss statement and substituted the relevant cash outgoing. This resulted in expenditure
being recorded in the year it is incurred rather than when the provision is changed. This
regulatory adjustment has a significant impact on the year by year reported expenditure profile as
some of the yearly movements in provisions are in excess of $10 million.
In response to the Draft Decision, the distributors generally disagreed with the Commission’s
approach to reversing movements in provisions because they considered that it may not provide
sufficient levels of operating expenditure. For example, SP AusNet (2005f, p. 33) stated that,
Under the Commission’s proposed treatment of provisions, the distributor faces the cost of
meeting the obligation and is not funded.
While provisions are a necessary aspect of accrual accounting, they may also be used to
represent the reported accounts of the business differently from its underlying economic
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circumstances. Moreover, they may prevent and distort the comparison of distributors on a
consistent basis from year to year and across distributors.
In addition, the Commission notes that, if it were to factor provisions into forecasts of
expenditure, compensating adjustments to the regulatory asset bases would also become
appropriate to reflect the change in future liabilities that have been provided for. This would
parallel the effect of movements in provisions on the balance sheet of entities under standard
financial accounting practices. Thus, if a net increase in provisions was forecast, a downward
adjustment to the regulatory asset base in each year would be required. Such an adjustment
would be very complex and only change the timing of a distributor’s cash flow, not its value.
Movements in provision amounts may also advantage one business over another. For example,
Powercor and CitiPower have taken significant provisions for safety compliance obligations —
$27.1 million in 2001 and $12.3 million in 2002, respectively (in nominal dollars). Other
distributors have not taken similar provisions, even though they have similar liabilities. By
reversing the movements in these provisions, expenditure for safety is accounted for in the year
in which it is incurred. If these provisions are not reversed, expenditure appears higher for
Powercor and CitiPower relative to the other distributors in 2001 and 2002 respectively, but
comparatively lower in subsequent years.
Further, movements in provisions can be affected by a change in accounting standards despite
expenditure remaining the same. An example of this is the introduction of International Financial
Reporting Standards (IFRS) which will affect the calculation of provisions for stock
obsolescence, doubtful debts and other items. For some of the distributors, the changes have
already occurred. By reversing the movements in provisions, the Commission is able to assess
expenditure in a form that is not impacted by a change in accounting standards.
The Commission is satisfied that its framework and approach for determining operating
expenditure estimates takes such liabilities into account. For example, where there are
expectations about changes in future expenditure requirements for safety compliance, these are
included as step changes to the base operating costs. Equally changes in expenditure in employee
entitlements are included in the approach to the rate of change. The rate of change is already
influenced by the historic trend that has occurred in relation to employee entitlements and
incorporates expected increases in labour costs and so, in adjusting base operating costs for the
rate of change, expectations about movements in employee entitlements are taken into account.
5.2.5 The market price for services
Regulatory Accounting Statements submitted by the five Victorian electricity distribution
businesses reflect the fact that a number of the businesses have entered into contracts with other
parties to provide a significant proportion of their distribution services. The use of these
arrangements has also been increasing over time. Where these other parties are identified as
related parties, the Regulatory Accounting Statements report the value of these contracts, rather
than the costs incurred by the related service provider in providing the services.
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The proportion of operating and maintenance and capital expenditure that was reported as
services provided by related parties by the Victorian distributors in 2003 and 2004 is set out in
Table 5.4. Information relating to related parties was not collected prior to 2003.
Table 5.4:
Related party transactions as a proportion of operating and capital
expenditure, all distributors
2003
2004
AGLE
94%
96%
CitiPower
29%
69%
Powercor
0%
9%
TXU
1%
3%
United Energy
55%
97%
Note: This information is based on the information reported in the Regulatory Accounting Statements of the
distributors. The United Energy information for 2003 and 2004 includes information that was provided in a letter
from Alinta Ltd dated 26 July 2005.
The role of related party contracts is an emerging issue across regulated industries and across
jurisdictions as a result of the corporate restructuring and integration that has occurred in the last
few years, and has been identified as such by the Productivity Commission (2004, p. 458-459).
In some cases, service providers have contracted out the role of operating and/or
managing the pipeline to an associate. Agility, for example, manages the distribution
assets of AGL Gas Networks in New South Wales. Agility and AGL Gas Networks are both
wholly owned subsidiaries of the parent company AGL.
Under such a structure, the asset manager can engage in inappropriate transfer pricing,
undermining the process of setting appropriate reference tariffs. Such transfer pricing
occurs when a regulated service provider pays the associated asset manager an inflated
price in order to raise its own cost structure, thus increasing the reference tariff for
services provided by the regulated business. The affiliated asset manager makes inflated
profits, which are ultimately passed through to the parent company.
These arrangements have the potential to allow for a greater than intended proportion of the
benefits of any efficiency gains to be retained within the corporate group that includes the
regulated business and the related service provider. If inflated charges paid to the related party
are accepted as representing the costs of providing the services, not only are any efficiency gains
made in the provision of services by the related service provider not returned to customers, but
customers will actually pay more for the services than otherwise would be the case.
In the Draft Decision the Commission indicated that, where the reported information included
additional fees or transfer prices that do not represent the cost of providing the distribution
services, it would make an adjustment based on the costs incurred by the related party in
providing distribution services.
The Commission’s approach to considering the underlying costs incurred by related parties in
providing services to the distributors is supported by various stakeholders. In its submission to
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Final Decision
the Position Paper, the Energy Users Coalition of Victoria (EUCV) (2005b, p. 19) stated that any
efficiency gain that is earned must not be left to enhance the distributor’s or contractor’s profit
margin and should be returned to customers. Similarly the Victorian Consumers’ Group (VCG)
(2005, p. 7) stated that the distributors’ owners should not
…be permitted to use a legal or accounting artifice to prevent consumers from obtaining
benefits that the Commission is required by law to deliver to them.
The appropriate identification and treatment of related party contracts and the impact of transfer
pricing between related parties is recognised as a significant issue worldwide for regulators and
government collection agencies.
For example, revenue authorities around the world are developing their transfer pricing audit
skills to capture what they regard as their proper share of tax on profits from the rapidly
increasing volume of international trade, especially in services and intangibles. The Organisation
for Economic Co-operation and Development (OECD) has proposed that related parties operate
at “arm’s length” when establishing a reasonable transfer price and this approach has been
agreed by its member countries including Australia. The Australian Tax Office (ATO) has
devoted considerable resources to addressing the transfer of profits out of Australia, primarily
through the mechanism of inter-company and intra-company transfer pricing. It considers that
transfer pricing may have the effect of depressing assessable income or increasing allowable
deductions.
This issue also needs to be addressed in regulation. Regulated entities may enter into
arrangements with unregulated entities that depress the assessable efficiency benefits or increase
the magnitude of costs to be recovered to ensure any profits are retained in the unregulated entity
rather than the regulated entity.
The analysis undertaken in the lead up to the Draft Decision relied primarily on the Regulatory
Accounting Statements from 2000 to 2003. However, the 2004 Regulatory Accounting
Statements that were provided at the end of April 2005 and the information in these statements
led to the Commission identifying that the issues associated with the use of related party service
providers were more substantial than in the earlier years. To address these issues the
Commission, in the Draft Decision, made adjustments to the reported expenditure of CitiPower,
Powercor, AGLE and SP AusNet to reflect its estimate of the profit transfers that might exist in
the arrangements they had entered into with related parties. For United Energy, the Commission
signalled that it was investigating further. The Commission also signalled the importance of
arm’s length tender processes to testing the market price.
The regulatory approach adopted by the Commission in relation to the treatment of contracts for
the provision of services to distributors, including where those services are provided by a related
party, must have regard to the objectives of the Commission’s regulatory framework and
approach – namely, to measure efficiencies for the purpose of establishing the efficiency
carryover amounts and to identify the relevant costs for the purpose of establishing the
distributors' forward-looking revenue. The achievement of those objectives requires the
Commission to determine the costs that are incurred in providing the distribution services. In
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establishing the costs that are to be taken into account for this purpose, the Commission must
reach a view on whether those costs should be established by reference to:
•
the price charged by any third party service provider to the distributor for providing those
services; or
•
the costs incurred by that third party service provider in providing those services.
It is not the Commission’s intention to prevent or prohibit arrangements between distributors and
third parties for the supply of services but rather to ensure that they do not result in customers
paying more because of them.
Indeed, the Commission recognises that, in the normal course of providing distribution services,
a distributor may find it beneficial to enter into arrangements with third parties for the supply of
certain services. However, the Commission expects that such arrangements would only be
entered into where the services could be provided more efficiently than if the distributor
provided those services itself. It also expects that, in entering into any such arrangements, the
distributor would seek to secure the best possible price from the market.
In establishing whether to take into account the price charged or the underlying costs, the
Commission must consider three fundamental questions:
•
Is there a competitive market for the services?
•
Is there an incentive for the distributor to enter into the arrangements on an other than
arm’s length basis?
•
Was a competitive tender process conducted to establish the price for the service?
The importance of each of these questions varies based on the answer to these questions as
follows:
•
Competitive markets tend to generate benefits for customers. Competitive rivalry among
suppliers creates strong incentives to produce and price efficiently. Choice amongst
available alternatives allows customers to select the offered products that best satisfies
their preferences. If the outsourced services in question were provided in a competitive
marketplace, the Commission can have a high degree of assurance that the outsourced
services are being provided efficiently and that the prices charged for these services reflect
a competitive market price.
•
If the services are not provided in a competitive market, then there is no market price for
the services and the only relevant consideration is the costs incurred. Any other approach
would involve a subjective valuation of the services that may be influenced by the
incentives of the parties involved.
•
If the services are provided in a market, then the incentives of the parties involved in the
arrangements become important. If there are no incentives for the parties to enter into
arrangements that are other than arm’s length, then the contracted price can be taken to be
a good proxy for the competitive market price. However, if there is an incentive for the
parties to enter into arrangements that are other than arm’s length, then the means by which
the price was established become important.
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•
Where there is an incentive for the parties to enter into arrangements that are other than
arm’s length then, if the services have been subject to a competitive tender process the
contract price can be taken to be a good proxy for the competitive market price. If a
competitive tender has not been conducted, then the costs incurred in providing the
services are the most practicable point of reference for determining the economic value of
the services. In principle, it may also be possible to use direct market evidence, if it is
established at the outset that sufficiently similar services are provided in a market.
However, whether this is possible will depend on whether the direct market evidence is
sufficiently comparable taking into account the nature of the services, their quantity, the
terms of the transactions and the incentives of the parties.
The following diagram is provided to illustrate these considerations:
Are the services
provided in a
competitive market?
Yes
Contract price is
relevant
Yes
Does an incentive
exist to enter into an
arrangement that is
not arm’s length?
No
Yes
Has an arm’s length
open tender process
been conducted?
Yes
No
Costs are relevant
Where the Commission must rely on costs (ie. where there is no market price either because
there is no market for the relevant services or because such a price has not been established
through an appropriate process), the building block cost components are taken to be the
appropriate representation of the economic value of the services. These components include a
reasonable return on capital consistent with this Determination. This means that where the
service provider uses regulated assets to provide the services, this return should not be
duplicated.
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A market for the services
In considering the framework identified above, it is helpful to clarify that a market is the area of
close competition between firms or the field of rivalry between them. Within the bounds of a
market there must be the potential for substitution — between one product and another, and
between one source of supply and another — in response to changing prices.
The process of defining markets usually involves the specification of four dimensions:
•
a description of the product or service that is being or could be provided;
•
the functional level at which that product or service exists in the supply chain, which is
important for distinguishing the different vertical stages of a production process at which
alternative suppliers may potentially compete;
•
the geographic area over which the product or service is or could be bought or sold; and
•
the time frame over which the product or service is or could be provided.
Economic principles define the boundaries of a market. At one end of the spectrum, for products
or services to be provided in a market, there must be actual or potential transactions between
multiple potential buyers or sellers of those products or services, with the potential for these
transactions to be repeated over time. A single, one-off transaction between two specific parties
is not sufficient to constitute a market.
At the other end of the spectrum, the boundaries of a market are determined by the extent to
which particular products or services form close substitutes for one another. If buyers are
unwilling to substitute one product or service for another in response to a small but significant
increase in the price of one of them, then those products or services are said to be in separate
markets.
In applying these principles to the analysis of services that may be outsourced by an electricity
distributor, whether or not a particular set of services can be said to be provided in a market is
also likely to depend on the extent to which potentially separate services are bundled together.
By way of example, office stationery, billing systems, network maintenance services, call centre
services and IT hardware might each be said to be provided in separate markets. However, the
wider the range of services that is bundled together for provision under a single contractual
arrangement, the less likely it is that such a bundle of services can be said to be provided in a
market. This is because the more heterogeneous is the bundle of products or services, the
narrower will be the field of potential buyers and sellers of that bundle.
Evidence of whether or not there is a market for a particular set of services that has been or will
be outsourced will depend upon:
•
the existence of transactions or evidence of potential transactions involving multiple
potential buyers and sellers; and
•
the bundle of services being considered, and the extent to which those services are being
sought or offered in a way that prevents them from being separated into a number of
individual services.
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If services are bundled into an outsourcing contract in such a way that there is no market for the
services encompassed by that contract, then:
•
market testing will not be possible, since there is not a sufficient number of alternative
providers against which to test the price being proposed; and
•
for the same reason, there will be no ‘market’ price.
Where there is no market price, then the economic value of the services being provided can only
be properly determined by reference to the costs of the service provider.
Incentives to enter into arrangements that are other than arm’s length
The incentives to enter into arrangements that are other than arm’s length are most apparent
where a distributor contracts with its related party. In this circumstance any variation between
the charges and the costs incurred in providing distribution services represents a transfer of
benefits from the regulated distributor to the related party. This transfer prevents these benefits
from being returned to customers.
However, there may be other circumstances that give rise to an incentive to enter into
arrangements that are other than arm’s length. One such example may be the existence of a
related transaction where the price for different parts within a set of transactions has been
determined simultaneously. The Commission recognises that, as regulation evolves, businesses
may become more sophisticated in seeking out arrangements that increase their share of any
benefits achieved under the regulatory framework. It is likely to be difficult for a regulator to
identify and address all of the possibilities. Where there is reasonable doubt as to whether or not
there are incentives to enter into arrangements that are other than arm’s length, it may be
appropriate that costs should be examined as a routine measure.
Open competitive tender
Where there are incentives to enter into non-arm’s length arrangements, the Commission
considers that market testing can only be properly applied where the services are procured under
an open competitive tender. In this circumstance the arrangements should be beyond reproach. It
is only then that the Commission can be assured that the contract price represents the market
price. Benchmarking or independent review, which typically involves subjective judgements,
cannot provide the necessary degree of confidence where there is an incentive for the parties to
achieve distorted outcomes.
This is a view shared by Ofwat, the economic regulator for water and sewerage services in
England and Wales. Its Regulatory Accounting Guideline on transfer pricing in the water
industry includes principles that transfer prices for transactions between the regulated water
business and the related party must be based on market price or less. For this purpose the
Guideline also indicates that market testing is to be used to establish market prices for supplies,
works and services provided to the regulated water business and discusses the principles for
market testing. The principles outline that there are a number of methods of market testing
including:
•
Competitive letting;
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•
Comparison to published list prices;
•
Third party evaluation; and
•
Benchmarking.
However, Ofwat found that market testing by all but competitive letting did not demonstrate
arm’s length trading because a large element of subjectivity was involved and comparisons were
not always made on the basis of the same type and volume of supplies, works or services. Ofwat
concluded that competitive letting was the only means of market-testing which objectively tested
and preserved the competitive market, and that all other methods tended to compare a
predetermined price with the market, as a means of justifying the original price. Competitive
letting avoids this problem as it inherently discovers the market price without interference in, or
judgement of, the market. Ofwat recognised that there may be circumstances where competitive
letting is impracticable but that in these cases documentation should be provided to satisfy Ofwat
that transfer prices are at market rates (Ofwat 2005, p. 11).
Where no market exists for particular supplies, works or a service, or the business does not
choose to test the market for that service/good, Ofwat is of the view that the related party
contract should be based on cost. Ofwat (2005, p. 10) deems the cost to be:
The actual cost to the supplier of the goods, works or services plus a rate of return on
capital.
Ofwat made downward adjustments to declared costs at the 1999 and 2004 Price Reviews
because companies were unable to demonstrate arm’s length trading due to weaknesses in their
processes for market-testing related party contracts, or because the competitive contract letting
process was not set down in advance of entering into the contract.
In a confidential submission, CitiPower pointed out that the Commission’s Regulatory
Accounting Guideline does not require market testing to be undertaken or specify the nature of
the market testing. This is true. However, the purpose of the Regulatory Accounting Guideline is
to require the provision of information which is necessary to achieve transparency and assist
understanding of the Regulatory Accounting Statements. Its purpose is not to prescribe a
regulatory methodology — that is a matter for the price review.
CitiPower also raises the approach adopted by the Australian Taxation Office (ATO) which
allows many ways of determining arm’s length prices between related parties. The arm’s length
principle referred to by the ATO requires comparison of the conditions that exist in the
commercial and financial relations between associated enterprises with the conditions that might
be expected to operate between independent parties dealing wholly independently with each
other.
This is not dissimilar to the Commission’s approach which first seeks to understand if there is a
market for the services (that is, can the services be provided by an independent party). The
preference of the ATO is to compare the prices or margins achieved by associated enterprises in
their dealings to those achieved by independent enterprises for the same or similar dealings,
recognising that there are many matters that may influence the prices or margins. In these
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circumstances the dealings being compared and circumstances of the parties involved need to be
closely examined.
CitiPower itself sought information on the market for the services currently provided internally
to CitiPower and Powercor. A report was prepared by PricewaterhouseCoopers (PwC) (and
provided confidentially to the Commission). This report outlined a number of issues in
determining a ‘market tested’ price for these services. These included:
•
limited service providers able to provide the service as specified;
•
limited ability to seek comparisons with the services;
•
lower prices may have been available when management costs are excluded;
•
the outsourced market has a ceiling of the current costs of providing the services;
•
robust data in relation to defined services is only obtainable under situations where the
particular service is subject to tender for outsourcing;
•
it is important to consider the full impact of outsourcing services in the context of the risks
that are transferred between the service provider and the company, and the service
provider’s relative incentive to achieve the longer term corporate goals and strategies of the
company.
In conclusion, PwC was not able to make a meaningful comparison of the costs, risks and
rewards available and without this comparison found it impossible to assess the merits of
outsourcing services because the cost of outsourcing could not be assessed against the current
cost of service provision.
A number of the submissions by the distributors to the Draft Decision provided information on
the market testing that is claimed to have been undertaken in relation to outsourcing contracts
entered into by the distributors, and how the contract value had been established. In some cases
the services provided are not provided in a market. In other cases, there is a clear incentive to
enter into arrangements that are other than arm’s length due to the relationship of the distributor
to the provider of the services. The situation of the individual distributors is discussed below.
CitiPower and Powercor
CitiPower and Powercor are owned by the same company. CitiPower purchases a range of
services from Powercor including management, administration, back office, IT,
telecommunication, construction, and maintenance services. Conversely, Powercor purchases
services from CitiPower for back-office resources through a resource agreement. The
relationship between CitiPower and Powercor means that there is a clear incentive for them to
enter into arrangements with each other that are not arm’s length. This has led the Commission
to assess the process undertaken to establish the contract price at which the services to each other
are provided.
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CitiPower57 states that its agreements with Powercor were developed and approved by each party
acting independently to comply with criteria established by CitiPower and Powercor. It claims
that it is erroneous to equate market testing with competitive tendering. Instead, it states that the
charges for these services have been market tested or are at market rates because they have been
based on benchmarking or independent review. The benchmarking has been based on the work
of KPMG which has aimed to estimate the efficient costs of providing the services. For back
office costs particularly, the price has been established using the mid-point of the range for each
possible service.
CitiPower has also provided information which indicates that there is no single service provider
capable of providing to CitiPower all of the services provided by Powercor and that this is a
reason why competitive tendering was not adopted.
The Commission considers this to be evidence that the services are not provided in a market, and
that there is no market price for these services. In that circumstance, for the reasons discussed
above, the Commission will only consider the costs of providing the services and has made
consequential adjustments for this purpose to CitiPower’s reported information.
In one instance, CitiPower pays a management fee for the use of an IT asset in Powercor’s nonregulated asset base. The fee charged is significantly greater than the financing costs associated
with the asset. The Commission has therefore made an adjustment to CitiPower’s capital
expenditure based on the cost of the asset and removed the fee charged from operating and
maintenance expenditure.
The Commission has sought information regarding whether there are any other non-regulated
assets utilised by CitiPower or Powercor in providing services to each other. Correspondence
indicates that there are none. Therefore, no return on capital has been included in relation to the
cost incurred in providing any of these other services. Where regulated assets are utilised in
providing services, a return on these assets is included in the revenue requirement.
In so far as the services provided by CitiPower to Powercor are concerned, CitiPower has
provided the Commission with the costs of providing back-office resources through the resource
agreement. This information indicates that the charge reflects these costs. Therefore, no
adjustment has been made to Powercor’s reported information in this regard.
CitiPower and Powercor each purchase a Discretionary Risk Management Scheme from a related
company, CKI/HEI Electricity Distribution (Services) Pty Ltd (CHED), reportedly to insure
against the payment of an excess on existing insurance policies. The information provided by
CitiPower and Powercor indicates that there is no market price for this service as it is not
available in a market. The reason there is no market is that the availability of such a service
would remove any incentive for the insured to manage their risk and would result in the insured
claiming all incidences regardless of their significance. The Commission has therefore
considered only the costs incurred by CHED in providing these services. However, an allowance
for self-insurance has been incorporated in the forecast operating and maintenance expenditure
as discussed in Chapter 6.
57
The views of CitiPower were outlined to the Commission in their confidential Related Party submission.
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CitiPower and Powercor have submitted that, in so far as they provide services to each other, the
costs which the Commission should take into account are the payments made by each of them to
the other. They contend that the failure to take into account any margin would mean that the
Commission has not taken into account the costs and risks incurred by the shareholders of
CitiPower and Powercor in making the multiple acquisitions that are the source of the cost
savings reflected in the margins. The submission proposes that, where the strategies and actions
of the shareholder mean that Powercor can lower the cost of service delivery to CitiPower, then
that is a matter for the shareholders, not CitiPower, and that the shareholders’ gains should not be
shared with CitiPower’s customers. The Commission notes that it is these cost savings that its
approach is designed to return to customers after they are retained by the distributor for five
years through the efficiency carryover mechanism. To do otherwise would result in the
shareholders of CitiPower and Powercor retaining those savings indefinitely.
AGLE
The majority of services provided to AGLE are provided by Agility or other AGL companies.
These services relate to all aspects of the provision of distribution services. This package of
services is unlikely to be available in a market. Additionally, the joint ownership between AGLE
and its service providers results in an incentive for arrangements to be entered that are not arm’s
length.
AGLE has indicated that the charges for the arrangements between AGLE and Agility, at least
for 2003 and 2004, were based on the benchmarks established at the last price review. Since the
Draft Decision, AGLE has provided information on the costs incurred by the AGL group in
providing distribution services to AGLE.
For the reasons given above, the Commission has made an adjustment to reflect the costs
incurred by the AGL group in providing services to AGLE.
SP AusNet
SP AusNet has an arrangement in place with Tenix for the provision of construction and
maintenance services. This arrangement accounted for nearly 40 per cent of the expenditure
undertaken by SP AusNet in 2004. Tenix is one of many providers of these services and it also
provides these services to other parties. This suggests these services are provided in a market.
The Commission has considered the ownership structure of Tenix and notes there is no common
ownership between Tenix and SP AusNet. Therefore, there appears to be no incentive for SP
AusNet to enter into an arrangement with Tenix that is other than arm’s length. Accordingly, the
Commission is satisfied that it is appropriate to take into account the contract price for these
services.
SP AusNet also purchased corporate services from its related entity, SP Energy in 2004. It is
unlikely that these services are provided in a market and there is an incentive for the
arrangements to be other than arm’s length. Therefore, for the reasons given above, the
Commission has made an adjustment to reflect the costs incurred by SP Energy in providing
these services.
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United Energy
The United Energy group was restructured in July 2003 with Aquila exiting the Australian
market. United Energy is now 100 per cent owned by a holding company (PPL) which in turn is
100 per cent owned by United Energy Distribution Holdings (UEDH). UEDH is owned by
DUET (66 per cent), which is a listed entity managed jointly by AMP Capital Investors and
Macquarie Bank, and Alinta (34 per cent).
United Energy acquires most of its operating and maintenance services and capital expenditure
service requirements from Alinta Network Services (ANS), a wholly owned subsidiary of Alinta.
In this regard, it is noted that information provided in the Regulatory Accounting Statements of
United Energy does not seem to accurately reflect the magnitude of the proportion of expenditure
associated with services provided by ANS. The Draft Decision indicated that the proportion of
operating and capital expenditure represented by charges to related parties (including ANS) was
52 per cent in 2004. Information provided later indicated that the actual proportion is closer to
100 per cent.
United Energy also acquires management and corporate services from UEDH, which in turn
acquires these services from Pacific Indian Energy Services (which is majority owned and
controlled by DUET), AMP Capital Investors, Macquarie Bank and Alinta.
United Energy itself has no employees.
In the Draft Decision, the Commission referred to the arrangements between ANS and United
Energy as a related party arrangement. The reference to ANS as a related party of United Energy
reflected the identification of ANS as a related party in the Regulatory Accounting Statements
submitted by United Energy. The Commission received a confidential submission from ANS
indicating that it did not consider itself to be a related party of United Energy. However, United
Energy has since confirmed that, for the purposes of the Regulatory Accounting Statements,
ANS is a related party of United Energy.
Nonetheless, United Energy has indicated that it considers that the definition of related party in
the Regulatory Accounting Statements is a technical issue and of limited practical value because,
even if ANS and United Energy are now related, they were not when the arrangements were
entered into. In its view this definition is not relevant as to whether the Commission should
accept the value of the contract rather than the costs incurred by ANS in providing the services
under the contract, and that, even if it is incorrect in this regard, the relevant service provision
arrangements have been market tested.58
United Energy has provided information to the Commission to the effect that59:
•
58
59
The transaction, of which the arrangement between ANS and United Energy for the
provision of distribution services was a part, involved an ownership reorganisation (by way
of a scheme of arrangement) of United Energy, MultiNet and AlintaGas Networks. This
transaction involved DUET and Alinta assuming ownership of the United Energy group.
Disclosed in a letter from Hugh Gleeson of United Energy, 16 September 2005.
Provided in a confidential submission by United Energy, 8 April.
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The cost to Alinta of acquiring its shareholding in the United Energy group was
$570 million, and the entire transaction involved an investment of $1.5bn. United Energy
has also indicated that the scheme of arrangement was approved by the Supreme Court.
•
The transaction between ANS and UED ultimately led the entire United Energy workforce
(except the Chief Executive Officer) and a significant amount of related operating and
maintenance costs to be transferred from United Energy to ANS.
•
Conducting an open competitive tendering process for the provision of the services
required by United Energy was not practical because of the requirement for the service
provider to acquire equity, the specific nature of the skills required from the service
provider, the insufficient time available to undertake such a process and the confidential
nature of the transaction.
•
However, the competitive pressures and commercial and governance drivers existing at the
time of the reorganisation meant that the arrangements were market tested and were
efficient. Further, support for the arm’s length nature of the United Energy/ANS
arrangements is derived from the fact that the transactions required the approval of a
number of other parties including directors and independent experts.
In some respects, however, this information serves to demonstrate that these services are not
provided in a competitive market:
•
The agreement for the provision of services by ANS to United Energy was not provided in
a competitive marketplace and was itself not market tested but rather was entered into as
part of a larger transaction.
•
The larger transaction involved the simultaneous determination of the price at which equity
was to be transferred and the price for which the services were to be provided.
•
The larger transaction involved the simultaneous sale of, and acquisition of services for,
electricity and gas network businesses.
•
The parties who approved the transactions had no responsibility to have regard to the
interests of United Energy's electricity distribution customers. In particular the
Commission notes that the interests of the shareholders in the United Energy group and of
the customers of United Energy's distribution network business are not aligned where
arrangements can be entered into under which the shareholders are able to retain those
benefits that, under the regulatory framework, would otherwise be shared with the
customers.
•
The reasons provided as to why a competitive tender was not practicable appear to support
the proposition that there is no market for the services that were agreed to be provided by
ANS to United Energy as part of the transaction.
A one-off transaction that bundles both the provision of services and the acquisition of equity
does not occur in a market. In that context, there is no reason to believe that the price at which
the services are provided properly represents the underlying economic value of those services
because:
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•
the ‘price’ of one component of the transaction (the services) was determined
simultaneously with the other (the equity); and
•
there is no market (within which prices can be observed) for the services component in its
own right.
In addition, the service provider ultimately acquired almost all of the employees (save one) that
were previously employed at United Energy and related operating expenses. Because these costs
were reallocated among related parties, the arrangements could be viewed as cost-shifting from
United Energy to ANS rather than an outsourcing of services to an independent contractor.
United Energy provided a submission to the Commission which included a report from Frontier
Economics considering the question of whether United Energy’s acquisition of services from
ANS occurred in a market. The report by Frontier Economics found that:
… a central conclusion ….. that ‘there is no market for the services that were agreed to be
provided by ANS to UED’ would be incorrect.60
To draw this conclusion, the report appears to rely on assumptions which may mis-characterise
the nature of the arrangements:
•
that United Energy and ANS are autonomous independent entities;
•
that the services provided are asset management services, primarily managing contracts
with third party providers, with ANS employing some resources to provide services
directly; and
•
That the price paid for the supply of services is less than the prior cost of acquiring those
services and there are savings through these arrangements.
The Commission notes that the report has defined a market in such broad terms that it finds that
even a price paid to a monopoly provider constitutes a market price. This approach to the
definition of a market is not useful in the context of the framework for regulating Victorian
distribution charges. Instead, given that the Commission’s regulatory function arises precisely
because the electricity distributors are monopoly service providers and are, therefore, not subject
to the competitive constraints that arise from a market, for its purposes, the Commission
considers that a reasonable assumption is that a market should be workably competitive.61
Even if the United Energy/ANS arrangements provide for the provision of the services to be
subsequently renegotiated independently of the continued holding of the equity stake (noting that
United Energy has little capacity of its own to determine the merits of the pricing or service
standards due to the absence of direct employees), the future price that may be struck for such
services will only be capable of representing the underlying economic value of those services if
there is a market for them. The requirement to provide substantially all of the services needed by
60
61
Frontier Economics, Did United Energy Distribution’s acquisition of service from Alinta Network Services occur in a
market?, 10 October, Melbourne. (Confidential)
See discussion on a workably competitive market: Re Dr Ken Michael Am; Ex Parte Epic Energy (WA) Nominees Pty Ltd &
ANOR, WASCA 231, 2002.
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United Energy requires the provision of a bundle of services that is so heterogeneous it cannot be
said to be provided in a competitive market.
For these reasons, the Commission does not consider that there is a market for the services.
In addition, there was an incentive to enter into the arrangements on an other than arm’s length
basis due to the simultaneous transaction for equity, and the arrangements were not entered into
through a competitive open tender process for the services.
Accordingly, for the reasons given above, the Commission considers that the costs incurred by
ANS in providing the services are the relevant costs to consider for the purpose of calculating the
efficiency carryover amount and forecasting United Energy’s operating and maintenance
requirements.
Given this conclusion, the Commission would prefer to rely on information provided by the
distributor and/or its service provider on the costs incurred for this purpose. The Commission
therefore requested that ANS provide it with information on the costs incurred by ANS in
providing services to United Energy. However, ANS indicated that it does not keep its
accounting records in a manner that enables it to readily identify these costs, and refused the
further requests of the Commission to provide any information on such costs that it may have.
This is cause for further concern about the validity of the charge in representing the economic
value of the services.
In the absence of reliable information on the costs incurred by ANS in providing services to
United Energy, the Commission must make an estimate of the costs that were incurred. For the
purposes of measuring efficiencies over the 2001-05 regulatory period and estimating the costs
for the 2006-10 regulatory period, the Commission considers that the most appropriate
information to use to estimate the relevant operating and maintenance costs is that contained in
the Regulatory Accounting Statements provided prior to 2003 (the year the ANS/United Energy
contract was entered into) - that is, the Regulatory Accounting Statements for the period 2000 to
2002 – as such information has been adjusted by the Commission for the reasons given earlier in
this Chapter. In arriving at its estimate, the Commission has used the average costs reported by
United Energy over the period 2000 to 2002 to address the possibility that costs in any one year
may be less representative than another. This average has then been rolled forward to 2006 based
on the rate of change and impact of growth over the 2002 to 2006 period. This approach, as
applied for 2005 to 2010 period, is outlined in Chapter 6.
In response to this approach62, United Energy has indicated to the Commission that the
information for 2000 to 2002 is unlikely to represent an appropriate estimate due to:
•
it including information from a previous regulatory period;
•
the existence of a cross subsidy from the non-distribution business to the distribution
business during this period due to the requirements of the Regulatory Accounting
Guideline;
62
The Commission received further information from United Energy on 14 October outlining the adjustments that they
suggest would need to be made to the pre-2003 data for it to appropriately represent the 2003 and 2004 costs.
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•
costs in previous years reflecting the lower costs of an integrated business;
•
the sale by Aquila which may have depressed the expenditure in 2001 and 2002;
•
the Aquila management fees representing fees for service rather than profit transfer; and
•
the increases in insurance and regulatory costs since 2002.
The Regulatory Accounting Guideline does not prescribe any particular allocation methodology.
As outlined earlier in this Chapter, it is a principle based guideline requiring disclosure. If any
subsidisation was occurring, it would have represented the allocations considered reasonable by
the regulated distributor, or have been addressed through the adjustments the Commission has
made to the regulatory accounting information in this Chapter. The reason the Commission has
considered information from the 2000 Regulatory Accounting Statements is because this
information relates to a year that was estimated — not reported — at the time of the last review.
Further, if there are issues with the information reported in 2001 and 2002, including information
from an additional reporting period is likely to mitigate the impact.
The Commission notes that United Energy has had opportunities to provide information on the
costs incurred in providing distribution services. Given its inability to provide such information,
it is unclear how United Energy has identified the cost increases they have claimed.
The Commission recognises that the information for 2000-2002 may not be entirely
representative of the costs incurred in providing distribution services to United Energy’s
customers in 2003 and 2004 and that its approach is a second best approach. However, the
Commission has been compelled to estimate these costs due to its inability to obtain information
about the actual costs incurred – and inevitably, the process of deriving any such estimate will be
subject to the vagaries of the information used for the purpose of making that estimate. It is for
this reason that the Commission has purposely taken an average so as to mitigate the impacts of
events that might have occurred in one year and not another. With regard to the Aquila
management fees and assertions that costs have increased, the Commission considers that, in the
absence of actual cost information, the 2000-2002 information (as adjusted) provides the best
basis for arriving at its estimate of operating and maintenance expenditure.
Estimating capital expenditure is complex and would not be amenable to the application of the
relatively simple approach outlined above for operating and maintenance expenditure. The
Commission understands that the majority of capital expenditure is undertaken under separate
contracts that are reviewed individually by the Chief Executive Officer (CEO) of United Energy.
It further understands that the charges to United Energy are based on a schedule of rates, the
price previously charged for like work or direct costs incurred.
The Commission has been provided with detailed information on the projects and charging basis
and, for the purpose of this price review, it would be difficult for the Commission to arrive at a
better estimate of these costs than the reported information (with the adjustments that have been
made for the reasons outlined earlier in this Chapter). Accordingly, for the purpose of applying
its regulatory framework, the Commission will adopt United Energy’s reported information on
capital expenditure (as adjusted).
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Arrangements such as those entered into between United Energy and ANS result in ongoing
concerns for the Commission which may not necessarily be addressed through its approach to
assessing the costs incurred. The regulator considers the costs of these kinds of arrangements
potentially result in higher costs to customers as a result of:
•
the transaction costs that are incurred that would not be incurred where the distributor
provided the services itself; and
•
the limited incentives for efficiency where the arrangements result in the distributor being
so dependent on the contractor that the threat of exiting the arrangements is no longer
credible, and therefore the incentives to achieve efficiencies in service provision are
reduced.
There may well be very good reasons for a particular structure adopted by a distributor.
However, the distributor's customers should not be required to bear any additional costs that
might arise as a result of that structure being adopted.
The Commission will therefore consider the existence of these arrangements in continuing to
review its approach to collecting information and licensing, as well as its approach to price
regulation.
Summary
Table 5.5 summarises the adjustments made by the Commission to reflect the approach set out
above.
Table 5.5:
Adjustments in relation to contractual arrangements entered into by the
distributors real $2004
Adjustment and reasons
AGLE
An immaterial adjustment has been made to operating and maintenance and capital
expenditure for the difference between the contract charge and the costs incurred by Agility
in providing services to AGLE in 2003. A $0.2 million reduction in operating and
maintenance expenditure and a $0.1 million reduction in capital expenditure has been made
in 2004.
CitiPower
The following adjustments have been made:
−
$5.8 million adjustment to operating and maintenance expenditure in 2004 and $5.2
million in 2003 for the difference in the charge paid to Powercor by CitiPower and the
costs incurred by Powercor in providing services to CitiPower.
−
$5.0 million adjustment to capital expenditure in 2004 and $4.8 million in 2003 for the
difference in the charge paid to Powercor by CitiPower and the costs incurred by
Powercor in providing services to CitiPower.
−
$0.7 million adjustment to operating and maintenance expenditure in 2004 for the charge
paid to CKI/HEI for self-insurance. Immaterial costs have been incurred in providing
these services.
−
$2.8 million adjustment downwards to operating and maintenance expenditure and $4.5
million adjustment upwards to capital expenditure in 2004 to remove the charge paid to
Powercor in providing the services relating to an IT asset, and to add the cost of the asset
to CitiPower’s regulatory asset base.
(continued over page)
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Table 5.5:
Adjustments in relation to contractual arrangements entered into by the
distributors real $2004
Adjustment and reasons
Powercor
An adjustment to operating and maintenance expenditure of $5.0 million in 2004 that
represents fees paid for in fill insurance services to CKI/HEI Electricity Distribution Services
for in fill insurance services that are in addition to the costs incurred.
SP AusNet
An adjustment to operating and maintenance expenditure of $0.6 million in 2004 to represent
the difference between the fee paid by SP AusNet and the costs incurred in providing
services by SP Energy.
United Energy
The following adjustments have been made:
−
$6.6 million to operating and maintenance expenditure in 2001 and $4.2 million in 2002
for the fees paid by United Energy to Aquila. These amounts represent the
Commission’s best estimate of the difference between the charge paid and costs incurred
in the absence of information on the costs.
−
$8.9 million adjustment to operating and maintenance expenditure in 2003 and $12.3
million in 2004 as a result of the Commission’s estimate of the costs incurred in
providing distribution services in those years.
5.2.6 Other adjustments
Through ongoing discussions with the distributors, errors have been identified in the Regulatory
Accounting Statements submitted by the distributors. Adjustments, which have been supported
by the distributors, have been made to correct for these errors. This includes an additional $2.4
million identified by CitiPower as a duplicated meter reading charge in its operating and
maintenance expenditure in 2004.
There have also been discrepancies between workpapers in the Regulatory Accounting
Statements, and between the Regulatory Accounting Statements and the distributors’ price
service proposals. These discrepancies have been resolved with the distributors and adjustments
have been made to the Regulatory Accounting Statements where appropriate.
5.2.7 Further adjustments to CitiPower and Powercor
In its Draft Decision, the Commission was of the view that the magnitude of the variation in the
2004 reported operating and maintenance expenditure for CitiPower (being 63 per cent above
2003 levels and 41 per cent above 2002 levels) was sufficiently anomalous that it may not be
representative of recurrent levels of operating and maintenance expenditure or the efficient costs
of providing its distribution services. The increase in Powercor’s expenditure over the 2001-04
period was also a concern.
As noted in the Draft Decision, it was difficult for the Commission to review this historical
information and ignore the magnitude of the increases in operating and maintenance expenditure
incurred by CitiPower and Powercor over the 2001-04 period, especially taking into account the
following factors:
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•
CitiPower’s estimate of 2004 operating and maintenance expenditure provided to the
Commission in October 2004 was more than 28 per cent below the reported full year
result, despite already representing a significant increase when compared to 2003. This
suggested that CitiPower incurred an additional and unanticipated $13 million in operating
and maintenance expenditure in the last three months of 2004.
•
Although CitiPower’s operating and maintenance expenditure increased significantly
compared to the estimate in October 2004, its estimate of 2004 total expenditure (operating
and maintenance expenditure plus capital expenditure) was consistent with the full year
result. This may be the result of a change in the application of CitiPower’s capitalisation
policy, although CitiPower indicated that there was no change in its actual policy during
the year or when compared to previous years.
•
CitiPower stated that it continued to manage and operate its network and that the majority
of its functions continued to be managed by CitiPower, not Powercor (CitiPower 2005b).
However, this appeared inconsistent with the information presented in the Regulatory
Accounting Statements provided shortly afterwards which indicated that nearly 70 per cent
of its expenditure related to a related party transaction involving Powercor.
•
Based on the reported information, the efficiency carryover amount to be carried over by
CitiPower and Powercor at the end of the period was zero, due to the net negative
carryover amount that would exist. This outcome would effectively insulate those
distributors from any penalties arising from inefficiencies incurred in 2004, or expenditure
brought forward from 2005 to 2004.
Accordingly, in its Draft Decision, the Commission considered that there were good reasons for
assuming that the reported information for CitiPower and Powercor for 2004 was not
representative of efficient recurrent levels of expenditure, and so ought not to be relied upon for
the purpose of estimating operating and maintenance expenditure for the 2006-10 regulatory
period.
As a result, the Commission adopted a ‘placeholder’ assumption on 2004 recurrent operating and
maintenance expenditure for these distributors and engaged Wilson Cook and Co. to provide it
with an opinion on a reasonable estimate of the recurrent operating and maintenance expenditure
that would be incurred by CitiPower and Powercor for the year ended 31 December 2006. This
estimate was to be based on a distribution business of average efficiency and having the same
functions and obligations encompassing the prescribed distribution services applicable to
CitiPower and Powercor at the end of 2004.
The process that Wilson Cook and Co. followed in undertaking this review was to:
•
discuss the terms of reference with the Commission and agree on a programme for the
work;
•
clarify with CitiPower and Powercor the cost categories for which they required more
detailed data;
•
examine each cost category and review the explanations given by CitiPower and Powercor
for movements and variations in them;
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•
where appropriate, make comparisons with other electricity distributors in Victoria and, in
respect of total operating and maintenance expenditure, in other jurisdictions;
•
determine what would have been a reasonable range of movement in the costs over the
period 2001-2004; and
•
determine what would have been an efficient and sustainable level of operating and
maintenance expenditure for CitiPower and Powercor in 2004, excluding non-recurrent
items.
In examining CitiPower and Powercor’s expenditure, Wilson Cook and Co.:
•
based its analysis on CitiPower and Powercor’s regulatory accounting information as
provided to it by the Commission, inclusive of the adjustments that the Commission
included in its Draft Decision;
•
noted that CitiPower and Powercor had provided the Commission with information on
actual costs incurred in providing services under their related party contracts and that the
Commission had made adjustments reflecting those costs;
•
made adjustments to the information itself to incorporate changes of allocations between
cost categories that were advised by CitiPower and Powercor;
•
took into account the responses and submissions made by CitiPower and Powercor;
•
considered whether any expenditure items were likely to be non-recurrent; and
•
considered whether there had been any changes in capitalisation or cost allocation policies
and whether there had been a consequential impact on reported operating and maintenance
expenditure.
When considering the costs and the movements in costs reported by CitiPower and Powercor,
Wilson Cook and Co. had regard to:
•
the impact of changes in activities and functions of the businesses;
•
differences in cost allocation policies (such as in the allocation of costs between regulatory
account categories or, to the limited extent possible, between the regulated, unregulated
and excluded business components) amongst the Victorian businesses;
•
differences in capitalisation policies, especially in respect of overheads, amongst the
Victorian businesses; and
•
any other factors that might explain differences between the businesses.
All information provided to Wilson Cook and Co. by CitiPower and Powercor was also provided
to the Commission. A draft of Wilson Cook and Co.’s report was provided to the Commission,
CitiPower and Powercor for comment and a final report was provided to these parties on 23
September 2005.
CitiPower and Powercor have expressed various concerns regarding the approach adopted by
Wilson Cook and Co., particularly the reliance placed on its approach of benchmarking costs per
customer. To support these concerns, CitiPower and Powercor engaged three consultants
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(Benchmark Economics, Meyrick and Associates and SKM) to review the draft Wilson Cook
and Co. report, provide a high level critique and commentary on the adoption of a single
performance indicator as a basis for benchmarking, and comment on appropriate models for
estimating efficiency. These consultants expressed the view that Wilson Cook and Co. had relied
too heavily on the other Victorian distributors rather than on comparisons with other
jurisdictions.
Wilson Cook and Co. reviewed the submissions by CitiPower and Powercor, which included the
reports from their consultants on benchmarking, and made adjustments to its report in response.
In its final report Wilson Cook and Co. concluded that:
•
CitiPower’s reported operating and maintenance expenditure for 2004 should be adjusted
down by $1.1m to reflect additional maintenance costs that might be considered to
represent ‘catch up’ expenditure from 2002, and by $2.1m in overhead costs related to
business restructuring that were considered to be of a non-recurrent nature; and
•
Powercor’s reported operating and maintenance expenditure for 2004 should be adjusted
down by $13.8m in light of Wilson Cook and Co.’s assessment that its overhead costs were
significantly higher than the other Victorian distribution businesses.
Adjusting for these findings, the Wilson Cook and Co. report set out the levels of operating and
maintenance expenditure that it considered represented efficient recurrent expenditure levels for
CitiPower and Powercor in 2006 in 2004 dollars. In Wilson Cook and Co.’s view, the efficient
level of recurrent expenditure for CitiPower in 2006 was $32.8 million (in 2004 dollars), while
for Powercor it was $93.4 million (in 2004 dollars), excluding capitalised indirect overheads.
The Commission notes that the Wilson Cook and Co. estimates are based on the relevant costs of
providing distribution services as contained in the Draft Decision. However, this Final Decision
has resulted in changes to these costs, notably an increase for AGLE and a decrease for United
Energy. In response to these changes, Wilson Cook and Co. has advised that it is doubtful that
the adjustments made in respect of CitiPower would be retained if the work was reassessed but
that the comparison may remain valid in respect of Powercor.
Just prior to the Commission receiving Wilson Cook and Co.’s final report, it came to the
Commission’s attention that Phillips Fox, acting for CitiPower and Powercor, wrote to Wilson
Cook and Co. alleging that Wilson Cook and Co. had engaged in conduct that contravened the
Trade Practices Act 1974, Fair Trading Act 1999 (Victoria) and Fair Trading Act 1986 (New
Zealand). In that letter, Phillips Fox reserved the rights of CitiPower and Powercor to institute
proceedings against Wilson Cook and Co. for breaches under these Acts and to seek appropriate
remedies, including declarations, injunctions and damages.
In response to receiving this letter, Wilson Cook and Co. sought its own legal advice regarding
this letter and this resulted in some delays in finalising its report.
The Commission deplores the use of such threats against experts and other consultants that it has
engaged in order to assist it in performing its statutory functions. The Commission emphasises
that the appropriate avenue for a distributor to adopt where it has concerns regarding the
methodology or conclusions of such an expert or consultant is to make appropriate
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representations to the Commission. Distributors also have the right to appeal Commission’s
decisions to the Appeal Panel.
The Commission has considered the information provided to Wilson Cook and Co. by CitiPower
and Powercor and the findings of Wilson Cook and Co., in addition to the information previously
provided by CitiPower and Powercor to the Commission. On the basis of this information the
Commission has formed a judgement as to the efficient recurrent operating and maintenance
expenditure that it should adopt for CitiPower and Powercor for 2004, for the purpose of
deriving both the efficiency carryover amounts for 2001-04 and to be used as the basis for
estimating operating and maintenance expenditure for the 2006-10 regulatory period.
The information provided to the Commission and/or Wilson Cook and Co. reveals that for
CitiPower in 2004:
•
There is an amount of direct overheads ($1.8 million) included in the reported operating
and maintenance expenditure for 2004 which would have been capitalised had the capital
works program not been disrupted due to industrial action.
•
There is an amount of indirect overheads ($2.1 million) included in the reported operating
and maintenance expenditure for 2004 which would have been capitalised had the capital
works program not been disrupted due to industrial action.
The Commission considers that, in exercising its judgement as to a reasonable level of recurrent
operating and maintenance expenditure for CitiPower, it is appropriate for a consistent
capitalisation policy to be applied from year to year. Accordingly, the Commission has made
further adjustments to CitiPower’s operating and maintenance expenditure to remove the
overheads (both direct and indirect) that would be expected to be capitalised.
In doing so, the Commission notes that the capitalisation policy that underpins the capital
expenditure forecasts needs to be consistent with the forecasts of operating and maintenance
expenditure. Accordingly, the Commission has increased the indirect (corporate) overheads
included in the capital expenditure forecasts (refer Chapter 7).
The information provided to the Commission and/or Wilson Cook and Co. reveals that for
Powercor in 2004:
•
The level of corporate costs63 incurred has increased significantly between 2001 and 2004.
•
The significant increase in corporate costs from 2003 to 2004 is explained by a change in
allocation policy (resulting in a greater allocation of corporate costs to prescribed services)
rather than increases in costs.
•
Other operating costs include redundancy costs in 2003 of $2.1m that would not be
expected to be a recurrent expenditure.64
63
64
These costs are categorised as regulatory and other operating in the regulatory accounting statements.
The Commission has been informed that $1.6 million has already been adjusted for with the reversal of movements in
provisions.
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In response to further queries from the Commission, Powercor provided additional information
to justify the increase in operating expenditure from 2003 to 2004, including more detailed
information regarding the total corporate costs incurred, the allocation of these costs to
Powercor, CitiPower and ETSA Utilities, and the allocation between prescribed services and
excluded services.
For the purpose of evaluating this information, the Commission notes that:
•
•
65
On a like for like basis, Powercor’s reported operating and maintenance expenditure
increased by 15 per cent from 2000 to 2004, whilst the operating and maintenance
expenditure for the other distributors did not increase materially over this same period.
y
Powercor has indicated that its costs have increased substantially because it has
chosen to deliver improved customer service — it has the best call centre
performance of all the distributors, and has received the largest increase in revenue
through the S-factor scheme during the current regulatory period.
y
However, the Commission would also expect that entering into joint ownership with
CitiPower would result in some synergies across the businesses. Although Powercor
and CitiPower have indicated that they have never claimed a reduction in costs as a
result of the joint ownership, the 2003 Chairman’s Report refers to benefits arising
from structural reorganisation related to service delivery and profitability. The
realisation of these benefits is not consistent with an increase in costs.
The increase in Powercor’s reported operating and maintenance expenditure over the
2000-04 period is largely attributable to increases in corporate costs.
y
Corporate costs are expected to be relatively fixed over time. Similarly, Powercor’s
submission to Wilson Cook and Co’s draft report indicated that the likely cost drivers
for these costs are revenue and employee numbers. This is consistent with the
benchmarking approach for these costs adopted by the Commission at the time of the
last price review. The increase in the reported corporate costs does not appear to be
consistent with relatively flat revenue and employee numbers.
y
Powercor has indicated that the corporate costs in 2001 and 2002 cannot be relied
upon. It is of the view that there is an error arising from the allocation of costs during
the transition from a stapled distributor/retailer to a stand alone distributor. The
Commission requested information on the explanation of variations in corporate
costs since 2001. This information was not provided. Instead, in response to a
subsequent request Powercor provided information on the variation between 2003
and 2004 in the interests of providing the Commission with some information in a
timely manner. This information revealed that the variation since 2001 was likely to
have been of use to the Commission.65
It is noted that in the letter to Powercor from PB Associates dated 5 September (provided to the Commission 14 October),
PB Associates suggest that previous years overheads costs could be reworked using the cost allocation policies applying the
2004 financial year in order to compare costs on a ‘like for like’ basis.
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•
•
Wilson Cook and Co. highlighted the increases in Powercor’s operating and maintenance
costs since 2001. Although the analysis represented a simple comparison, the results
showed that:
y
On a cost per customer basis, Powercor’s operating and maintenance costs have
increased significantly over the period, and by significantly more than the other
Victorian distributors.
y
Overhead costs per customer and overhead costs in total have increased significantly
in each year since 2001. In 2004, the overhead costs per customer are more than six
times greater than in 2001. Further, the total overhead costs are more than double
those reported by other Victorian distributors.
Meyrick and Associates (Meyrick)66 has undertaken partial factor productivity analysis of
Powercor’s total operating and maintenance expenditure. This analysis indicates that
Powercor is the most efficient of the distributors.
y
However, when Meyrick undertakes partial factor productivity analysis on the basis
of the specification underpinning the rate of change calculation incorporated in the
operating and maintenance benchmarks (see Chapter 6), Powercor is the least
efficient of the distributors. This specification is based on work undertaken by
Pacific Economics Group for SP AusNet.
y
Meyrick considers that in specifying the capacity measure for the purposes of
undertaking their analysis, MVA-km is preferred to peak demand. The unavailability
of MVA-km data for the Victoria distributors has led Meyrick to substitute line km.
Further, the weights adopted by Meyrick are derived from econometric work in New
Zealand rather than Victoria. It is the Victorian weightings that are incorporated in
the PEG work.
y
Additionally the Commission notes that the use of line lengths would result in
Powercor being presented favourably given the nature of its network.
•
The total corporate costs incurred by Powercor have increased by $5 million from 2003 to
2004 due to additional costs incurred in providing services to ETSA Utilities. However, the
costs allocated to ETSA Utilities remained unchanged from 2003 to 2004.
•
When comparing the increase in corporate overheads from 2003 to 2004, Powercor
adjusted for $5.3 million in overheads allocated to maintenance in 2004. However a
corresponding reduction in maintenance costs is not apparent.
•
A significant proportion of the variation in corporate costs from 2003 to 2004 is due to the
under or over recovery of network personnel.
Taking into account all of these matters, the Commission considers that an adjustment to
Powercor’s reported operating and maintenance expenditure is appropriate to account for
inefficiencies, changes in allocations and non-recurrent expenses.
66
Meyrick and Associates 2005, Review of Wilson Cook & Co Final Report ‘Estimate of Efficient Opex for CitiPower and
Powercor’, 5 October, provided in a confidential submission from CitiPower and Powercor 10 October 2005.
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Final Decision
The information before the Commission indicates that an adjustment to Powercor’s operating
and maintenance expenditure of up to $13.8m may be appropriate based on the review
undertaken by Wilson Cook and Co. However, the Commission considers that any adjustment
should take into account that the increases may be due to a number of factors, including an
increase in the efficient costs of providing services to Powercor’s customers. In the absence of
being able to accurately identify the contributors to the increase, the Commission has made a
judgement that at least $5.5m is not due to an increase in the efficient cost of providing services
to Powercor’s customers. Therefore, for these reasons, an adjustment of $5.5 million has been
made to Powercor’s operating and maintenance expenditure in 2004.
In Table 5.6, the Commission sets out CitiPower and Powercor’s reported 2004 operating and
maintenance expenditure that reflects the adjustments described above. This table also provides,
for comparison purposes, the Wilson Cook and Co. estimate of efficient recurrent operating and
maintenance expenditure for CitiPower and Powercor (although it should be noted that, in light
of the changes to the relevant costs made since the Draft Decision, these estimates might no
longer be appropriate) and the ‘placeholder’ approach adopted in the Draft Decision.
Table 5.6:
Adjustments to the 2004 reported operating and maintenance expenditure,
CitiPower and Powercor, $million, real $2004
Reported operating and maintenance expenditure
CitiPower
Powercor
47.3
110.2
0.1
3.8
Adjustments
Provisionsa
b
(0.1)
c
(2.8)
d
(2.4)
e
Contractual arrangements
(6.5)
Capitalisation of direct overheads
(1.8)
Capitalisation of indirect overheads
(2.1)
Excluded services
Capitalisation
Errors
(5.0)
Further adjustments
Commission’s adjustment
(5.5)
Adjusted total
31.7
103.5
Wilson Cook and Co estimate for 2006
32.8
93.4
Placeholder from Draft Decision
a
b
27.4
c
d
93.2
e
refer Section 5.24 refer Section 5.2.2 Refer Section 5.2.5 Refer Section 5.2.6 Refer Section 5.2.5
5.2.8 Summary
The adjustments made to the information provided in the distributors’ regulatory accounting
statements for the purposes of enabling that information to be used appropriately in this price
review are summarised in Table 5.7 for operating and maintenance expenditure and Table 5.8 for
capital expenditure.
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Table 5.7:
Adjustments to reported operating and maintenance expenditure, 2000-04,
all distributors, $million, real $2004
2000
2001
2002
2003
2004
Provisions
-0.7
-1.9
-3.0
2.0
0.8
Excluded services
0.0
0.0
0.0
-0.1
0.0
Retail
-1.4
-0.6
-0.1
-0.3
0.0
Capitalisation
-0.5
-1.2
-1.5
-1.6
0.0
Contractual arrangements
0.0
0.0
0.0
0.0
-0.2
Provisions
0.0
0.6
-11.8
-0.3
0.1
Excluded services
0.0
-4.4
0.0
0.2
-0.1
Retail
-4.2
-1.8
-1.3
0.0
0.0
Capitalisation
0.0
0.0
0.0
0.0
-6.6
Errors
0.0
0.0
0.0
0.8
-2.4
Contractual arrangements
0.0
0.0
0.0
-5.3
-6.5
Provisions
-2.4
-30.1
-6.0
1.1
3.8
Excluded services
-0.1
-9.5
3.2
0.0
0.0
Retail
-1.3
-0.6
0.0
0.0
0.0
Errors
0.0
0.9
0.0
0.0
0.0
Contractual arrangements
0.0
0.0
0.0
0.0
-5.0
Further adjustments
0.0
0.0
0.0
0.0
-5.5
Provisions
-3.2
-0.3
1.4
-0.8
-0.6
Excluded services
0.0
-1.2
0.4
-6.8
0.0
Retail
-3.6
-5.2
-6.2
-4.0
0.0
Errors
0.0
0.5
-3.8
-4.5
0.6
Contractual arrangements
0.0
0.0
0.0
0.0
-0.6
Provisions
-4.7
4.7
-1.7
-1.1
1.6
Contractual arrangements
0.0
-6.6
-4.2
-8.9
-12.3
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CitiPower
Powercor
SP AusNet
United Energy
Essential Services Commission, Victoria
Final Decision
Table 5.8:
Adjustments to reported capital expenditure, 2000-04, all distributors,
$million, real $2004
2000
2001
2002
2003
2004
Excluded services
0.0
-1.4
-1.2
-0.9
-1.4
Capitalisation
6.2
9.7
5.9
1.0
1.4
Contractual arrangements
0.0
0.0
0.0
0.0
-0.1
Provisions
0.1
0.1
0.0
-0.5
-0.4
Excluded services
0.0
-1.7
0.0
0.0
0.0
Retail
0.0
0.0
-31.9
0.0
0.0
Capitalisation
0.0
0.0
0.0
0.0
8.3
Contractual arrangements
0.0
0.0
0.0
-5.0
-6.4
Provisions
-1.1
-0.3
-0.9
-0.3
-1.8
Excluded services
0.0
-3.8
-4.5
0.0
0.0
Errors
0.0
-9.2
0.0
-9.5
0.0
Excluded services
0.0
-0.9
-2.8
0.0
0.0
Errors
-1.3
-0.7
1.8
-1.4
0.0
Excluded services
0.0
-3.5
-0.5
0.8
0.0
Errors
20.1
-22.2
-14.2
-8.5
-5.9
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TXU
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Final Decision
6 OPERATING AND MAINTENANCE EXPENDITURE
Operating and maintenance expenditure requirements are added into the forecast revenue
requirements as a separate component — the other components of the revenue requirement being
the cost of capital, regulatory depreciation and forecast tax liability (see Chapter 9) and the
efficiency carryover amounts (see Chapter 10).
As with capital expenditure, the distributors are not required to spend the operating and
maintenance expenditure forecast. Under the Commission’s incentive-based framework,
incorporating a CPI-X price control and an efficiency carryover mechanism, the distributors are
encouraged to achieve efficiencies in their operating and maintenance expenditure over the
period. The framework is designed so that the benefits of these efficiencies are shared with
customers over time.
This Chapter sets out the operating and maintenance expenditure forecasts used to determine the
distributors’ revenue requirements for the 2006-10 regulatory period as well as the information
considered and reasons for the decision.
6.1 Final Decision
The operating and maintenance expenditure forecasts used to determine the distributors’ revenue
requirements are set out by component in Table 6.1 and by year in Table 6.2.
Table 6.1:
Operating and maintenance expenditure, all distributors, 2006-10, $million,
real $2004
Base opexb
Step changes
c
d
Rate of change
Impact of growth
e
Total opex
Increase above base opex
AGLE
CitiPower
Powercor
SP
AusNeta
United
Energy
234.9
155.0
516.3
460.8
374.3
8.5
11.8
42.5
56.4
17.9
4.2
2.7
9.1
8.2
6.6
12.5
7.5
27.6
36.4
20.4
260.1
177.1
595.6
561.8
10.7%
14.2%
15.4%
21.9%
419.3
f
12.0%
Note: Totals may not add due to rounding. The Commission’s decision cannot necessarily be compared on a line for
line basis with the distributors’ proposals because in some cases costs associated with the rate of change have been
included as a step change and in some cases costs associated with the impact of growth have been included as a step
change. a Formerly TXU b Refer to Table 6.8 c Refer to Table 6.23 d Refer to Section 6.2.3 e Refer to Section 6.2.4. f
An increase of 11.5 per cent when the step change for GSL payments is excluded.
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Table 6.2:
Operating and maintenance expenditure by year, all distributors, 2006-10,
$million, real $2004
2006
2007
2008
2009
2010
Total
AGLE
50.1
50.9
51.9
53.0
54.3
260.1
CitiPower
34.0
35.117
35.3
36.0
36.7
177.1
Powercor
114.0
116.6
118.9
121.5
124.6
595.6
SP AusNet
106.7
109.4
112.3
115.1
118.3
561.8
United Energy
80.8
82.5
84.2
86.0
85.8
419.3
Note: Totals may not add due to rounding
6.2 Reasons for the Decision
As foreshadowed in the 2001-05 Price Determination (ORG 2000a, pp. 87-88), the Commission
in its Final Framework and Approach indicated that it would assume that the value of operating
and maintenance expenditure in 2005 would equal the level of operating and maintenance
expenditure incurred in 2004, adjusted by the annual efficiency gain implied by the forecasts
established in the last price review for the years 2004 and 2005.
Using these assumptions, the Commission indicated that the starting point, or base operating and
maintenance expenditure, for the year 2006 would be the operating and maintenance expenditure
incurred in 2005, reduced for standard metering67, Guaranteed Service Level (GSL) payments68,
and licence fees.69 This value would then be further adjusted for any improvement in efficiency
that the Commission considered appropriate between the years 2005 and 2006, having particular
regard to experience to date in the 2001-05 regulatory period and any other relevant
considerations.
Once the starting point, or base operating and maintenance expenditure, had been determined
using the methodology outlined above, the Commission then indicated that it would use the ‘rate
of change’ approach to recognise anticipated productivity improvements, and the costs
associated with the impact of growth, to determine the operating and maintenance expenditure
forecasts for the 2006-10 regulatory period.
To recognise the potential that the distributors may be required to perform new (or changed)
functions or meet new (or changed) legislative obligations, the Commission provided for the
distributors to propose step changes which would be added to the base operating and
maintenance expenditure where sufficient supporting information is provided.
67
68
69
Prescribed service standard metering will be subject to a separate metering price control in the 2006-10 regulatory period.
The Commission has made changes to the GSL payments scheme (refer Chapter 3). Accordingly the expenditure forecast
for GSL payments is considered separately.
Expenditure on licence fees is being allowed as a pass through under the price controls.
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6.2.1 Distributors’ proposed operating and maintenance expenditure
The distributors forecast $2,235 million of operating and maintenance expenditure over the
2006-10 regulatory period. This was 37 per cent greater (on an average annualised basis) than the
level of expenditure undertaken over the 2001-04 period (see Figure 6.1). This forecast increase
was due to claims by the distributors that:
•
their rate of productivity improvement would decline and labour rates would increase;
•
they would incur costs from servicing the forecast increase in customer numbers; and
•
they faced numerous changes in functions and obligations for which they would incur large
increases in operating and maintenance expenditure.
The distributors’ forecasts for each component of operating and maintenance expenditure are set
out in Table 6.3.
Figure 6.1:
Operating and maintenance expenditure, industry aggregate, actual
operating and maintenance expenditure 2001-04a and distributors’ proposals
2005-10, $million, real $2004
600
500
400
$M 300
200
100
0
2001
2002
2003
2004
2005
2006
Actual opex
a
2007
2008
2009
2010
Distributor proposed
Exclusive of operating and maintenance expenditure associated with prescribed metering services.
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Table 6.3:
Operating and maintenance expenditure proposed by the distributors, all
distributors, 2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Base opex
236.3
237.0
572.6
458.1
422.7
Step changes
38.6
21.5
121.3
112.4
30.0
Rate of change
3.6
20.9
50.5
35.7
0.0
Impact of growth
4.4
0.9
0.7
28.6
7.5
280.4
745.1
634.8
460.1
Total opex
282.9
a
Note: Totals may not add due to rounding. Based on AGLE’s current regulatory obligations with respect to the cost
of safety compliance
The ability of the distributors to retain the benefits of any spending that is less than forecast
creates an incentive for them to ‘overstate’ their expenditure forecasts in order to obtain a more
generous revenue requirement and price cap. This incentive, together with the asymmetry of
information between the distributors and the regulator, makes it very difficult for the regulator to
determine the efficient level of expenditure required to deliver reliable distribution services by
simply having regard to the distributors’ submitted expenditure proposals.
If the regulator accepts the distributors’ forecasts, and that level of expenditure is not required,
then customers will pay more than they should for a given level of service. On the other hand, if
the regulator reduces the distributors’ forecasts without good reason, there is a risk of not
providing sufficient expenditure for the distributors to maintain the reliable provision of services
over the longer term.
In deciding upon the expenditure requirements for the distributors, the Commission must
therefore make a judgement on the level of expenditure that will be reasonably required by the
distributors to operate and maintain their networks and meet their obligations.
The fact that the operating and maintenance expenditure reported by the distributors over the
2001-04 period is much lower than estimated at the last price review and the sizeable increase in
operating and maintenance expenditure which is forecast to be required over the
2006-10 regulatory period (especially given that such expenditure is largely recurrent) raises
questions over the reasonableness of the distributors’ forecasts.
In this regard the Commission notes the EUCV’s (2005c, p. 11-12) comments:
Further, the ESCoV has noted that when it assumed that the DBs did have a better
understanding of the cash needs of the network (such as during the last EDPR in 2000)
and granted the DBs the funds requested, the DBs demonstrated quite clearly that they had
claimed much higher amounts than were really needed to manage the networks, and to
improve on service standards.
It is quite clear that in the last price review that the DBs sought funds which would permit
them to adequately manage the networks — the issue is that they did not need all of these
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funds and so took the difference between needs and the allowed amounts to profit. This
approach has had two outcomes:
x
consumers have had to pay an unnecessary premium for the DBs to manage the
networks
x
the DBs had no regulatory cost constraint on them in the management of the networks
and so the actual expenditure by the DBs reveals the funds really needed by the DBs for
their opex and capex.
The Commission notes that the benchmarks set at the last price review by the Office of the
Regulator-General allowed for operating and maintenance expenditure of $2,100 million over the
2001-05 period. Over this same time period, the distributors only spent $1,638 million (assuming
expenditure in 2005 is the same as the average over 2001-04), or $460 million less than allowed.
With this in mind, the Commission’s approach to the 2006-10 price review was to give particular
focus to assessing the distributors’ forecasts against historic expenditure, the information
provided by the distributors as to reasons for incurring additional operating and maintenance
expenditure over the 2006-10 regulatory period, and relevant information available from a range
of other sources.
The Commission has also had regard to the need to ensure that the operating and maintenance
expenditure included in the revenue requirement is reasonable in aggregate. Whilst the
Commission has assessed each component of the operating and maintenance expenditure this
does not represent the amounts of money that the distributors are required to spend against each
component. Under the Commission’s incentive-based framework, the distributors are given
incentives to increase their returns by meeting their service and regulatory obligations at lower
cost. Customers benefit from these efficiency gains over the longer term through lower real
prices.
6.2.2 Base operating and maintenance expenditure
The base level of operating and maintenance expenditure proposed by each distributor is
provided in Table 6.4.
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Table 6.4:
Annual base operating and maintenance expenditure as proposed by the
distributors, all distributors, 2006, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
2004 as reported in
regulatory accounts
48.6
47.3
114.0
93.4
85.6
plus efficiency
changes (2004-05)
-0.2
0.6
1.4
-0.3
0.0
less GSL payments
0.0
0.0
0.0
0.5
0.0
less expenditure
associated with
standard metering
0.5
0.5
0.8
0.4
0.5
less licence fees
0.6
0.0
0.0
0.6
0.6
Base opex
47.3
47.4
114.5
91.6
84.5
Note: May not add due to rounding. The distributors’ proposals have been updated since the release of the Draft
Decision
The Final Framework and Approach for estimating operating and maintenance expenditure relied
on two important assumptions:
1)
that the revealed costs are efficient; and
2)
that operating and maintenance expenditure is recurrent.
This approach relied on the incentive properties of the regulatory framework established at the
last price review, in particular the efficiency carryover mechanism. This mechanism aimed to
provide additional incentives for the distributors to achieve efficiencies and then report the actual
cost of service provision in order to claim the efficiency carryover amounts.
The intent of the mechanism was to only reward sustainable efficiencies — where lower
operating costs are followed by higher operating costs, then the mechanism assumes that there is
an efficiency loss and a penalty applies. Thus, to continually earn rewards under the mechanism,
a distributor would have to achieve efficiency gains year on year and report these increasingly
efficient cost levels to the Commission.
In formulating its framework and approach for the 2006-10 price review, the Commission
assumed that it could rely on the incentive properties of the efficiency carryover mechanism such
that the level of operating and maintenance expenditure incurred in 2001-04 was efficient. The
framework and approach established also assumed that, due to the recurrent nature of operating
and maintenance expenditure, the 2004 reported operating and maintenance expenditure would
provide a reasonable representation of at least the efficient base operating and maintenance
expenditure for the 2006-10 regulatory period.
To ensure that this was the case, the Commission reviewed the information reported in the
distributors’ regulatory accounting statements to assist it in understanding the costs reported, to
ensure that its analysis is based on the relevant costs (that is the costs of providing distribution
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Essential Services Commission, Victoria
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services), and to ensure that it was using appropriate information for the purposes of calculating
the efficiency carryover amounts and establishing the basis for estimated operating and
maintenance expenditure in the 2006-10 regulatory period (see Chapter 5). Table 6.5 presents the
Commission’s decision on the operating and maintenance costs for 2000 to 2004 that it considers
relevant for this purpose.
Table 6.5:
Historical operating and maintenance expenditure, 2000-04, all distributors,
$million, real $2004
2000a
2000b
2001c
2002c
2003c
2004c
AGLE
53.7
49.6
43.3
44.54
50.0
48.4
CitiPower
36.4
31.3
30.2
20.5
24.9
31.7
Powercor
99.2
89.7
81.74
87.6
101.1
103.5
SP AusNet
96.8
93.1
86.9
90.3
86.1
93.4
United Energy
79.4
73.4
76.8
72.6
74.6
74.9
a
Includes metering data services and public lighting which were classified as prescribed services prior to 2001.
Excludes metering data services and public lighting which were classified as excluded services from 2001.
c
Adjusted as discussed in Chapter 5.
b
The recurrent operating and maintenance expenditure of each distributor for 2004, set out in
Table 6.5, is used as the basis for determining base operating and maintenance expenditure for
2006.
In rolling forward the recurrent operating and maintenance expenditure to 2006, the Commission
has deducted expenditure from the 2004 value as follows:
•
The amounts spent on Guaranteed Service Level (GSL) payments equal to the actual
expenditure for GSL payments reported in 2004 — expenditure on GSL payments in the
2006-10 regulatory period is instead considered a step change by the Commission (see
Section 6.2.6).
•
Maintenance expenditure on standard metering equal to that reported in 2004 —
expenditure on standard metering services has been incorporated in the prescribed metering
service price controls from 2006 (see Chapter 14).
•
The Commission’s licence fees as reported in 2004 — expenditure on licence fees is being
allowed as a pass through under the price controls from 2006 (see Chapter 12).
As set out in Chapter 5, for the purposes of calculating the relevant costs for CitiPower and
Powercor, the Commission has made an adjustment to the information contained in their
regulatory accounting statements of $0.7 million and $5.0 million respectively to remove a
payment made by them in 2004 to a related party for in-fill insurance services. The in-fill
insurance services are designed to reduce the insurance cover excess to zero on claims by third
parties.
A market does not exist for insurance of excess payments due to ‘moral risk’, that is, if the
insured incurred no risk they have no incentive to minimise the risk covered. Thus any attempt to
establish a market risk premium is based on a false premise, given that such a market premium
does not actually exist (refer to Chapter 5).
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However, the payment of excess insurance costs is a normal business expense where the
quantum of the expense may vary over time as do many other business expenses, and therefore
the Commission recognises that uninsured losses need to be considered in determining the
distributors’ forecast operating and maintenance expenditure. This is not a new (or changed)
function or legislative obligation. Accordingly, the Commission has decided to include an
amount to recognise uninsured losses in the base operating and maintenance expenditure.
The Commission notes that SP AusNet70 has also proposed a step change for self insurance,
however its claim is for losses incurred by SP AusNet itself, rather than by third parties.
Since the Draft Decision, CitiPower and Powercor provided to the Commission:
•
a confidential report prepared by AON Risk Solutions that quantifies its exposure to claims
by third parties; and
•
sections of a confidential internal document relating to Fire Liability Exposure, Fire Claims
History, Outstanding General Liability Claims, and Claims Management Responsibility.
This information indicated that the amount included by CitiPower and Powercor for in-fill
insurance services is likely to be too high to be representative of the cost of uninsured losses for
the following reasons:
•
The amount was calculated on the basis of the 75th percentile, rather than the expected
value. Whilst this may be an appropriate basis for determining the amount of a provision,
as confirmed by AON during a meeting with the Commission, it is not considered to be
appropriate for the purpose of determining an annual expenditure allowance.
•
In the case of the bushfire liability risk for Powercor, quantification of the risk took into
account events prior to the Ash Wednesday fires in 1983. There have been many changes
in the industry since then to reduce the impact of the distribution system on bushfires.
•
The material provided indicates that Powercor has not experienced any significant bushfire
claims or any claim against its fire liability insurance policy since privatisation (October
1994). The probability of such an event occurring is thus less than one in ten years.
•
The average value of claims for bushfires occurring after the Ash Wednesday fires has
been $34,000 per annum compared to Powercor’s quantification of losses incorporated in
the 2004 operating and maintenance expenditure of $3.5 million per annum.
The amount proposed by SP AusNet ($1.2 million per annum) was determined by SAHA
International based on the cost of replacing poles and wires. However the Commission notes
that, under the ‘building blocks’ approach, the costs incurred by the distributor are not the total
costs of the replacement asset, but just the financing charges for a period of approximately two
and a half years, given that there will not be an efficiency carryover mechanism on capital
expenditure during the 2006-10 regulatory period. Accordingly, SP AusNet’s quantification of
the cost of such events would appear to significantly overstate the likely cost.
70
Formerly TXU
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The Commission has therefore decided to add into the base operating and maintenance
expenditure an amount for uninsured losses (self insurance) for each of the distributors based on
the difference in the movement in the relevant provision in 2004 and the average annual
movement in the relevant provision between 2000 and 2004. This will ensure the distributors are
provided with a reasonable level of funding for the frequent uninsured events that occur, where
the expenditure incurred in 2004 is greater or less than that incurred on average over the period.
Additionally for the rural distributors there is a risk of third party claims arising from bushfires.
Based on the information provided by the distributors, the excess payable under the distributors’
insurance policies is in the order of $5,000,000 and the probability of such an event occurring
would appear to be a around 1 in 20 years. Therefore, the Commission has included an additional
amount of $250,000 in the 2004 base operating and maintenance expenditure for Powercor and
SP AusNet.
Having determined the starting point (that is, the base operating and maintenance expenditure),
the Commission has rolled forward this operating and maintenance expenditure to 2005 based on
the efficiency improvement that the Commission has determined to be appropriate between 2004
and 2005. The Commission’s Final Framework and Approach indicated that the 2004 operating
and maintenance expenditure would be rolled forward to 2005 based on the efficiencies assumed
in the 2001-05 benchmarks. However, the framework and approach assumed that it could rely on
the operation of the efficiency carryover mechanism to assume that the 2004 base operating and
maintenance expenditure was representative of the efficient recurrent expenditure.
The Commission considers that it can rely on these assumptions for AGLE and SP AusNet and
apply the foreshadowed approach. However, for CitiPower, Powercor and United Energy, the
Commission has had to estimate the efficient recurrent operating and maintenance expenditure
for 2004. For CitiPower this required an adjustment for items that were not recurrent, for
Powercor this required an adjustment for an amount that could not be said to represent efficient
increases in operating costs, and for United Energy the Commission based its estimate on rolling
forward previous year information. For these distributors it would not be appropriate to roll
forward the 2004 operating and maintenance expenditure to 2005 on the basis of the
foreshadowed approach when the estimates are based on more recent information on their costs
and better information is available on the likely efficiencies achieved over the 2001-04 period.
For these distributors the Commission has therefore applied the ‘rate of change’ and growth
adjustment for the 2006-10 regulatory period.
The efficiency gains between 2004 and 2005 that have been used by the Commission for this
purpose are set out in Table 6.6.
Table 6.6:
Efficiency gain
Assumed efficiency gains, all distributors, 2004 to 2005, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United Energy
-0.22
0.37
1.37
-0.28
1.02
The 2005 operating and maintenance expenditure that results from this calculation has then been
rolled forward to 2006 based on the efficiency improvement that the Commission has determined
to be appropriate between 2005 and 2006. The Commission considers that the ‘rate of change’
and impact of growth determined for the 2006-10 regulatory period (as discussed in
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Sections 6.2.3 and 6.2.4 respectively) is a reasonable representation of the efficiency
improvement for this purpose. Thus the base operating and maintenance expenditure is rolled
forward from 2005 to 2006 on the same basis as it is rolled forward from 2006 to 2010.
In Table 6.7, the Commission’s decision on the 2006 base level of operating and maintenance
expenditure and its derivation for each distributor is set out.
Table 6.7:
Base operating and maintenance expenditure, all distributors, 2006, $million,
real $2004
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
2004 recurrent opex
(see Table 6.5)
48.4
31.7
103.5
93.4
74.9
plus efficiency changes (2004-05)
(see Table 6.6)
-0.2
0.4
1.4
-0.3
1.0
less GSL paymentsa
0.0
0.0
0.3
0.5
0.0
less expenditure associated with
standard metering
0.6
0.5
0.8
0.4
0.4
less licence fees
0.6
0.6
0.7
0.6
0.6
plus self insurance
0.1
0.0
0.2
0.5
0.0
2006 base operating and
maintenance expenditure
47.0
31.0
103.3
92.2
74.9
Note: May not add due to rounding. a As reported by the distributors in their performance reports.
Executive remuneration
In assessing the distributors’ operating and maintenance expenditure requirements, the Tariff
Order requires the Commission to consider executive remuneration. Distributors must forecast
executive remuneration in terms of the total remuneration, average remuneration per executive
and actual headcount as per section 5.9.2 of Electricity Industry Guideline No. 3.
Executive remuneration represents less than 2 per cent of the distributors’ proposed base
operating and maintenance expenditure. The Commission has compared the distributors’
proposals on executive remuneration for the 2006-10 regulatory period with the executive
remuneration expenditure reported by the distributors over the 2001-04 period and with the
benchmarks set at the last price review (see Table 6.8). This analysis indicates that the proposed
average executive remuneration rate is in line with that reported over the current period and
lower than the benchmarks set at the last price review.
It is noted, however, that United Energy has 12 executives paid $2.4 million per annum, although
their statutory accounts reveal they have no direct employees.
Therefore, the Commission considers that the level of executive remuneration is appropriately
reflected in the base operating and maintenance expenditure.
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Table 6.8:
Executive remuneration, all distributors, 2006-10
AGLE
CitiPower
Powercor
SP AusNet
United Energy
Executive remuneration ($ million per
annum, real $2004)
2001-05 forecasts
1.4
2.9
3.2
1.9
3.6
2004 actual
1.1
1.9
3.8
3.3
0.5
2006-10 distributors’
proposals
1.0
0.9
2.8
1.1
2.4
2001-05 forecasts
6
12
13
14
14
2004 actual
10
9
14
15
2
2006-10 distributors’
proposals
9
5
11
5
12
Number of executives
6.2.3 Rate of change
The Commission indicated that the distributors’ operating and maintenance expenditure might be
expected to change over the 2006-10 regulatory period to reflect changes in input cost drivers
and productivity. This has been referred to as the ‘rate of change’. It is applied to the 2005 base
operating and maintenance expenditure figure to establish the forecast for 2006 and is used to
roll forward the 2006 base operating and maintenance expenditure forecasts for 2007 to 2010.
The ‘rate of change’ is defined as the year to year change in operating and maintenance
expenditure for a number of factors such as expected productivity improvements and changes in
the price of distributors’ inputs.
The rates of change proposed by the distributors in their price-service proposals are set out in
Table 6.9.
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Table 6.9:
Proposed rate of change in operating and maintenance expenditure, all
distributors
Proposed rate
of change per
cent p.a.
Basis for rate of change
AGLE
0.00
Did not support a reduction of forecast costs for unidentified efficiency
gains. In its submission to the Position Paper, AGLE proposed a rate of
change of 1.8 per cent per annum plus a real increase in labour costs, but
this is not reflected in its templates.
CitiPowera
-2.83
Productivity Commission (productivity growth in the Australian
electricity, gas and water sectors 1998/99 – 2003/03) and KPMG’s
Labour Rate report
Powercora
-2.83
Productivity Commission (productivity growth in the Australian
electricity, gas and water sectors 1998/99 – 2003/03) and KPMG’s
Labour Rate report
SP AusNeta
-2.51
SP AusNet originally proposed a rate of change of -0.89 per cent per
annum based on a PEG report on the Partial Factor Productivity trend in
the US and KPMG’s Labour Rate report. This has been increased based
on its latest forecasts of labour cost increases.
United Energy
0.00
Did not support a reduction of forecast costs for unidentified efficiency
gains
a
A negative rate of change implies that there is an increase in costs net of any productivity improvements.
The distributors commissioned KPMG and Pacific Economics Group (PEG) to support the rates
of change that they submitted in their price-service proposals.
In its original price-service proposal, SP AusNet indicated that its rate of change of -0.89 per
cent per annum consisted of an underlying rate of annual productivity improvements of 0.82 per
cent (based on studies of US distribution businesses by PEG, see Box 6.1), offset by allowances
of 1.26 per cent for increasing labour costs (based on KPMG’s report indicating increasing
labour costs of 4.5 per cent per annum) and 0.45 per cent per annum for increased training costs.
SP AusNet subsequently increased its forecast of labour cost increases, resulting in a revised rate
of change of -2.51 per cent per annum.
CitiPower and Powercor indicated that they expected the industry operating and maintenance
expenditure productivity trend to decline by 2.83 per cent a year over the 2006-10 regulatory
period based upon:
•
projecting forward analysis conducted by the Productivity Commission on the productivity
growth in the Australian electricity, gas and water sectors from 1998-99 to 2002-03, which
indicated that productivity varied between -5.0 per cent in 1998-99 and 3.4 per cent in
1999-00; and
•
consideration of evidence arising from KPMG’s analysis of real increases in labour rates of
between 4 and 5 per cent per annum over the 2004-10 period.
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Box 6.1:
Calculation of changes in partial factor productivity
As part of its price-service proposals, SP AusNet commissioned PEG to write a report on the projection of its future
operating expenses. The report, “Predicting Growth in SPI’s O&M Expenses”, focused on the more mature North
American utility industry and found that:
… the total cost of power distribution depends chiefly on the number of customers served but also
depends on delivery volumes (PEG 2004a, p. 5).
The Commission used PEG’s econometric results as a means of calculating the changes in the partial factor
productivity.
The change in partial factor productivity (PFP) is calculated by the difference between the change in operating and
maintenance expenditure and the change in operating and maintenance expenditure driven by changes in growth
factors such as customer numbers, energy consumption and peak demand. The change in operating and maintenance
expenditure driven by changes in growth factors was determined by multiplying the annual change in the key
network drivers of customer numbers, energy consumption and peak demand, by the weights or estimated
coefficients computed for these same network drivers by Pacific Economics Groups (PEG) on behalf of SP AusNet,
based on Victorian data. The estimated coefficients were 0.431 for customer numbers, 0.296 for energy consumption
and 0.272 for peak demand.
Using average figures for the 2000-04 period, and establishing an industry-wide operating and maintenance
expenditure figure (based on the total average operating and maintenance expenditure for the industry) allowed the
Commission to establish an industry wide partial factor productivity growth rate for operating and maintenance
expenditure.
In its Issues Paper and Position Paper, the Commission raised a number of concerns with regard
to the way in which the distributors had calculated the rate of change. The main issue for the
Commission was why US data rather than Victorian data was used by PEG to calculate the rate
of annual productivity improvements for SP AusNet when the analysis of Total Factor
Productivity (TFP) that PEG undertook on behalf of the Commission suggested that the use of
Victorian data is more appropriate. The Commission supported the approach proposed by SP
AusNet but considered that Victorian data should be used.
Additionally the Commission raised concerns regarding the assessment of expected external
labour rates commissioned by the distributors and undertaken by KPMG.71 This study forecasts
that real wage increases of 4 to 5 per cent per annum will occur over the period 2004-2010.
The Commission engaged PEG to review the KPMG report. PEG identified issues with KPMG’s
statistical methodology and results. According to PEG, “after properly controlling for the effects
of inflation, KPMG’s preferred model projects that wages will decline rather than increase in real
terms over the 2006-2010 period” (PEG 2004, p. 22). A copy of PEG’s report, a copy of
KPMG’s response to the PEG report, and PEG’s subsequent response are available on the
Commission’s website.
The Draft Decision on the methodology for calculating the rate of change combined a backward
looking approach to identify the trend in operating and maintenance expenditure (change in
71
This report is available on the Commission’s website http://www.esc.vic.gov.au/electricity832.html
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partial factor productivity) and a forward looking approach to include the expected increase in
labour costs.
The change in partial factor productivity72 was determined based on the difference between the
change in operating and maintenance expenditure and the change in operating and maintenance
expenditure driven by changes in growth factors such as customer numbers, energy consumption
and peak demand (see Box 6.1). The reported information provided by distributors for 2000 to
2004 (including the adjustments discussed in Chapter 5) was used to determine the change in
operating and maintenance expenditure over the period.
The results of this analysis suggested that the average weighted rate of change in operating and
maintenance expenditure was 1.22 per cent per annum, which represents a reduction in the
operating and maintenance expenditure.
With regard to expected changes in labour costs, the Commission acknowledges that labour costs
are not falling. Labour costs have been increasing at a greater rate than CPI over a number of
years. The issue is whether there will be a real increase in labour rates over the next regulatory
period, particularly given the recognised shortage of skilled electricity workers in Victoria.
The Commission held discussions with the Electrical Trades Union (ETU) and Energy Safe
Victoria (ESV) to improve its understanding of the constraints that are currently impacting upon
the labour market and the resulting effect on costs. The Commission understood that the
approach being adopted within the Victorian electricity industry was to increase the intake of
apprentices (which has already commenced) and to constrain wage rate increases.
In its Draft Decision, the Commission stated that it expected that labour costs would increase by
4 per cent per annum in nominal terms (or 1.5 per cent per annum in real terms, assuming a CPI
of 2.5 per cent per annum) over the 2006-10 regulatory period, based on information from the
ETU regarding Enterprise Bargaining Agreements that had been negotiated in Victoria.
Assuming that labour costs account for 40 to 60 per cent of costs,73 the Commission calculated
that this would result in a 0.6 to 0.9 per cent per annum increase in operating and maintenance
expenditure over the period. The annual rate of change calculated under this approach,
incorporating the average weighted rate of change in operating and maintenance expenditure and
the forecast real labour rate increases, was -0.32 to -0.62 per cent per annum.
The Commission has also considered the decisions taken by regulators in the other Australian
jurisdictions on this issue. This information is compared to the distributors’ proposals and the
Draft Decision in Table 6.10.
72
73
Partial factor productivity growth is the change in productivity arising from a change in a given input, such as labour,
assuming all other inputs are held constant.
This assumption is reasonably consistent with SP AusNet’s assumption regarding the rate of change in operating and
maintenance expenditure based on the labour rate increase (SP AusNet 2004f, p. 108)
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Table 6.10:
Rates of change in operating and maintenance expenditure
Source
Commission’s approach
in Draft Decision
Distributors’
submissions
South Australia
Projected labour cost
increases
Productivity
improvements
Estimated net impacta
4.0% p.a. nominal
1.5% p.a. real
-1.22% p.a.
-0.32 to -0.62% p.a.
4 – 5% p.a. real
-0.82% p.a. (SP AusNet)
-2.83 to 0.0% p.a.
-5.0% - 3.4% p.a.
(Productivity
Commission)
2.1% p.a. real
-0.84 to -1.26% p.a.
ACT
5.0% p.a. nominal
-1.0% p.a.
-0.5 to 0.0% p.a.
Queensland
4.5% p.a. nominal
-1.0% p.a.
-0.2% to 0.2% p.a.
Nil
Nil
0% p.a.
NSW
a
Assumes that labour comprises 40 to 60 per cent of operating and maintenance expenditure and a CPI of 2.5 per
cent per annum. A negative number for productivity improvements and estimated net impact represents an increase
in costs.
Taking into consideration the expected labour rate increases, the productivity improvements over
the 2000-04 period and the analysis undertaken by regulators in the other Australian
jurisdictions, the Commission applied a rate of change of 0 per cent over the 2006-10 regulatory
period in its Draft Decision.
In response to the Draft Decision, the distributors have questioned the principle of incorporating
efficiency gains into the operating and maintenance expenditure benchmarks and stated that
labour rate increases would be higher than those assumed in the Draft Decision.
SP AusNet (2005f, p.35) and United Energy (2005i, p. 13) stated that if the Commission
anticipates future efficiency gains in setting operating expenditure benchmarks, customers will
enjoy an immediate gain of 100 per cent of those efficiency gains. According to these
distributors, this was neither ‘fair sharing’ nor was it an outcome from a gain actually ‘achieved’
(contrary to clause 2.1(c)(2) of the Victorian Tariff Order (2005)).
In a workably competitive market, the market prices will tend to move based on industry-wide
productivity improvements. Those firms that outperform the industry-wide productivity
improvements will generally receive higher returns than the other firms, and those firms that
underperform the industry-wide productivity improvements will generally receive lower returns
than the other firms. Other stakeholders supported this view, indicating that productivity
improvements were expected in all industries and therefore should continue to be expected
within the electricity industry sector.
The Commission’s forecasts of the level of operating and maintenance expenditure that will be
required by the distributors to manage their networks are based on consideration of industrywide trends. This includes a consideration of changes in productivity and labour costs.
Consistent with the operation of a workably competitive market, customers receive the benefit of
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industry-wide benefits immediately. Where a distributor outperforms these industry-wide trends,
then those efficiencies are retained by the distributor for five years under the efficiency carryover
mechanism. A distributor will therefore benefit when it achieves greater efficiencies than the
industry-wide trend, but is penalised when it is less efficient.
In this regard, CUAC (2005c, p. 4) supported the Commission's approach, indicating that
productivity improvements should be considered as business as usual and not part of the
efficiency carryover mechanism. However, it identified that improvements in productivity will
be largely offset by increases in labour costs as the labour market continues to tighten in the
short term.
SP AusNet (2005f, p. 35) and United Energy (2005i, p. 13) also stated that it was not reasonable
to expect the distributors to improve efficiency at the same rates as in the past. To set the future
required efficiency improvement equal to history ignores the reality that, as distributors approach
the productivity frontier, the potential rate of productivity growth declines. These distributors
contend that the proposed rate of change formula is based on the recent historical productivity
trend of a group of recently privatised distribution businesses. They commented that the high
productivity growth that has recently been experienced has been facilitated by special
circumstances that will not be repeated in the next five years.
In response the Commission notes that the period over which the change in the partial factor
productivity is calculated excludes the years immediately post privatisation during which the
change in partial factor productivity may have reflected higher productivity gains. Therefore, the
Commission is of the view that it is reasonable to assume that the industry-wide improvements in
productivity over the 2000-04 period will be achieved, on average, over the 2006-10 period.
Therefore, the Commission has decided to confirm the use of the methodology it put forward n
the Draft Decision. However, it has updated the change in partial factor productivity since the
Draft Decision based on the updated historic operating and maintenance expenditure (including
capitalised indirect overheads) as set out in Chapter 5. The Final Decision on the change in
partial factor productivity is 0.83 per cent per annum, that is, a reduction in operating and
maintenance expenditure.
The distributors also questioned the assumptions that the Commission had made in regard to
changes in labour rates.
In confidential submissions provided to the Commission, CitiPower and Powercor calculated an
effective nominal labour cost increase of 5.7 per cent per annum based on its Enterprise
Bargaining Agreements (copies of which were provided to the Commission). Similarly, SP
AusNet calculated a nominal increase in labour costs of 5.76 per cent per annum based on its
Enterprise Bargaining Agreement.
Using the information provided by these distributors, the Commission has calculated the forecast
increase in nominal labour costs over the next regulatory period to be approximately 5.0 per cent
per annum.
The difference between the distributors’ estimates and the Commission estimate is the period
over which one-off changes (for example, changes in long service leave) are recovered. For
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example, the distributors prorated these costs over the life of the EBA (three years) whereas the
Commission has prorated the costs over the period in which the rate will be applied (six years —
2005 to 2010). The distributors’ approach assumes that similar one off costs will be incurred
when the next EBA is negotiated.
The change in partial factor productivity reflects the increase in labour rates over the
2000-04 period. To calculate the rate of change for the 2006-10 regulatory period, it is necessary
to also include the incremental change in the labour rate increase that is expected relative to the
2000-04 period.
The nominal increase in labour rates over the 2001-04 period has been assumed to be 3.43 per
cent per annum based on the average of the actual labour rate increases reported in the Victorian
budget papers for the period 2000/01 to 2003/04. This results in an expected change in the
increase in labour costs of 1.57 per cent per annum over the 2006-10 regulatory period.
In the Draft Decision the Commission estimated labour costs to represent between 40 and 60 per
cent of total operating and maintenance expenditure. However, according to PEG (2005b, p. 22),
labour costs represent 62.3 per cent of total operating and maintenance expenditure across the
Victorian electricity distributors. For the Final Decision, the Commission has therefore assumed
that labour costs represent 62.3 per cent of total operating and maintenance expenditure.
Given that the Commission has calculated the weighted change in partial factor productivity
based on the updated adjusted historic operating and maintenance expenditure (including
capitalised indirect overheads) as 0.83 per cent per annum (see above), the rate of change is
calculated as follows:
Rate of change = Change in PFP + Labour cost increase * Proportion of labour
= 0.83 - 1.57 * 0.623
= -0.15 per cent per annum
This represents an increase in operating and maintenance expenditure of 0.15 per cent per
annum.
6.2.4 Impact of growth
Another factor considered in determining the operating and maintenance expenditure forecasts
for the 2006-10 regulatory period is the costs incurred from servicing the forecast increase in the
number of customers expected over the period.
The distributors set out the expected cost to service additional customers over the
2006-10 regulatory period in their price-service proposals (see Table 6.11).
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Table 6.11:
Proposed cost impacts from the expected growth in customer numbers, all
distributors
Cost per customer per annum
AGLE
$12.76
CitiPower
$14.07
Powercor
$12.10
SP AusNet
Included in rate of change of -2.51 per cent per annum
$7.74 — $10.02
United Energy
In an Open Letter issued on 27 July 2005, the Commission indicated that the rate of change
proposed in the Draft Decision was incorrect in that it did not incorporate the impact of growth
on the operating and maintenance expenditure forecasts for the 2006-10 regulatory period. It
further indicated that, in order to address this issue, it intended to forecast the impact of growth
on these operating and maintenance expenditure forecasts using the same methodology that was
applied in calculating the change in partial factor productivity, with the same drivers of growth
and the same coefficients, and using the Commission’s Final Decision on growth forecasts.
Stakeholders were generally supportive of the Commission’s proposed approach as outlined in
its Open Letter.
Using the Final Decision on the growth forecasts (see Chapter 4), the impact of growth for each
of the distributors has been calculated using the following formula:
Change in growth = 0.431 * Ln Change in customer numbers + 0.272 * Ln Change in
peak demand + 0.296 * Ln Change in energy consumption
Table 6.12 sets out the impact of growth for each distributor for the 2006-10 regulatory period
based on this methodology. This impact has been included in the forecast operating and
maintenance expenditure for the 2006-10 regulatory period.
Table 6.12:
Impact of growth, all distributors, per cent per annum
AGLE
CitiPower
Powercor
SP AusNet
United Energy
1.73
1.59
1.74
2.55
1.78
6.2.5 Step changes
Having determined the 2006 base operating and maintenance expenditure starting point, the
Commission’s approach is to recognise that the distributors may be subject to changes in
functions or obligations in 2006 that would not necessarily be reflected in the 2004 recurrent
expenditure. The 2006 base operating and maintenance expenditure should therefore be adjusted
for costs arising from new (or changed) functions and legislative obligations (termed ‘step
changes’). For these purposes, the reference to legislative obligations is intended to encompass
all regulatory obligations whether imposed by legislation or another regulatory instrument, for
example, a licence, code or price determination.
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Accordingly, the distributors were required to identify any step changes and provide information
supporting the basis and quantum of these step changes. The step changes identified by each
distributor are set out in Table 6.13. Since the Draft Decision, a number of the step changes
initially proposed by the distributors have been withdrawn.
Table 6.13:
Distributor identified step changes to operating and maintenance
expenditure for 2006-10, $million, real $2004
New functions and legislative
obligations
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
Total
Cost of safety compliancea
26.6
5.0
21.9
5.5
17.8
76.8
Electric Line Clearance
Regulations
0.8
2.0
49.7
31.5
0.5
84.5
5.5
18.6
Ageing assets
Apprentices
5.9
GSL payments scheme
1.1
Road Management Act
1.1
4.2
Voltage compensation claims
0.6
0.3
Growth related faults
Audits and accreditation
0.2
Asset inspections
1.5
0.0
5.9
41.5
2.3
44.9
12.2
5.8
2.5
25.8
2.1
1.5
2.5
7.0
7.0
7.0
2.9
4.6
0.6
0.6
Occupational health and safety
Critical infrastructure protection
24.1
7.8
0.3
Allowance for cost of self
insurance
1.9
2.9
3.2
b
b
6.0
Premature failure of XLPE
underground cable
7.8
1.5
6.0
3.2
SCADA master station upgrade
3.2
0.5
Ring fencing
0.8
Electricity demand side response
0.6
Financial report for 2009
regulatory financial information
0.1
9.8
0.5
0.8
0.6
0.6
1.8
0.1
Automated B2B
6.5
6.5
Distribution Code – Quality of
Supply
2.0
2.0
(continued next page)
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Table 6.13:
Distributor identified step changes to operating and maintenance
expenditure for 2006-10, $million, real $2004
New functions and legislative
obligations
AGLE
CitiPower
SPI Powernet augmentation
Powercor
SP
AusNet
1.0
0.5
United
Energy
Total
1.5
System changes for changes to
GSL payments scheme
0.0
0.0
GSL payments for reliability
0.7
0.7
Increased labour cost
Total
38.6
21.5
121.3
112.4
2.5
2.5
30.0
323.8
a
Note: Totals may not add due to rounding. With the exception of AGLE, the distributors’ proposals are based on a
risk management approach, rather than literal compliance, with the safety regulations. b CitiPower and Powercor
included an allowance for the cost of self-insurance in their reported 2004 expenditure.
In reviewing the step changes proposed by the distributors, the Commission notes that, with the
exception of the step change originally proposed by SP AusNet for a reduction in the Energy
Safe Victoria (ESV) levy (and since withdrawn), the distributors have not proposed reductions in
operating and maintenance expenditure as a result of functions or legislative obligations that
require less expenditure in the 2006-10 regulatory period than in the current regulatory period.
The Commission has taken this into consideration when assessing the step changes.
To assist the Commission in assessing the distributors’ proposals and to estimate reasonable
expenditure associated with the step changes, the Commission engaged Wilson Cook and Co,
technical engineering consultants, to review the reasonableness of the distributors’ expenditure
proposals. Wilson Cook and Co’s report is available on the Commission’s website.
Further, the Commission has undertaken its own analysis of the proposals and considered the
views of stakeholders to arrive at its Final Decision. In particular, the Commission has formed its
own view on whether the identified changes are appropriately categorised as step changes based
on information received from the distributors, stakeholders and relevant parties, and its own
analysis.
Each step change proposed by the distributors is discussed in the following sections, including
the step changes that have subsequently been withdrawn by the distributors.
Cost of safety compliance
The distributors are required to comply with a variety of legislative and regulatory requirements
including the Electricity Safety (Network Assets) Regulations 1999. A major audit was conducted
by the former Office of the Chief Electrical Inspector during the 2001-05 regulatory period
which identified that the distributors did not comply with a number of the regulations,
specifically:
•
Regulation 13 – Minimum distances between aerial lines and the ground, particularly those
over driveways
•
Regulation 17 – Minimum distances between aerial lines and parts of tramway systems
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•
Regulation 20 – Construction of underground lines – location of underground lines
•
Regulation 22 – Substations – minimum distances for pole mounted substations
•
Regulation 23 – Earthing and electrical protection – a low voltage network asset must be
earthed so that the resistance of the neutral conductor of the service line is not more than 1
ohm to earth
•
Regulation 27 – Inspection and testing – earth systems must be tested every ten years.
The Electricity Safety Act 1998 provides the opportunity for distributors to apply for variations to
the Regulations by means of exemptions from the Regulations to achieve equal or better safety
outcomes applicable to networks through the establishment of electricity safety management
schemes (ESMSs). The Act also provides the opportunity for persons authorised under an
approved scheme to be exempt from certain sections of the Act or from the Regulations.
The distributors have each developed and submitted ESMSs to Energy Safe Victoria (ESV).74 At
the time their price-service proposals were received, none of the distributors’ ESMSs had been
gazetted through an Order in Council. However, the Commission understands that all distributors
have now had their ESMSs gazetted in the form submitted.
Additionally, the distributors have submitted Electricity Safety Management Plans (ESMPs) to
ESV identifying plans to achieve compliance with specific regulations. In developing their
ESMPs, the distributors assumed that ESV would be able to grant exemptions to certain safety
regulations. At the time their price-service proposals were received, ESV’s powers to grant
exemptions were unclear, however the legislation has recently been amended in this regard. ESV
is now able to recommend to the Governor in Council that a scheme be accepted where it:
… is satisfied that the level of safety to be provided by the scheme minimises as far as
practicable –
(i)
the hazards and risks to the safety of any person arising from the upstream
network to which the scheme applies; and
(ii)
the hazards and risks of damage to the property of any person arising from the
upstream network to which the scheme applies.
ESV has now granted an exemption to CitiPower in relation to the height of aerial service lines
and has been in discussions with Powercor regarding an exemption for it in relation to the height
of aerial service lines.
Whilst some distributors, principally SP AusNet and United Energy, have been undertaking
works to improve their compliance with the Regulations, other distributors, principally
CitiPower and Powercor, have focused on risk assessments and seeking exemptions to the
Regulations.
74
ESV incorporates the former Office of the Chief Electrical Inspector (OCEI)
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Since the Draft Decision, the Commission has met with the distributors and ESV to obtain a
better understanding of the regulations that the distributors do not currently comply with and the
actions that will be required to move towards compliance over the 2006-10 regulatory period.
Each distributor has provided more detail in regard to the expenditure that will be required for
this purpose and has detailed the actions that will be undertaken.
CitiPower and Powercor (2005f, p. 1) have proposed that, in the event the exemptions they have
been seeking are not granted prior to the Final Determination, then a pass through should be
considered so that if the exemptions are not granted they are able to recoup the costs of
complying with the Regulations in the absence of those exemptions.
The Commission has given consideration to this proposal. However, it is of the view that the
only regulation for which the level of uncertainty is such that expenditure cannot be reasonably
forecast is regulation 23(11) regarding earthing. Whilst there is not a sufficient level of certainty
to forecast the capital expenditure associated with this regulation, the Commission is of the view
that there is sufficient certainty to forecast the operating expenditure.
With regard to the other regulations, the Commission is of the view that there is sufficient
certainty for the expenditure for the 2006-10 regulatory period to be estimated. Hence, the
Commission has included as a step change a level of expenditure that is consistent with ESV’s
understanding of the actions that are required to meet the conditions of any exemptions granted
or to be granted.
The allowances for these step changes are based on the Commission’s assessment of the
reasonable levels of expenditure required by an efficient distributor — they do not prescribe the
expenditure that must be undertaken. Each distributor must make its own decision regarding the
requirements and risks associated with compliance. The Commission also notes that some
distributors have undertaken very little expenditure to date to address these risks.
In this regard, AGLE (2005f, p. 46) continues to insist that it is appropriate that its forecast
expenditure be based on compliance with the Regulations and should not consider the possibility
of exemptions.
The Commission considers that any amount included in the expenditure requirements should
represent the requirements of an efficient distributor. It does not appear that the approach
adopted by AGLE is consistent with the approach that would be expected to be taken by an
efficient distributor. The Commission has sought further information from AGLE regarding the
most likely costs it would incur in complying with the safety regulations on the assumption that
it is granted exemptions from compliance, similar to those that have been, or are likely to be,
granted to the other distributors. This information has now been provided.
The Commission considered this information when assessing the reasonable expenditure for
AGLE for each regulation.
Whilst the Commission has assessed each of the regulations in turn, it has given consideration to
a reasonable level of operating and maintenance expenditure for safety compliance in aggregate.
In its considerations of a reasonable level of expenditure, the Commission notes that the
distributors have had a legal obligation to comply with these Regulations since 1999. In some
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instances the distributors have pointed to a lack of expenditure allowance as a reason for not
undertaking expenditure.
However, the distributors have had more than sufficient financial capacity to respond to these
obligations over the period. Further, the distributors were provided with expenditure of
$138 million (in 2004 dollars) for compliance with these regulations over the 2001-05 regulatory
period. Whilst some distributors appear to have undertaken works in the current period, other
distributors have not. This illustrates the tenuous link between a legal obligation and the
expenditure allowance.
The expenditure allowance provided by the Commission neither guarantees nor prevents
compliance with obligations. It is entirely up to the distributors to respond to their obligations
accordingly.
Regulation 13 — Minimum distances between aerial lines and the ground, particularly those
over driveways
The forecast expenditure proposed by the distributors as being required to improve compliance
of aerial line clearance heights, together with the distributors’ assumptions, is set out in
Table 6.14. The forecast operating expenditure and capital expenditure is also provided to
appropriately compare where different capitalisation policies have been adopted.
Table 6.14:
Distributors’ proposed expenditure, aerial service lines, all distributors,
2006-10, $million, real $2004
Opex
Capex
Total
AGLE
0.0
5.5
5.5
CitiPower
1.7
5.8
7.5
Powercor
8.4
16.9
25.3
SP AusNet
3.1
12.6
15.7
United Energy
0.4
24.8
25.1
Assumptions
Based on precedent in CitiPower’s and
Powercor’s exemption application
Approx 792 aerial service lines to be
rectified per annum and 259 aerial
service lines to be repaired per annum
Approx 3440 aerial service lines to be
rectified per annum and 2590 aerial
service lines to be repaired per annum
Prorated based on Powercor’s risk
analysis and the number of residential
customers
Additional 2000 service audits per
annum, Priority 1 and 2 services to be
replaced in years 1-4, priority 3
services in year 5
Discussions with ESV have indicated that CitiPower’s and Powercor’s assumptions are
reasonable based on the information provided to ESV in support of their exemption applications.
In the absence of an application for an exemption, SP AusNet forecast its expenditure by
prorating Powercor’s costs based on the ratio of residential customers. The Commission
considers this approach to be reasonable. However, the Commission also notes that Powercor’s
forecast expenditure has increased since SP AusNet submitted its costs due to a late change to
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Powercor’s exemption application by ESV. The Commission has therefore prorated these
additional costs for SP AusNet and increased its forecast expenditure accordingly.
The forecast step change in operating expenditure proposed by United Energy appears
reasonable.
AGLE did not forecast any step change in operating and maintenance expenditure in relation to
aerial service lines.
The forecast capital expenditure is considered by the Commission in Chapter 7.
Regulation 17 — Minimum distances between aerial lines and parts of tramway systems
The forecast expenditure proposed by the distributors as being required to improve compliance
of tramway assets, with the distributors’ assumptions, is set out in Table 6.15. The forecast
operating expenditure and capital expenditure is also provided to appropriately compare where
different capitalisation policies have been adopted.
Table 6.15:
Distributors’ proposed expenditure, tramway assets, all distributors, 200610, $million, real $2004
Opex
Capex
Total
Assumptions
AGLE
0.1
1.8
1.9
Opex - Inspection of all 1585 poles
shared with tramways and a survey of
unattached aerial crossings of about
37km of tram track. Capex - 174 low
voltage lines to be modified over five
years
CitiPower
0.3
5.0
5.3
Opex – additional minor works
procedures, replace 10 tramways
owned poles per year. Capex –
relocation of CitiPower overhead assets
in vicinity of tramway assets
Powercor
0.0
0.0
0.0
SP AusNet
0.0
0.0
0.0
United Energy
0.1
0.3
0.4
Opex – one off survey. Capex – rectify
some level of non compliance
Discussions with ESV have indicated that the distributors’ forecast step changes in operating
expenditure associated with tramways assets appear reasonable.
The forecast capital expenditure is considered by the Commission in Chapter 7.
Regulation 20 — Construction of underground lines – location of underground lines
The forecast expenditure proposed by the distributors as being required to improve compliance
of underground lines, together with the distributors’ assumptions, is set out in Table 6.16.
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Table 6.16:
Distributors’ proposed expenditure, location of underground assets, all
distributors, 2006-10, $million, real $2004
Opex
AGLE
0.0
CitiPower
0.0
Powercor
0.0
SP AusNet
0.0
United Energy
0.3
Assumptions
Additional 200 surveys per annum
During meetings with the distributors and ESV, ESV indicated that it expected that distributors
would be able to develop a risk assessment to leave underground assets in their current locations
if they could demonstrate that they knew where their assets were located. Accordingly, it is
expected that some expenditure would be incurred to improve the information on the location of
underground assets.
Whilst United Energy proposed $300,000 over the five year period for additional surveys, SP
AusNet forecast $1.5 million under audits and accreditation for the automation of records. SP
AusNet’s proposed step change for the automation of records has not been included in the
revenue requirement on the basis that process improvements such as this would only be
undertaken where the benefit exceeds the costs, and therefore it would not be appropriate to
include the costs without the benefits.
The expenditure proposed by United Energy is considered to be reasonable to improve the
information relating to underground assets. A similar step change will be provided for the other
distributors so that they can also improve their records relating to underground assets.
Regulation 22 — Substations — minimum distances for pole mounted substations
The forecast expenditure proposed by the distributors as being required to improve compliance
of pole mounted substations, together with the distributors’ assumptions, is set out in Table 6.17.
The forecast operating expenditure and capital expenditure is also provided to appropriately
compare where different capitalisation policies have been adopted.
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Table 6.17:
Distributors’ proposed expenditure, pole mounted substations, all
distributors, 2006-10, $million, real $2004
Opex
Capex
Total
AGLE
0.3
1.1
1.3
CitiPower
0.4
7.0
7.4
Powercor
0.0
10.0
10.0
SP AusNet
0.0
0.0
0.0
United Energy
0.0
9.7
9.7
Assumptions
Opex – 700 inspections per annum
Opex – 800 inspections per annum
and additional monitoring of 60
substations per annum. Capex – 200
aerial substations to be replaced per
annum
Capex – 400 aerial substations to be
replaced per annum
Opex – Program commenced in 2004
and is due to be completed by the end
of 2008.
AGLE and CitiPower proposed a step change in operating expenditure to increase the number of
inspections and monitoring of pole mounted substations. The expenditure proposed by them
appears to be reasonable.
United Energy indicated that its surveying of pole mounted substations had already commenced
and therefore the costs were included in its reported 2004 operating and maintenance
expenditure. Although the program is scheduled for completion by the end of 2008, United
Energy did not propose a negative step change reflecting that these costs will not be incurred
from 2009. United Energy was of the view that this step change was not material. The
Commission does not consider this to be a reasonable approach, and has therefore incorporated a
negative step change of $0.1 million in total across 2009 and 2010.
The forecast capital expenditure is considered by the Commission in Chapter 7.
Regulation 23 — Earthing and electrical protection — a low voltage network asset must be
earthed so that the resistance of the neutral conductor of the service line is not more than 1
ohm to earth
The forecast expenditure proposed by the distributors as being required to improve compliance
with the earthing requirements, together with the distributors’ assumptions, is set out in
Table 6.18. The forecast operating expenditure and capital expenditure is also provided to
appropriately compare where different capitalisation policies have been adopted.
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Table 6.18:
Distributors’ proposed expenditure, earthing and electrical protection, all
distributors, 2006-10, $million, real $2004
Opex
Capex
Total
AGLE
10.4
15.8
26.2
CitiPower
2.0
0.0
2.0
Powercor
9.5
0.3
9.8
SP AusNet
0.0
0.1
0.1
United Energy
17.1
0.0
17.1
Assumptions
Opex – a more sophisticated test of half
its service lines @ $93 per test
Opex – 15,000 tests per annum @ $35
per test, plus a controlled sample test of
1,500 services per annum @ $50 per
test
Opex – 52,000 tests per annum @ $35
per test, plus a controlled sample test of
1,500 services per annum @ $50 per
test
Opex and capex based on a risk
management approach. Cost to comply
with current regulations is $87.5m over
the five year period. If all service
cables tested every 10 years, then $16.4
million over 5 years based on 563,000
services.
Opex – 132,500 tests per year until
2010 and 62,000 tests in 2010 @ $32
per test.
The number and cost of tests proposed by CitiPower and Powercor appear reasonable.
Whilst AGLE’s assumption regarding the number of tests to be undertaken appears reasonable,
the cost of each test does not appear to be reasonable when compared to the cost proposed by the
other distributors. Accordingly, the Commission has reduced AGLE’s expenditure based on a
unit cost of $35 per test, consistent with that proposed by CitiPower and Powercor.
SP AusNet did not forecast any expenditure based on a risk management approach, but indicated
that the cost of testing each service cable every ten years would be $16.4 million over the five
year period. The Commission is of the view that it is reasonable that SP AusNet test half of the
services over the 2006-10 regulatory period. Given that SP AusNet has a similar number of
service cables to Powercor, expenditure of $9.5 million over the 2006-10 regulatory period has
been included in the revenue requirement for SP AusNet.
United Energy’s forecast expenditure is based on testing approximately one fifth of its service
cables in each year from 2006-09 and approximately one tenth of its service cables in 2010.
Given that service cables are required to be tested once every ten years, the Commission
considers that it is more likely that one tenth of the service cables will be tested in each year of
the 2006-10 regulatory period. The Commission is therefore of the view that it is more likely that
United Energy will undertake approximately 62,000 tests per annum. Accordingly, the forecast
expenditure to be included in the revenue requirement for United Energy has been reduced based
on undertaking 62,000 tests per annum.
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United Energy75 disagrees with this approach — it has advised that it has not been testing its
service cables as required, and therefore there is a catch up of testing in the first four years of the
period. The Commission notes that if an efficiency carryover amount has been obtained for not
undertaking these works as required during the 2001-5 regulatory period, this efficiency gain is
not sustainable, and customers should not pay twice (through a step change and through an
efficiency carryover amount).
The unit cost proposed by United Energy is considered to be reasonable.
The forecast capital expenditure is considered by the Commission in Chapter 7.
Regulation 27 — Inspection and testing — earth systems must be tested every ten years
The forecast expenditure proposed by the distributors as being required to improve compliance
with the requirement to inspect and test earth systems, together with the distributors’
assumptions, is set out in Table 6.19. The forecast operating expenditure and capital expenditure
is also provided to appropriately compare where different capitalisation policies have been
adopted.
Table 6.19:
Distributors’ proposed expenditure, inspection and testing, all distributors,
2006-10, $million, real $2004
Opex
Capex
Total
AGLE
0.3
4.1
4.4
CitiPower
0.7
0.7
1.4
Powercor
4.0
3.1
7.1
SP AusNet
0.8
7.4
8.2
United Energy
0.0
0.9
0.9
Assumptions
Opex - additional testing of earths in
rural areas approximately 320 tests per
annum @ $155 per test
Opex – test regime of high risk assets
(580 tests per annum @ $125 per test)
and random sample across network
(500 tests per annum @ $125 per test)
Opex – targeted test regime ($125,000
per annum) and additional program for
SWER distribution substations
($675,000 per annum)
Opex – 10,700 tests of SWER isolators
and substations ($0.9m, incremental
cost = $0.8m)
The step changes in operating expenditure proposed by the distributors to improve compliance
with these inspection and testing requirements appear reasonable.
The forecast capital expenditure is considered by the Commission in Chapter 7.
The step changes in operating expenditure to improve safety compliance that will be included in
the distributors’ revenue requirement are summarised in Table 6.20.
75
Email from Andrew Schille dated 7 October 2005
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Table 6.20:
Step changes in operating expenditure for safety compliance, all distributors,
2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Aerial service lines
0.0
1.7
8.4
5.0
0.4
Tramway assets
0.1
0.3
0.0
0.0
0.1
Underground lines
0.3
0.3
0.3
0.3
0.3
Aerial substations
0.3
0.4
0.0
0.0
-0.1
Earthing and electrical
protection
3.9
2.0
9.5
9.5
8.6
Inspection and testing of
earthing
0.3
0.7
4.0
0.8
0.0
Total
4.9
5.4
22.2
15.6
9.3
Electric line clearance
The Electricity Safety (Electric Line Clearance) Regulations 2005 were promulgated on 1 July
2005. These Regulations clarify various issues relating to the encroachment of vegetation
towards electric lines. However, ESV has indicated in correspondence with the distributors that:
With regard to the current industry practice of practical compliance rather than literal
compliance at all times on the clearance space between electric lines and vegetation, the
Regulations are unchanged.
The Office advises that it will not change its present interpretation or enforcement actions,
but will continue to ensure that literal compliance occurs during the Proclaimed Fire
Declaration Period for the area.
In a response to this correspondence dated 10 August 2005, CitiPower and Powercor have
indicated that Powercor has received legal advice that:
The [ESV’s] statement of intent in respect of non-enforcement of the Code (except during
Proclaimed Fire Declaration Periods) does not change distributors’ legal obligations to
comply with the Code. Distributors continue to have a legal obligation to comply with all
requirements of the Code, in the absence of an exemption from the [ESV] under r10 of the
Regulations.
Accordingly CitiPower, Powercor and SP AusNet have proposed expenditure which they assert
is necessary to ensure that at all times (that is, not just during a Proclaimed Fire Declaration
Period) their vegetation clearance is such as to comply with the electric line clearance
requirements set out in the Regulations.
The forecast expenditure proposed by the distributors as required to comply with the new
Regulations, together with the distributors’ assumptions, is set out in Table 6.21.
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Table 6.21:
Forecast expenditure, electric line clearance, all distributors, 2006-10,
$million, real $2004
Opex
Assumptions
AGLE
0.8
Anticipated expenditure at time of submitting proposal, however
proclamation of new Electricity Safety (Electric Line Clearance)
Regulations 2005 effectively removes AGLE’s exposure in this area
CitiPower
2.0
$0.4m to comply with the new Regulations and $1.6m to maintain
clearance at all times
Powercor
49.7
$2.2m to comply with the new Regulations and $47.5m to maintain
clearance at all times
SP AusNet
31.5
Additional cutting cycle
United Energy
0.5
Advice from a qualified arborist
In determining the revenue requirement for each distributor, the Commission must determine the
costs which it is reasonable to include in that requirement. If the Commission was to include an
allowance for expenditure that is unlikely to be required, then the distributor would make a
windfall gain to the extent that the expenditure is not actually incurred.
Given that ESV has indicated that it only intends to enforce literal compliance with the
requirements imposed by the Regulations as to the clearance between electric lines and
vegetation during Proclaimed Fire Declaration Periods, the Commission considers that a
reasonable allowance for the costs of complying with these Regulations is one that is based on
literal compliance with the Regulations during Proclaimed Fire Declaration Periods (as opposed
to during periods outside Proclaimed Fire Declaration Periods).
However, the Commission does regard the $0.4 million proposed by CitiPower and the $2.2
million proposed by Powercor to meet the new Regulations as the consequence of a change in
obligation which is appropriately regarded as a step change. Similarly the $0.5 million proposed
by United Energy has been included in the revenue requirement as a step change.
Consistent with the expenditure provided to CitiPower and Powercor, the Commission has also
included a step change of $0.4 million for AGLE and $2.2 million for SP AusNet.
Ageing assets
CitiPower and Powercor forecast increased operating and maintenance expenditure resulting
from the projected increase in the average age of their asset bases. CitiPower and Powercor were
of the view that ageing assets would result in increased operating and maintenance expenditure
because, to maintain service standards, the assets will become more resource intensive reflecting
the decline in the condition of the assets.
CitiPower and Powercor engaged SKM to assess the likely increase in inspections, maintenance
costs and failures arising as a result of the projected increase in the average age of their asset
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bases. Their preliminary conclusions were used to quantify an operating and maintenance
expenditure increase.
During the course of the review, the Commission noted that SP AusNet did not consider that
changes in operating and maintenance expenditure arising from the requirement to service ageing
assets were a ‘step’ change.
There are a number of areas where there is upward pressure on costs that are not assessed
as meeting criteria for a step change and are therefore not claimed as incremental
operating and maintenance cost [including]…increased maintenance costs due to the
gradual ageing of certain network assets (SP AusNet 2004f, p. 112).
SP AusNet’s modelling had indicated that maintenance costs would increase by $13 million over
the five year period due to ageing assets.
In its expenditure review prior to the Draft Decision, Wilson Cook and Co noted that ageing
assets were not a new phenomenon but were a feature of electricity supply networks and thus the
proposed expenditure was not a step change, but should be included in the rate of change.
In its Draft Decision, the Commission did not consider ageing assets a new (or changed) function
or legislative obligation and thus excluded this expenditure from the revenue requirements for
these distributors. Given that there was not a sharp increase in the age of assets (but rather a
steady increase in the age of assets) over time, increasing costs for maintaining ageing assets
should be reflected in the reported costs and therefore incorporated into the rate of change.
In response to the Draft Decision, CitiPower (2005g, p. 3) and Powercor (2005l, p. 4) stated that
whether the proposed expenditure was a step change or not was of no relevance. Failing to
provide for an efficient level of operating and maintenance expenditure in respect of ageing
assets leads to outcomes and/or incentives that are inconsistent with the Commission's
efficiency-related statutory objectives. These distributors also contend that, if the Draft Decision
on reducing replacement capital expenditure was translated into the Final Decision, then further
age-related maintenance costs would need to be incurred.
United Energy (2005i, p. 16) commented that the Commission's approach to the rate of change
did not explicitly allow for the ageing of network assets because there was no facility in the
original guidance that allowed the distributors to input opening and closing average asset lives.
As a result, United Energy requested an increase in operating and maintenance expenditure of
$300,000 per annum based on internal modelling and engineering assessments. According to
United Energy, if the Commission maintained its Final Decision, then the rate of ageing would
greatly increase and the impact of this ageing on operating and maintenance expenditure would
require a substantial and detailed review.
The Commission has analysed the change in the weighted average remaining life of assets
(weighted based on the written down value of assets) between 2001 (as forecast in the last price
review) and 2005 (as forecast in the current price review) and the change in maintenance costs
between 2000 and 2004. This analysis indicates that there is no correlation between the two
parameters (R2=0.06).
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Given that there is no correlation between the ageing of assets (represented by the change in the
weighted average remaining life of assets) and the change in maintenance costs, no additional
expenditure has been included for ageing assets. This is because the Commission is not satisfied
that ageing assets will lead to a change in maintenance costs.
Cost of apprentices
In their original price-service proposals, AGLE and United Energy proposed a separate step
change for apprentices which the Commission considered in conjunction with the increased
labour costs in its Draft Decision. AGLE indicated that it planned to increase the number of
apprentices taken on each year from 3 in 2004 to 8 in 2005 and then to 15 in 2007. Similarly SP
AusNet and United Energy indicated they would be increasing their intake of apprentices,
although SP AusNet had originally included these costs in its rate of change.
In its Draft Decision, the Commission included costs associated with increasing labour rates,
including the costs of apprentices, in the rate of change. The Commission’s analysis prior to the
Draft Decision indicated that there were various subsidies available from the federal and State
governments for apprentices so that the incremental costs to the distributor were unlikely to be
material.
In its response to the Draft Decision, AGLE (2005, p. 46) stated that it currently has an
arrangement with VICTEC Limited whereby apprentices are hired by VICTEC and provided
with 'on the job training' by the distributor. VICTEC receives the government funding as the
employer of apprentices whilst the distributor pays an hourly rate for apprentices while they are
working for and obtaining their 'on the job' training. AGLE also indicated that it provides
uniforms, safety equipment and other miscellaneous equipment as required for this ‘on-the-job’
training. Accordingly it considers that incremental costs are incurred by the distributors when
employing additional apprentices, and that these costs are material.
The Commission understands that the other distributors have a similar arrangement with
VICTEC.
In a submission to the Draft Decision, the Hon. Minister Theophanous (2005, p. 2) commented
that:
The capacity of Victoria's energy industry to provide a competitive, reliable and
sustainable energy supply depends fundamentally on the continued maintenance and
development of a skilled workforce. Industry faces important challenges in recruiting and
training skilled employees, arising from the ageing of the workforce, the low level of
interest in the industry of young people entering the workforce, the reduced level of
recruitment that followed industry reform, and the substantial investment and
technological change facing the energy sector in coming decades. As the primary
responsibility for meeting these challenges rests with the Businesses, the Government
urges the Commission to give regard to demonstrated programs of the Businesses that add
long term skills capacity to the Victorian electricity distribution sector.
The Commission sought further information from the distributors regarding their plans for
recruiting apprentices. CitiPower and Powercor considered they currently had a reasonable
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number of apprentices and therefore did not consider this to be a step change. AGLE, SP AusNet
and United Energy provided details regarding the number of apprentices to be employed and the
costs of these apprentices.
The Commission considers that the hiring and training of new workers to meet expanded
obligations or to replace retiring workers should be part of a long term human resource strategy
that a prudent distributor would already have in place to ensure that the distributors have the long
term skills capacity required. As indicated in the response from the Hon. Minister Theophanous,
the distributors clearly have the responsibility for maintaining this capacity.
The distributors have spent $200 million less on operating and maintenance expenditure than
was forecast as being required at the last price review. AGLE, SP AusNet and United Energy
will each be receiving an efficiency carryover amount in their revenue requirement as a result of
this underspending relative to the forecasts for the period. The claims by these distributors for
increased expenditure to meet the costs of new apprentices appear at odds with their claims that
the efficiencies they have achieved are sustainable over the longer term.
Additionally, the Commission considers that any increased costs incurred employing apprentices
within the industry will already be reflected in the rate of change.
Therefore, the Commission has not included the costs of apprentices as a step change because it
does not consider this a new (or changed) function or legislative obligation.
GSL payments scheme
In determining the base level of operating and maintenance expenditure, the distributors were
required to deduct the GSL payments that they expected to pay in 2004. Whilst CitiPower,
Powercor and United Energy did not deduct any expenditure for GSL payments in determining
the base operating and maintenance expenditure forecast, AGLE deducted $0.05 million and SP
AusNet deducted $1.82 million.
The distributors were then expected to include forecast expenditure required for GSL payments,
based on their proposals for the GSL payments scheme over the 2006-10 regulatory period, in
the operating and maintenance expenditure step changes. The distributors’ proposals for the GSL
payments scheme are discussed in the Chapter 3. AGLE, SP AusNet and United Energy most
recently forecast expenditure of $1.1 million, $41.5 million and $3.5 million respectively, over
the 2006-10 regulatory period for GSL payments.
In its Draft Decision, the Commission considered increased expenditure arising from the changes
to the GSL payments scheme was a step change because it was a changed regulatory obligation
from 1 January 2006. Consequently, the expenditure on GSL payments in 2004 was excluded
from the calculation of the base operating and maintenance expenditure but the forecast cost of
meeting the revised GSL payment scheme was included in the revenue requirement.
In response to the Draft Decision, the distributors indicated that additional expenditure was
required for them to meet their GSL payment obligations.
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In light of this, the Commission has re-examined the thresholds of the revised GSL payments
scheme (see Chapter 3). The expenditure required by the distributors to meet their GSL payment
obligations has been revised in accordance with these thresholds and included as a step change.
Road Management Act
The Road Management Act 2004 (RMA) has legislated a number of specific requirements that
utility infrastructure and service providers must adhere to when their operations affect the
physical structure or operation of roads. According to United Energy, regulations are still being
developed that are expected to exempt specific works from requirements to obtain consent or
give notice.
The additional costs associated with the implementation of the RMA are claimed to include the
establishment of systems and processes for accreditation, consent and notification processes, and
payment of prescribed fees (United Energy 2004e, p. 126). Consequently, each distributor has
proposed an increase to their operating and maintenance expenditure requirements. AGLE,
CitiPower and Powercor have also proposed an increase of $4.6 million, $3.0 million76 and
$17.9 million respectively to their capital expenditure requirements.
However, as AGLE noted, the details of the Act will not be known until the Codes of Practice
underpinning the Act are developed over the next few years.
In its Draft Decision, the Commission included expenditure associated with the RMA as a step
change because it considered this a new legislative obligation from 2005 and so would not be
reflected in the base level of operating and maintenance expenditure in 2004. The Commission
indicated that an expenditure amount would be incorporated into the revenue requirement for the
next regulatory period.
Whilst AGLE, SP AusNet and United Energy accepted the Draft Decision, CitiPower and
Powercor noted that the Draft Decision did not fully allow the amounts sought by them. In a late
submission prior to the Draft Decision, CitiPower and Powercor increased their proposed
expenditure by $1.5 million and $6.8 million respectively. Given the short notice of this increase,
the Commission did not have the time to consider the increase and so incorporated only 50 per
cent of the additional costs proposed by CitiPower and Powercor in the Draft Decision.
CitiPower and Powercor have since provided a full break down of the costs associated with
permits and road authority interfacing, and confirmed that there was no overlap between
operating and maintenance expenditure and capital expenditure.
In its submission to the Draft Decision, the Streetlighting Group of Councils (2005, p. 8) did not
agree that the RMA imposed new obligations on the distributors that would require an increment
of cost anywhere near the $27.2 million proposed by the distributors. It contended that the
responsibilities imposed on distributors under the RMA were no more onerous than their current
obligations under relevant OH&S and Planning and Environment legislation, and through
individual responsibilities required by Local Government by virtue of the Local Government Act
76
Excluding overheads
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1989. According to the Streetlighting Group of Councils, the spirit and intent of the RMA was
only to standardise and consolidate disparate statutory obligations as they relate to road
reservations under a single statutory instrument, rather than to extend those obligations.
The Commission notes that the Regulatory Impact Statement that accompanied the RMA
contemplated that additional costs in the form of consent fees would be incurred by the
distributors. The RIS did not include the additional administrative costs that would be incurred
by the distributors in applying for permits and in notifying VicRoads of works.
Therefore, the Commission remains concerned about the increase in costs submitted by
CitiPower and Powercor, particularly given the uncertainty as to how the obligations will be
enforced, the amounts included by CitiPower and Powercor in their capital expenditure forecasts,
and the operating and maintenance expenditure proposed relative to the other distributors.
The Commission continues to be of the view that the Road Management Act is a new legislative
obligation and should be considered as a step change. However, whilst it continues to be of the
view that the expenditure proposed by AGLE, SP AusNet and United Energy is reasonable, and
that the expenditure originally proposed by CitiPower and Powercor is reasonable, it is not
convinced that the additional expenditure proposed by CitiPower and Powercor shortly before
the Draft Decision is reasonable.
The amounts included with the revenue requirement for this step change are set out in
Table 6.22.
Voltage compensation claims
As discussed in Chapter 2, the distributors are required to compensate residential and small
business customers for damage due to voltage variations (surges and brown outs). The
Commission codified the circumstances in which customers are entitled to compensation in the
Electricity Industry Guideline No. 11: Voltage Variation Compensation.
Insurance companies have the right of subrogation under the law. The Commission recently
clarified that its guideline on voltage variation compensation does not prevent the insurance
companies’ right to subrogation under the law.
Each distributor proposed additional expenditure to cover claims made by insurance companies,
in anticipation that this clarification will increase the number of claims by insurance companies.
The additional operating and maintenance expenditure originally proposed by the distributors
varied from $0.3 million for CitiPower to $3.6 million for AGLE over the 2006-10 regulatory
period.
AGLE also proposed expenditure for the introduction of a ‘new-for-old’ policy, similar to that
proposed by CitiPower and Powercor in their enhanced service offerings. The introduction of a
‘new-for-old’ policy has been discussed in Chapter 2.
Wilson Cook and Co reviewed the expenditure proposed by the distributors and found that the
proposed amounts were reasonable.
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Having given consideration to the views expressed by Wilson Cook and Co and the distributors,
in the Draft Decision, the Commission included expenditure for voltage variation claims as a
step change as it was considered a change in regulatory obligations following the Commission’s
2004 clarification of the Electricity Industry Guideline No. 11: Voltage Variation Compensation
in regard to insurance companies’ rights to subrogation.
For these purposes the amount the Commission included for this expenditure were as proposed
by the distributors, with the exception of AGLE. The Commission considered that expected
expenditure would be lower than that forecast by AGLE. AGLE has a smaller number of
customers than Powercor, SP AusNet and United Energy, and the number of over voltage events
reported by AGLE is significantly less than these three distributors. Therefore, AGLE’s
expenditure would be expected to be lower than that incurred by Powercor, SP AusNet and
United Energy.
AGLE and United Energy were the only stakeholders to comment on this issue and both
distributors accepted the Commission’s Draft Decision.
Therefore, the Commission has included amounts for voltage compensation claims as a step
change. The amounts included are the same as those included in the Draft Decision.
Growth-related faults
According to its submission, Powercor believes that unexpected, gradual load growth will result
in load related faults on low voltage circuits and distribution substations, and increased voltage
variation complaints.
For the purposes of the Draft Decision, both Wilson Cook and Co and the Commission
considered that this expenditure was not a step change because it was not a new (or changed)
function or legislative obligation.
In response to the Draft Decision, Powercor stated that this step change was justified for the
following reasons:
•
Wilson Cook and Co acknowledged the legitimacy of load-related maintenance
expenditure in its final report.
•
Further factual evidence was provided to demonstrate that expenditure on growth-related
faults in 2004 was below average.
•
The impact of growth-related expenditure varies with system dynamics and the degree to
which a distributor is ‘rural’ or low density. Consequently, Powercor considered the issue
unique to rural distributors.
Since the release of the Draft Decision, the Commission has included a growth-related
component to operating and maintenance expenditure (see Section 6.2.4). The Commission is of
the view that this growth-related component addresses changes in operating and maintenance
expenditure that are related to growth. This includes the expenditure proposed for growth-related
faults. Additionally the Commission notes that the expenditure allowed under this growth-related
component is well in excess of the amount that Powercor has proposed for this step change.
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Therefore, the Commission has not included additional expenditure for this item as a step
change.
Audits and accreditation
The distributors proposed step changes arising from their obligations in regard to various audits
and accreditations.
•
AGLE, CitiPower and Powercor submitted additional operating and maintenance
expenditure for audits required by ESV during the 2006-10 regulatory period.
•
AGLE and United Energy submitted additional operating and maintenance expenditure for
regulatory audits required to be undertaken by the Commission.
•
AGLE submitted additional operating and maintenance expenditure for financial audits
required to be undertaken by the Commission.
•
CitiPower and Powercor submitted additional operating and maintenance expenditure for
internal audits.
OCEI (ESV) audit and regulatory audit
ESV undertook a major audit of the distributors in 2001, but has not undertaken an audit since.
Accordingly, AGLE, CitiPower and Powercor were of the view that the costs associated with an
ESV audit were not included in the actual operating and maintenance expenditure for 2004.
Therefore, these distributors did not believe that this required expenditure has been included in
the base operating and maintenance expenditure forecast and noted that ESV has foreshadowed
more frequent audits in the 2006-10 regulatory period.
The Commission conducted a desktop audit of the distributors’ regulatory obligations in 2004.
AGLE and United Energy were of the view that minimal costs associated with the Commission’s
regulatory audits were included in the actual operating and maintenance expenditure for 2004
and thereby in the base operating and maintenance expenditure forecast. These distributors have
also noted that the Commission has foreshadowed annual audits in the 2006-10 regulatory
period. Therefore, they proposed additional operating and maintenance expenditure.
In the Draft Decision, the Commission did not include expenditure for this item as a step change
because it did not consider it a new (or changed) function or legislative obligation. Additionally
it noted that the 2004 base operating and maintenance expenditure (and benchmarks from the
previous price review) includes higher regulatory costs associated with the conduct of this price
review. This higher level of costs was not expected to be incurred during the first three years of
the next regulatory period, and therefore would offset costs associated with other regulatory
obligations not incurred in 2004, such as the ESV and regulatory audit costs, in addition to the
transition from state-based to national regulation.
While United Energy accepted the Draft Decision, CitiPower and Powercor did not on the basis
that they believe regulatory costs will increase substantially due to the change from state-based
to national regulation, and that a price review spans multiple years.
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The Commission notes that the distributors will spend in the order of $1 million each, if not
more, on the price review in each of 2004 and 2005. This higher level of expenditure is included
in the base operating and maintenance expenditure for each distributor. However, this
expenditure is not expected to be incurred in 2006, 2007 or 2008, but is expected to be incurred
in 2009 and 2010. As a result, the base operating and maintenance is in the order of $3 million
higher for each of the distributors than if the phasing of expenditure had been considered in the
expenditure forecasts.
For this reason, the Commission continues to be of the view that the higher level of costs
provided through the inclusion of the costs associated with the price review will offset costs
associated with other regulatory obligations not incurred in 2004, such as these ESV and
regulatory audit costs.
Financial audit
In the Draft Decision, the Commission included additional expenditure as a step change for the
costs incurred from financial audits as this was a changed regulatory obligation for AGLE.
While distributors are required to accompany the submission of their regulatory accounting
statements with a Special Purpose Financial Report, AGLE has accompanied its regulatory
accounting statements with a Review Report. Additional operating and maintenance expenditure
was allowed for AGLE because the cost of a Special Purpose Financial Report is higher than a
Review Report and thus, for AGLE, base level operating and maintenance expenditure may
understate the costs of financial audits.
However, the Commission noted that it had allowed AGLE to submit its regulatory accounting
statements on the same financial year basis as its statutory accounts, rather than on the current
calendar year basis. This will enable AGLE to have an audit on its regulatory accounts in
conjunction with its statutory accounts, which will offset in part the additional costs associated
with a Special Purpose Financial Report.
AGLE agreed with the Commission’s approach to this issue and thus the Commission has
maintained this approach in its Final Decision.
Internal audits
CitiPower and Powercor have an internal risk-based audit program where the level of auditing is
driven by a fixed percentage of the total work conducted over the network. According to
CitiPower and Powercor, the anticipated increase in total workloads over the 2006-10 regulatory
period means that additional auditing will be required to maintain the current sample rate to
support the risk-based approach.
Additionally CitiPower in a confidential submission to the Commission proposed a step change
in expenditure for audits and accreditation for the following reasons:
•
To fund the roll out of its Contractor Performance Management System (CPMS) to the
majority of its external suppliers and audit all field projects undertaken by contractors.
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•
Greater competition in the provision of customer contestable works driving the need for an
increase in accreditation and quality auditing regimes around contractors hired by
customers for these external works.
Powercor, also in a confidential submission, proposed a step change in expenditure for audits and
accreditation for the following additional reasons:
•
An increased number of customer works (where customers choose their own contractor,
rather than having to use Powercor for the works) undertaken due to revised rules and
processes expanding the range of work and simplifying this option for customers.
•
A requirement by ESV for increased self and independent auditing of new customer
connection works.
In the Draft Decision the Commission indicated that, with the exception of the customer
connection inspections, the Commission did not consider internal audits a step change because it
was not considered a new (or changed) function or legislative obligation.
The Commission noted that a letter from ESV dated 10 September 2004 indicated that a higher
level of inspection of connection works would be required. However, the Commission was of the
view that the costs associated with these works are included in the excluded service charge for
new connections.
The Commission also noted that:
•
the capital expenditure for new connections included in the Draft Decision was less than
that proposed by CitiPower and Powercor and that therefore the audit programme would
not need to be expanded at the rate proposed; and
•
no new (or changed) function or legislative obligation for internal audits was envisaged for
the 2006-10 regulatory period.
In response to the Draft Decision, CitiPower and Powercor accepted the Commission's view on
the costs of customer connection inspections provided that the associated cost was included in its
excluded service charge. The Commission notes that these costs would only be included in the
excluded service charge if CitiPower and Powercor submit a revised schedule of charges in
accordance with Electricity Industry Guideline Number 14, and these revised charges were
approved by the Commission.
CitiPower and Powercor were of the view that other costs arising from internal audits should be
included for the following reasons.
•
It was consistent with the primary objective of protecting the long term interests of
consumers.
•
It was consistent with the facilitating objective of efficiency and facilitating effective
competition.
•
The Commission’s statement that capital expenditure is lower than proposed was flawed.
The physical volume of capital expenditure drives the expansion of audits and accreditation
rather than the financial value of that capital expenditure.
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The Commission remains of the view that this is not a new (or changed) function or legislative
obligation and is therefore not considered to be a step change. Additionally the Commission
notes that, where there is no new or changed function or legislative obligation but an increase in
the volume of work, these additional costs are recovered through the rate of change and the
impact of growth.
Asset inspections
In a late submission prior to the Draft Decision, CitiPower proposed a step change in expenditure
to increase the frequency of inspection of low voltage assets and Private Overhead Electric Lines
(POELs). CitiPower indicated that ESV had requested that the frequency of inspections be
increased following a Bushfire Mitigation Audit in 2004 to ensure that it complied with the
Electricity Safety (Bushfire Mitigation) Regulations 2003.
The Commission did not include the expenditure for asset inspections as a step change in its
Draft Decision, but noted that prior to its Final Decision it would consult with ESV regarding the
need for this proposed step change. ESV has confirmed that CitiPower was not compliant with
its requirement to inspect POELs every 36 months. However, ESV also noted that there were not
many POELs in CitiPower’s area.
In these circumstances, the Commission concluded that this was a changed legislative obligation
for CitiPower and sought further information from CitiPower (and other distributors) regarding
the number of POELs in their respective areas. From the information provided by CitiPower the
Commission noted that an additional 156 inspections were required per annum at a cost of
$705 per inspection. Given the density of CitiPower’s area, the Commission does not consider
this to be a reasonable cost for each inspection, and has reduced the forecast expenditure for this
step change from $0.6 million to $0.2 million over five years.
Occupational health and safety
SP AusNet indicated that WorkSafe Victoria introduced two new requirements in 2004.
•
First, regulations came into operation, as of 31 March 2004, with the overall objective to
prevent incidents at workplaces involving falls of more than 2 metres and to prevent or
reduce injury resulting from those falls. SP AusNet estimated that incremental operating
and maintenance expenditure of approximately $4.8 million over the 2006-10 regulatory
period was required to meet this requirement.
•
Second, new guidelines were introduced in July 2004 in relation to work practices and
procedures that must be followed when working in the vicinity of overhead lines and
underground cables. SP AusNet estimated that incremental operating and maintenance
expenditure of approximately $2 million would be required over the 2006-10 regulatory
period to meet this requirement.
In relation to the prevention of falls, SP AusNet has indicated that work is underway to meet the
requirements but that further reduction of risk is required. The Commission noted that AGLE has
also proposed additional capital expenditure to address this issue. In relation to the guidelines on
undertaking work near overhead and underground assets, SP AusNet anticipated increased
workloads responding to queries from the Melbourne One Call Centre.
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SP AusNet also indicated that s. 207 of the Occupational Health and Safety (Asbestos)
Regulations 2003 limits the removal of asbestos without a licence. SP AusNet does not currently
require a licence to work with asbestos. However, according to SP AusNet, its proposed program
of work for zone substations over the 2006-10 regulatory period will require it to obtain an
asbestos removal licence. SP AusNet has forecast the incremental cost to current practices of
complying with the requirements to maintain an asbestos removal licence at $0.3 million over
the 2006-10 regulatory period.
In its Draft Decision, the Commission considered this a step change and an amount was included
in SP AusNet’s revenue requirement for the related expenditure. The amounts included were
adjusted by the Commission based on the advice it had received from Wilson Cook and Co.:
•
The proposed expenditure to prevent falls ($4.8 million) was reduced by 50 per cent as,
based on its experience, it was regarded as being greater than necessary;
•
The proposed expenditure to automate records of underground lines ($1.5 million) was not
included in the expenditure requirement on the basis that this is a process improvement.
Process improvements will only be undertaken by a prudent business where the benefits
exceed the costs. Given that there is no reduction to reflect the benefits, the costs should
also not be included.
In response to the Draft Decision, SP AusNet indicated that it did not understand the level of
adjustment made and proposed an additional step change of $0.7 million to meet new training
requirements which came into effect 1 July 2005.
The Commission remains concerned that no other distributors have proposed this change in
legislation as a step change for changes to the legislative requirements for occupational health
and safety, although it is noted that AGLE has included additional expenditure in its proposed
capital expenditure for this reason. There is a potential for double counting by SP AusNet
whereby the proposed additional expenditure could be included as a step change and could also
be reflected in the proposed capital expenditure.
With regard to the proposed expenditure to automate records of underground lines, the
Commission notes that a step change in expenditure for each of the distributors to improve the
records of underground lines has been included under the cost of safety compliance
(Regulation 20).
Given the uncertainties associated with this particular proposed step change, the Commission has
upheld its Draft Decision. Additionally it has included the amount proposed by SP AusNet for
training as a step change.
Critical infrastructure protection
AGLE, CitiPower, Powercor and SP AusNet forecast additional operating and maintenance
expenditure as a result of the apparent increasing threat of terrorism. AGLE, SP AusNet and
United Energy also forecast additional capital expenditure to address this issue.
CitiPower, Powercor and SP AusNet indicated that the additional expenditure was associated
with meeting requirements under the Terrorism (Community Protection) Act 2003. According to
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these distributors, this Act requires them to establish and implement risk management plans,
conduct reviews and audits, take part in exercises and make all improvements necessary to
protect the State’s critical infrastructure including the distribution assets.
While AGLE did not refer to the Terrorism (Community Protection) Act 2003 in its price-service
proposal, it had undertaken reviews of the security of key infrastructure, which led to a number
of initiatives to improve the security of key installations. Additional operating and maintenance
expenditure was forecast for additional patrols of key infrastructure and remote monitoring of
alarms by accredited security service providers.
SP AusNet also forecast additional operating and maintenance expenditure to respond to
heightened security measures that are foreshadowed following several fatalities in NSW. These
measures included communication or public education programs, increased primary security
measures (improved fencing, locks etc) and increased detection measures (monitoring alarms,
closed circuit television (CCTV) etc).
In the Draft Decision, incremental expenditure was included for critical infrastructure protection
as the Commission considered that expenditure was required to meet recent legislative
obligations that came into effect in 2004. Consequently, the expenditure levels proposed by the
distributors were included in the revenue requirements. This followed advice from Wilson Cook
and Co that the proposed amounts appeared reasonable.
While AGLE accepted the Draft Decision, United Energy identified that the forecast in its initial
submission was insufficient for securing critical infrastructure. It proposed $200,000 per annum
for increased patrols when the alert level is high and permanent manning for when the alert level
is extreme, and $100,000 per annum to prepare risk management plans, audit risk management
plan, participate in training exercises, and if necessary, to certify risk management plans.
The expenditure proposed by United Energy appears reasonable when compared to the
expenditure proposed by the other distributors. The expenditure proposed by each of the
distributors to meet its obligations under the Terrorism (Community Protection) Act 2003 has
therefore been included in their respective expenditure requirements.
Allowance for cost of self-insurance
In its price-service proposal, SP AusNet proposed an allowance of $6 million over the
2006-10 regulatory period for the cost of self-insurance of low likelihood high impact risks. SP
AusNet claimed that such an allowance would enable it to cover the cost of replacing items
damaged as a result of a rare event which was not insured. An example of such an event was a
significant bushfire in SP AusNet’s distribution area.
In its price-service proposal, SP AusNet referred to recent decisions by the Australian
Competition and Consumer Commission and the Independent Pricing and Regulatory Tribunal in
NSW to allow self-insurance costs.
In its Draft Decision, the Commission noted that there may have been a need to provide for self
insurance, however self-insurance could not be considered a step change because it was not
linked to a new (or changed) function or obligation.
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SP AusNet provided a report prepared for it by SAHA International that identified and quantified
the self-insured risks. In Chapter 5, the Commission has noted that this report overstates the risks
associated with the loss of poles and wires. The report assumed that the amount to be provided
reflects the total replacement cost of the poles and wires. However, given that any assets
installed will be rolled into the regulatory asset base at the time of the next price review, and
given the absence of an efficiency carryover mechanism, the only costs incurred by SP AusNet
are the financing costs for a period of approximately two and a half years.
With the Commission’s approach to assessing capital expenditure at the aggregate level, the
Commission considers that there should be some flexibility for the financing costs associated
capital expenditure above the forecast, up to a cap, to also be rolled into the regulatory asset
base, based on the circumstances (see Chapter 7). The Commission considers that substantial
losses of poles and wires may be a factor that is taken into account by the relevant regulator at
the time of the next price review when considering whether these additional financing costs
should be rolled into the regulatory asset base.
The Commission considers this to be the appropriate approach for dealing with these risks, rather
than including additional operating and maintenance expenditure as a step change.
SP AusNet was also proposing to self insure for the financial failure of a retailer. However, as
noted in Chapter 12, the financial failure of a retailer will be a relevant pass through event in the
2006-10 regulatory period.
The Commission does not consider self insurance to be a new (or changed) function or
regulatory obligation and has therefore not regarded it as a step change.
It should be noted that the base operating and maintenance expenditure has been adjusted
upwards for all the distributors for uninsured losses and for Powercor and SP AusNet for the
excess on third party claims for bushfire damage.
Premature failure of XLPE underground cables
In their original price-service proposals, AGLE and Powercor stated that operating and
maintenance expenditure would increase over the regulatory period to reflect the projected
premature failure of cross linked polyethylene (XLPE) underground cables. Both distributors
indicated that the installed XLPE cables would not achieve a 40 or 50 plus year life as
anticipated and were now, in many cases, reaching the end of their reliable life after only 20 to
25 years.
AGLE and Powercor suggested that the cost impact arises through an increased need to monitor
and test the cable condition, and that this cost is expected to increase by approximately $100,000
per annum and $650,000 per annum respectively.
Wilson Cook and Co noted that an increase in cable monitoring and testing may have been valid
in these circumstances but that it did not meet the definition of a step change. In its Draft
Decision, the Commission also considered that this expenditure was not associated with a new
(or changed) function or legislative obligation and thus no allowance was included in the revenue
requirements for the 2006-10 regulatory period.
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In response to the Draft Decision, AGLE has withdrawn this as a proposed step change whilst
Powercor continues to be of the view that the step change proposed was justified. Its reasons are
as follows:
•
External technical advice confirmed that there was an emerging issue of premature failure
of underground cables.
•
Wilson Cook and Co had acknowledged the legitimacy of the expenditure.
•
The expenditure was not reflected in the 2004 operating and maintenance expenditure —
the program was published in December 2004 and implemented in 2005.
•
Failure to recognise this expenditure would necessitate inefficient premature replacement
of a number of underground cables.
The Commission notes that while the distributors identified assets for which additional
maintenance was required, the distributors did not identify assets for which maintenance may
have been deferred. Additionally the Commission continues to be of the view that this
expenditure is not associated with a new (or changed) function or legislative obligation and thus
no allowance has been included in the revenue requirements for the 2006-10 regulatory period.
SCADA master station upgrade
CitiPower purchases SCADA Master-Station services from SPI Powernet to support its control
centre functions. It is claimed that SPI Powernet is proposing to upgrade the system in 2007 and
is proposing to levy CitiPower $0.49 million for its share of the upgrade cost.
Wilson Cook and Co considered this item should be capitalised. However, CitiPower indicated
that it can not be capitalised because it is not an asset that it owns.
In its Draft Decision, the Commission indicated that it did not consider this a step change
because it was not linked to a new (or changed) function or legislative obligation.
Further, it was noted that the distributors have identified increases to their operating and
maintenance expenditure based on expenditure incurred in years other than 2004, but have not
identified reductions to their operating and maintenance expenditure based on expenditure
incurred in 2004 but not expected to be incurred in 2006-10. The Commission was of the view
that it was reasonable to expect that expenditure increases and reductions would largely net out
and thus a step change was not required.
Stakeholders did not comment on this issue in their responses to the Draft Decision although in
discussions with the Commission CitiPower has noted its concern with the Commission’s Draft
Decision.
The Commission’s review of CitiPower’s operating and maintenance expenditure incurred in
2004 has resulted in adjustments for any expenditure incurred in 2004 that was not considered to
be recurrent (see Chapter 5). It is therefore not reasonable to assume that non-recurrent
expenditure incurred in 2004 will offset this proposed expenditure.
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Additionally the Commission notes that CitiPower’s obligation to pay for the upgrade of the
SCADA master station is an obligation placed on it by a third party. If the expenditure was not
included in CitiPower’s expenditure requirement, then CitiPower may choose the inefficient
option of replicating its own SCADA master station. For these reasons, the Commission now
regards this as a changed obligation, and has included the proposed expenditure in the revenue
requirement.
SPI Powernet augmentation
Powercor originally proposed $1.1 million associated with switching and non-capital relocation
of existing assets arising from SPI Powernet’s asset replacement program during the
2006-10 regulatory period.
At the time of the Draft Decision, the Commission did not have sufficient information available
for it to consider this expenditure a step change, although the Commission noted that other
distributors had not proposed similar step changes. Since then, the Commission has undertaken a
further review of this issue.
The expenditure outlined by Powercor was estimated based on the works program proposed by
SPI PowerNet. Powercor considered this expenditure a step change because SPI PowerNet had
undertaken a very low level of work in Powercor’s area in 2004.
Powercor also noted that it was not in a position to know what work programs had been
undertaken in other distributors’ areas in 2004 and so could not comment on the reason why
other distributors had not proposed a similar step change. In Powercor’s view, the Commission's
obligation is to consider expenditure based on actual works being undertaken by Powercor.
Since the Draft Decision, SP AusNet has indicated that SPI PowerNet has planned a number of
initiatives that will require it to undertake works on its assets at the connection interface. SP
AusNet stated that they have agreed to coordinate their respective asset replacement activities to
coincide with SPI PowerNet's program, and has proposed a step change of $0.5 million over the
2006-10 regulatory period accordingly.
The Commission notes that with the vertical separation in the electricity industry, there is a need
to coordinate the works between SPI PowerNet and the distributors. Works at the transmission
level are more critical to a reliable and secure electricity supply than the works at the distribution
level as more customers are supplied from a single point on the transmission system than the
distribution system.
SPI Powernet has written to both Powercor and SP AusNet to advise its current plans for works
at terminal stations in their area. The letter to Powercor dated 2 August 2005 (as an example)
states that:
As per usual processes we will require Powercor to coordinate switching, relocation or
alteration of its system as required to facilitate these works. … [SPI Powernet] also
confirms that any DB relocation costs have not been provided for in their revenue cap.
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The works undertaken by SPI PowerNet place an obligation on the distributor. The Commission
therefore considers that this is a changed obligation imposed on the distributors by a third party
and that the expenditure proposed by the two distributors should be incorporated in the revenue
requirement.
Electricity demand side response
In its original price-service proposal, AGLE proposed $0.6 million for negotiating with potential
demand side suppliers, developing technical and operating standards, and legal costs associated
with entering agreements with demand side suppliers.
Wilson Cook and Co regarded the proposed expenditure as prospective and not necessarily
related to a new function or obligation as demand management has always been an attribute of
efficient utility operation.
However, some stakeholders, particularly the Victorian Consumers’ Group, supported additional
incentives for the distributors to introduce additional demand side management initiatives. The
view was expressed that additional expenditure should be incorporated in the revenue
requirement even if there was no guarantee that the distributors will deliver an outcome, given
the potential long term benefits to customers if the peak demand is reduced and augmentation
costs are reduced.
In its Draft Decision, the Commission did not consider expenditure associated with electricity
demand side response a step change because it was not linked to a new (or changed) function or
legislative obligation. However given the strong views expressed by consumer representatives
and the materiality of the expenditure proposed, the Commission incorporated the step change
proposed by AGLE in the revenue requirement, and also included the same amount for the other
distributors. The Commission indicated that it would require the distributors to report on an
annual basis the demand side activities that have been undertaken and the outcomes that have
been delivered.
While AGLE and United Energy supported the inclusion of expenditure for demand side
response, the Department of Sustainability and Environment stated that it was important to
ensure that the distributors reported to stakeholders on the success or otherwise of their demand
management programs. It suggested that the Commission could establish a demand management
consultation group which could invite the distributors to present progress on their demand
management programs. The Commission will consider this and notes that there are a variety of
forums that could be utilised for presentations by the distributors.
No stakeholders opposed the inclusion of this expenditure in the revenue requirement, even if
there is no guarantee that the distributors will deliver an outcome. Accordingly, the Commission
will include an amount in the revenue requirement for each distributor for negotiating with
potential demand side suppliers, developing technical and operating standards, and legal costs
associated with entering agreements with demand side suppliers. The Commission will require
distributors to report on an annual basis the demand side activities that have been undertaken and
the outcomes that have been delivered.
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Additional step changes proposed by AGLE
In its original price-service proposal, AGLE proposed a number of other step changes. These
were as follows:
•
Mobile computing implementation — forecast an additional $2 million to procure ongoing
support from the vendor of a new mobile computing system that is planned to be
implemented.
•
Outage management, market and billing systems — forecast an additional $1.9 million to
procure ongoing support from the vendor of a new outage management system that is
planned to be implemented.
•
Head Office relocation costs — forecast an additional $0.8 million to relocate its head
office when its current lease expires.
•
Ring fencing — forecast an additional $0.8 million to comply with the Commission’s Draft
Decision on ring-fencing. The additional expenditure proposed was for location changes
($0.1 million), training ($0.25 million), reviewing procedures ($0.1 million), compliance
auditing ($0.2 million) and IT enhancements ($0.15 million).
•
Public consultation on various matters — forecast an additional $0.5 million to carry out
more customer and stakeholder consultation, particularly in areas such as network pricing
and network development.
•
Sponsorship and marketing — forecast an additional $0.03 million for marketing of
multiple supply tariffs to retailers and $0.4 million to fund economic development groups
within its area.
•
Additional EWOV cases — forecast an additional $0.2 million to manage an expected
increase in the number of claims raised with EWOV in relation to voltage compensation
claims.
•
Gather and provide data on all public lighting poles — forecast an additional $0.2 million
to collect, record and disseminate information on public lighting in accordance with the
Public Lighting Code.
•
Financial report for 2009 regulatory financial information — forecast an additional
$0.1 million to provide audited regulatory accounts to the Commission on a calendar year
basis in the penultimate year of the regulatory period, in addition to the regulatory accounts
submitted on a financial year basis. The Commission requested this financial information
as a condition to change the submission of regulatory accounts from a calendar year basis
to a financial year basis.
Shortly prior to the release of the Draft Decision, AGLE proposed further step changes to reflect
the costs associated with changes that had been proposed to the service standards and service
incentive arrangements.
In its Draft Decision, the Commission considered that only the expenditure associated with ring
fencing and the financial report for 2009 regulatory financial information could be considered
step changes and linked to new (or changed) functions or legislative obligations. With regard to
ring fencing, the Commission noted that it released a ring fencing guideline in October 2004.
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AGLE’s submissions during the consultation process for that guideline indicated that it did not
comply with the proposed requirements. With regard to the financial report for 2009 regulatory
financial information, the Commission noted that this was an additional requirement by the
Commission to transition from calendar year end reporting to financial year end reporting
(consistent with its statutory accounts) for AGLE.
With regard to the other items, the Commission considered that many of the proposed
expenditure items would already be included in the 2004 base level of operating and
maintenance expenditure, and in the case of changes proposed to the service standards and
service incentive arrangements, that the proposed changes that AGLE was responding to had not
been included in the Draft Decision. Furthermore, any business process improvements which
resulted in lower costs will be self financing because the net costs would be expected to be less
than those reflected in the revenue requirement.
AGLE subsequently withdrew the proposed step changes for each of these step changes except
ring fencing, the financial report for 2009 regulatory financial information, and a change to the
GSL payments scheme from supply restoration time to annual duration of interruptions. With
regard to the change in the GSL payments scheme, it argued that its systems could not provide
such information and that $0.1 million was required to amend its systems and $0.11 million per
annum was required to administer the GSL payments scheme.
The only other comments provided on the Draft Decision regarding AGLE’s various step
changes were provided by the Streetlighting Group of Councils who supported the decision to
not include the gathering and provision of data on public lighting poles as a step change.
The Commission continues to be of the view that the expenditure proposed for ring fencing ($0.8
million) and the financial report for 2009 regulatory financial information ($0.1 million) are
considered to be step changes and that the expenditure proposed is reasonable. With regard to the
changes to its systems to accommodate the change in the GSL payments scheme, the
Commission also considers this to be a change in obligation and thus a step change. Furthermore,
the expenditure proposed is reasonable given the current state of AGLE’s systems. However,
given the number of GSL payments administered by AGLE, the Commission is of the view that
no incremental costs will be incurred by AGLE on an annual basis and the proposed expenditure
has not been included as a step change.
Additional step changes proposed by SP AusNet
Like AGLE, SP AusNet also proposed a number of additional step changes. These were as
follows:
•
Automated B2B — forecast incremental costs of $6.5 million to manage exceptions arising
from higher levels of B2B transactions with the new automated systems and processes that
are planned.
•
Distribution Code: Quality of Supply — forecast an additional $2 million for load
balancing to address negative sequence compliance under the Electricity Distribution
Code.
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•
Utility Meters Act and Regulations — forecast an additional $1.7 million to comply with
the requirements of the Utility Meters (Metrological Controls) Act 2002 and associated
regulations.
•
Testing of CTs and VTs — forecast an additional $1.5 million to comply with the CT and
VT test requirements in the Electricity Customer Metering Code.
•
NEMMCO standard for data communications — forecast an additional $0.7 million for
costs associated with providing data, in accordance with NEMMCO’s standards, from
large wind farms that may be connected during the regulatory period.
•
OCEI (ESV) levy savings — forecast an operating and maintenance expenditure reduction
of $0.8 million to reflect an expected reduction in the OCEI (ESV) levy.
In its Draft Decision, the Commission did not include amounts in the operating and maintenance
expenditure forecasts for these proposed step changes, with the exception of automated B2B,
because they were not linked to new (or changed) functions or legislative obligations.
With respect to automated B2B, the Commission noted that it was a new obligation but that it
was expected that automated B2B processes would reduce the manual workarounds that were
currently being undertaken by the distributors. While SP AusNet may have been incurring capital
expenditure in the current period to develop automated B2B processes, the operating and
maintenance expenditure incurred in fulfilling these functions should decrease with the new
automated processes. To the extent that SP AusNet’s step change related to an increase in
exceptions, the Commission expected that these data-related issues would be addressed in the
period of time leading up to the implementation of the automated B2B systems.
The Commission also noted that no other distributor submitted proposed expenditure for
automated B2B processes.
In response to the Draft Decision, SP AusNet transferred the proposed step changes for the
Utility Meters Act and Regulations and testing of CTs and VTs to the metering price control and
withdrew the proposed step changes for the NEMMCO standard for data communications and
OCEI (ESV) levy savings. With regard to the other two proposed step changes it made the
following comments:
•
Automated B2B — SP AusNet believed that it was in a unique position compared to the
other Victorian distributors. Throughout 2004, it was working with a stapled retailer for the
vast majority of its B2B transactions through highly customised and efficient processes
built specifically to the requirements of the two ring-fenced parties. From the date of
national B2B, this will not be the case and those transactions will pass through national
B2B, which by its very nature is a compromise across all market participants that does not
suit any party perfectly. While national B2B will be more efficient for the whole market,
and will reduce loss of efficiency as the proportion of TRUenergy customers on SP
AusNet’s network gradually declines, national B2B will be less efficient than the situation
in 2004.
•
Electricity Distribution Code: Quality of Supply — SP AusNet believed that the decision
to exclude expenditure did not reflect the Commission's desire to change current industry
practice and adopt a more proactive approach to managing quality of supply compliance.
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As a result of increased monitoring, it detected Negative Sequence Voltage issues. It
proposed:
y
36 x 22 kV feeders requiring load balancing
y
10 x 22 kV feeders requiring transpositions
y
10 x 66 kV lines requiring transpositions,
would restore quality of supply within Electricity Distribution Code requirements for
8964 customers.
The Commission’s Final Decision on each of these proposed step changes is as follows:
•
Automated B2B — the Commission notes the concerns raised by SP AusNet, however it
also notes that clause 7.4A.4(k) of the National Electricity Rules allows market participants
to enter into bilateral agreements between parties so that if the national B2B Procedures
introduce inefficiencies, then the affected parties can agree to conduct B2B
communications in another way. If the automated B2B arrangements introduce
inefficiencies relative to the existing arrangements, to the extent identified by SP AusNet,
then the Commission would expect that SP AusNet would explore alternative arrangements
rather than adopting the automated B2B arrangements. Accordingly, the Commission is of
the view that, whilst the distributors have the choice of accepting this as a new obligation,
SP AusNet has the option to continue the status quo.
•
Electricity Distribution Code: Quality of Supply — the Commission continues to be of the
view that this is not a step change as it is not a new (or changed) function or legislative
obligation. An efficient distributor would have been undertaking the types of works
proposed by SP AusNet such that a step change in expenditure was not required. If an
efficiency carryover amount has been obtained for not undertaking these works during the
2001-5 regulatory period, this efficiency gain is not sustainable, and customers should not
pay twice (through a step change and through an efficiency carryover amount).
Enhanced customer service offerings
In their price-service offerings, CitiPower and Powercor proposed “enhanced” offerings for
consideration to “deliver additional value to customers”. These enhanced offerings entailed
increased operating and maintenance expenditure associated with such areas as:
•
improved contact centre responses;
•
improved customer connection times;
•
‘new-for-old’ replacement of customer equipment damaged by voltage surges;
•
increased local community representation; and
•
increased access to GSL payments for customers receiving worse than average
performance.
CitiPower proposed an additional $10.8 million in operating and maintenance expenditure to
provide these enhanced customer offerings, while Powercor proposed an additional
$32.1 million.
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The additional cost associated with providing ‘new-for-old’ replacement of customer equipment
damaged by voltage surges has been considered in the Chapter 2. The additional costs associated
with improving customer call centre response, improving customer connection times, and
increasing access to GSL payments have been considered in Chapter 3.
In relation to increasing local community representation, Powercor proposed an additional
$1.1 million over the 2006-10 regulatory period to have a senior company representative visit
major regional centres on a rotational basis. These proposed visits aimed to allow customers to
meet with the company and hold face-to-face discussions, raise any issues of concern to them
and obtain information or assistance on any network or customer service related issues.
According to its submission, Powercor conducted customer research which indicated that its
rural-based farming and business customers placed a high value on local representation and faceto-face contact. Powercor was of the view that the improved level of service would enhance the
level of customer satisfaction for its rural based customers without imposing significant costs
upon them.
In its Draft Decision, the Commission did not include this expenditure because it did not
consider increased local community representation as a step change. Increased local community
representation was not a new (or changed) function or legislative obligation.
No comments were received on this issue in response to the Draft Decision and CitiPower and
Powercor have not included the expenditure in their most recent submissions. Hence, the
Commission has not included this expenditure as a step change in the Final Decision.
Increased labour costs
In their original price-service proposals, the distributors identified that a shortage in the
availability of skilled electricity workers would place significant upward pressure on their
operating and maintenance costs. Each distributor maintained that there was strong evidence to
indicate that a shortage of skilled labour in Victoria will have long lasting impacts on the cost of
service delivery, and as a consequence impact the operating and maintenance expenditure trend.
•
SP AusNet maintained that there was evidence to demonstrate that, as a result of a skills
shortage, labour costs would diverge from underlying CPI trends during the next period.
The impact of this effect was incorporated in its forecast rate of change.
•
Powercor and CitiPower stated that the increased demand for skilled labour in the industry,
combined with wage movement associated with an ageing workforce, would have a similar
impact. This impact was incorporated in their forecast rate of change.
•
AGLE and United Energy made similar comments, however both treated the increase in
real employment costs and additional costs for apprentices and training as a step change.
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In support of the forecast impacts of a constrained labour market, an assessment of expected
external labour rates was commissioned by the distributors and undertaken by KPMG. This study
forecast that real wages will increase by 4 to 5 per cent per annum over the period 2004-10.77
The Commission engaged Pacific Economics Group (PEG) to review the KPMG report. PEG
had serious concerns with KPMG’s statistical methodology and results. According to PEG
(2004, p. 22):
… after properly controlling for the effects of inflation, KPMG’s preferred model projects
that wages will decline rather than increase in real terms over the 2006-2010 period.
A copy of PEG’s report is available on the Commission’s website.
In the Draft Decision, the Commission did not include expenditure associated with increased
labour costs as a step change because it did not consider this a new (or changed) function or
legislative obligation. However, an increase in labour costs was incorporated into the rate of
change, and an increase in labour costs associated with capital expenditure was also included in
the capital expenditure requirement.
Stakeholders did not comment on the Draft Decision treatment of increased labour costs.
Consequently, the Commission has maintained this approach in the Final Decision.
Impact of industrial action
In its original price-service proposal, CitiPower and Powercor claimed that an adjustment to their
2006 base level of operating and maintenance expenditure was required to take account of work
deferred from 2004 as a result of industrial action. Industrial action in 2004 reportedly resulted in
the loss of 126,000 man-hours and 50,000 man-hours for Powercor and CitiPower respectively,
requiring equivalent increases in the base expenditure level of $8.8 million (based on $68.25 per
man-hour) and $4.9 million (based on $96.00 per man-hour) respectively.
In its Draft Decision, the Commission indicated that it did not consider this a step change
because it was not a new (or changed) function or legislative obligation.
During Wilson Cook and Co’s review of CitiPower and Powercor’s operating and maintenance
expenditure, CitiPower and Powercor indicated that, on resolution of the industrial action after
the submission of the price-service proposal, they had deferred some non priority capital works
which enabled them to complete the operating and maintenance works planned for 2004.
Accordingly, CitiPower and Powercor have withdrawn this proposed step change.
Land tax
United Energy originally proposed an additional $0.4 million of operating and maintenance
expenditure per annum due to increased liabilities for land tax. According to United Energy,
additional expenditure was required because of real increases in land tax arising from real
77
This report is available on the Commission’s website http://www.esc.vic.gov.au/electricity832.html
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increases in land values. United Energy indicated that the increased liabilities were calculated net
of any decrease in the rates of land tax applicable from 2005, and were levied on properties it
owns and leases.
The Commission did not include an allowance for land tax in its Draft Decision because it did
not consider it a new (or changed) function or legislative obligation. Increases in expenditure due
to land tax would be reflected in the rate of change. The Commission also noted that the State
Budget provided some relief from land taxation.
In response to the Draft Decision, United Energy accepted the Commission’s Draft Decision and
accepted that an allowance for land tax would be included in the rate of change.
The Commission has therefore not included an amount for land tax in the revenue requirements
for the 2006-10 regulatory period.
Reliability investigations
Powercor originally forecast additional operating and maintenance expenditure of $0.3 million
per annum to monitor and identify areas of poor reliability. Powercor indicated that this was in
response to feedback from its customer information sessions.
In the Draft Decision, the Commission indicated that it did not consider this a new (or changed)
function or legislative obligation. The increased GSL payments and liabilities under the S-factor
scheme would provide Powercor with an incentive to identify areas of poor reliability and to
improve the reliability where it is efficient to do so.
Powercor subsequently withdrew this proposed step change. Therefore the Commission has not
included expenditure for this item in the revenue requirement for the next regulatory period.
Embedded networks
In its original price-service proposal, United Energy included an additional $1 million in
operating and maintenance expenditure over the 2006-10 regulatory period associated with
uncertain responsibilities in relation to embedded networks.78 According to United Energy, the
proposed changes to the regulatory framework for embedded networks place additional
responsibilities on the distributor including issuing National Metering Identifiers (NMIs) and
metering.
In the Draft Decision, the Commission indicated that it did not consider this expenditure was a
step change because it was already an existing obligation.
78
Some electricity customers are not directly connected to the distributor's network. They may be connected to a separate
network that takes supply from a distributor’s network. A separate network that takes supply from a distributor’s network
and resupplies electricity through the separate network to customers is referred to as an embedded network because it is
embedded within the distributor's network. Customers supplied in this way are referred to as embedded network customers
(examples of embedded networks are caravan parks, retirement villages, shopping centres and high rise apartment
buildings).
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In response, United Energy accepted the Commission’s decision and thus the proposed
expenditure has not been included in the revenue requirement.
Embedded generation
Powercor forecast that an increased number of embedded generators would seek connection to
its network during the 2006-10 regulatory period. This was as a result of initiatives by the
Victorian Government to facilitate embedded generation, particularly wind farms. Powercor
forecast that, as a result of this policy, Powercor would incur an additional expenditure of
$0.8 million in negotiating the connection of embedded generators.
In its Draft Decision, the Commission did not consider this a step change and noted that a
separate cost recovery mechanism exists for costs associated with the connection of embedded
generators.
Powercor subsequently withdrew this step change. Therefore the Commission has not included
expenditure for this item in the revenue requirement for the next regulatory period.
Potential retailer liquidation costs
In its original price-service proposal, United Energy identified that the success of retail
competition in the Victorian electricity market exposed them to an increased risk of retailer
liquidation. United Energy claimed that the uncertainty surrounding Retailer of Last Resort
(RoLR) arrangements required an additional step increase in operating and maintenance
expenditure to mitigate the risk of small retailer failure.
Under its original price-service proposal, United Energy provided for $0.5 million in operating
and maintenance expenditure associated with the failure of an electricity retailer, and indicated
that these costs included the costs of bad debts and the resources required to transact the
necessary market obligations.
In its Draft Decision, the Commission indicated that it did not consider this a step change
because it was not associated with a new (or changed) function or legislative obligation. The
treatment of ROLR events is currently the subject of a separate review by the Commission and a
pass through for the administration costs associated with a ROLR event was provided for.
United Energy accepted the Draft Decision and thus the Commission has not included a step
change for a ROLR event. The Commission has maintained the provisions for the pass through
of the administrative costs arising from such an event (see Chapter 12).
Decision on the step changes
Table 6.22 sets out the Commission’s decision on the amounts that will be added to the base
operating and maintenance expenditure for each distributor for costs associated with step
changes.
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Table 6.22:
Step changes to operating and maintenance expenditure for 2006-10,
$million, 2006-10
New functions and legislative
obligations
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
Total
Cost of safety compliance
4.4
5.3
22.2
17.2
9.3
58.4
Electric Line Clearance Regulations
0.4
0.4
2.2
2.2
0.5
5.7
0.0
0.0
Ageing assets
Apprentices
0.0
GSL payments scheme
0.1
Road Management Act
1.1
Voltage compensation claims
0.6
0.2
Asset inspections
0.0
0.0
6.4
21.6
1.3
29.4
2.7
5.3
5.8
2.5
17.4
0.3
2.1
1.5
2.5
7.0
Growth related faults
Audits and accreditation
0.0
0.0
0.0
0.0
0.0
0.2
0.2
0.2
Occupational health and safety
3.9
Critical infrastructure protection
0.3
1.9
2.9
Allowance for cost of self insurance
3.2
3.9
1.5
0.0
Premature failure of XLPE
underground cable
0.0
0.0
SCADA master station upgrade
0.0
0.5
Ring fencing
0.8
Electricity demand side response
0.6
Financial report for 2009 regulatory
financial information
0.1
9.8
0.5
0.8
0.6
0.6
0.6
0.6
3.0
0.1
Automated B2B
0.0
0.0
Distribution Code – Quality of
Supply
0.0
0.0
0.5
1.5
SPI Powernet augmentation
1.0
System changes for changes to GSL
payments scheme
0.1
Total
8.5
0.1
11.8
42.5
56.4
17.9
137.2
Note: Totals may not add due to rounding.
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The step changes for each distributor are provided, by year, in Table 6.23.
Table 6.23:
Step changes in operating and maintenance expenditure by year, all
distributors, 2006-10, $million, real $2004
2006
2007
2008
2009
2010
Total
AGLE
2.0
1.7
1.6
1.6
1.7
8.5
CitiPower
2.3
2.8
2.2
2.2
2.2
11.8
Powercor
8.4
8.5
8.3
8.4
9.0
42.5
SP AusNet
11.6
11.4
11.3
11.0
11.0
56.4
United Energy
4.2
4.1
3.9
3.9
1.8
17.9
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7 CAPITAL EXPENDITURE
The Commission uses forecasts of capital expenditure as an input into determining the revenue
requirement. The capital expenditure forecasts are added to the rolled forward value of the
regulatory asset base and from this value the capital financing component of the revenue
requirement is calculated (see Chapters 8 and 9).
Distributors undertake capital expenditure to, among other things:
•
augment the capacity of the network to meet demand growth;
•
replace aged or obsolete assets;
•
improve the quality and reliability of supply;
•
meet the requirements of other regulators such as Energy Safe Victoria (ESV) and the
Environmental Protection Agency (EPA); and
•
purchase non-network assets (for example, buildings and vehicles) for normal business
purposes.
The capital expenditure forecasts that are established by this price review do not represent
amounts of money that the distributors are required to spend. Under the Commission’s incentivebased framework, the distributors are given incentives to increase their returns by meeting their
service and regulatory obligations at lower cost. Customers benefit from these efficiency gains
over the longer term through lower real prices.
The Commission’s Final Decision on the capital expenditure forecasts represents an increase of
30 per cent above historic capital expenditure levels.79 The Commission considers these forecasts
provide sufficient financing capacity for the distributors to continue to meet their service
obligations during the 2006-10 regulatory period and over the longer term. That is, the forecasts
will provide sufficient financing capacity for the distributors to:
•
maintain and improve service levels in line with the targeted service levels set out in
Chapters 2 and 3;
•
continue to meet their obligations to a growing customer base; and
•
meet a range of new service obligations and functions.
The forecasts reflect the Commission’s view on the cost of meeting these service obligations at
this time.
79
30 per cent above historic gross capital expenditure levels and 45 per cent above historic net capital expenditure levels. This
comparison is based on the capital expenditure in 2001-05, with the expenditure in 2005 being assumed to be the average of
the expenditure over the 2001-04 period.
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This Chapter sets out the Commission’s Final Decision on the capital expenditure forecasts that
will be used in determining each distributor’s revenue requirement for the 2006-10 regulatory
period and the reasons for the decisions it has made.
7.1 Final Decision
The Commission’s Final Decision on the capital expenditure forecasts that have been used to
determine each distributor’s revenue requirement is set out in Tables 7.1, 7.2 and 7.3.
Table 7.1:
Capital expenditure by asset category, all distributors, 2006-10, $million, real
$2004
AGLE
CitiPower
Powercor
SP
AusNeta
United
Energy
Reinforcements
41.6
100.2
167.7
94.9
83.3
New customer connections
80.0
139.1
268.9
261.5
106.4
Load Movement
0.0
20.1
0.0
0.0
0.0
Reliability & quality
maintained
41.1
133.6
268.8
162.7
190.6
Reliability & quality improved
0.0
0.0
19.1
24.2
4.8
Environmental, safety and
legal
18.5
38.8
78.0
98.2
52.5
SCADA/Network control
9.4
6.2
15.4
25.4
0.0
Non-network assets – IT
29.4
43.1
55.8
25.9
52.9
Non-network assets – other
12.8
5.6
52.6
1.4
12.4
Total gross capex
232.8
486.5
926.4
694.2
503.0
Customer contributions
22.6
28.8
130.4
66.4
20.3
210.2
457.8
795.9
627.8
482.7
Total net capex
a
Note: May not add due to rounding. Formerly TXU
Table 7.2:
Capital expenditure (gross) by year, all distributors, 2006-10, $million, real
$2004
2006
2007
2008
2009
2010
Total
AGLE
50.7
44.3
46.6
41.9
49.3
232.8
CitiPower
101.3
96.7
95.3
104.6
88.7
486.5
Powercor
171.8
186.2
190.4
187.6
190.3
926.4
SP AusNet
139.3
132.8
133.9
140.1
148.2
694.2
United Energy
101.1
95.0
95.5
102.1
109.4
503.0
Note: May not add due to rounding.
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In addition, the extent a distributor incurs additional capital expenditure which is above that
included in the revenue requirement (excluding expenditure associated with reliability
improvements or Melbourne’s CBD security of supply project) but is at or below the applicable
expenditure cap set out in Table 7.3, it may have the financing costs associated with that higher
level of capital expenditure rolled into the regulatory asset base in 2011. However, the decision
on whether to permit the roll-in of this expenditure is ultimately one that is at the discretion of
the relevant regulator at that time based on the circumstances that give rise to the additional
expenditure.
Table 7.3:
Capital expenditure (gross) compared to historic expenditure, all
distributors, 2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
Total
Historic expenditure
(2001-04)a
179.1
374.2
712.5
533.9
386.9
2,186.6
Variance (2006-10)
53.7
112.3
213.9
160.3
116.1
656.4
Expenditure requirement
(2006-10)
232.8
486.5
926.4
694.2
503.0
2,843.0
Expenditure cap (2006-10)
289.5
559.5
964.9
768.8
565.3
3,148.1
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure is divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period).
The expenditure proposed by CitiPower to improve the security of supply in Melbourne’s CBD
has been excluded from the expenditure requirement. The Commission will consult on the
appropriate planning standard for the Melbourne CBD area, the appropriate project to meet this
planning standard and the way in which the expenditure will be recovered from customers. If the
outcome of the consultation process leads to a change in the Electricity Distribution Code, the
expenditure determined through that process will a pass through (see Chapter 12 and clause 5 of
Volume 2). This mechanism will allow CitiPower to recover the estimated expenditure for the
CBD security of supply project finalised as a result of that process, should it proceed.
Additionally, should it proceed, the Commission will require separate reporting of the
expenditure associated with this project in CitiPower’s regulatory accounting statements and will
exclude this expenditure from out-turn expenditure for the purposes of assessing historic
expenditure in this category in future price reviews.
The distributors have different capitalisation policies. As a result some distributors have a higher
proportion of expenditure that is capitalised relative to others. The Commission’s Final Decision
on the total expenditure forecasts that have been used to determine each distributor’s revenue
requirement is set out in Table 7.4 to enable the total expenditure to be compared across
distributors.
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Table 7.4:
Total expenditure, all distributors, 2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
Operating expenditure
260.1
177.1
595.6
561.8
419.3
Gross capital expenditure
232.8
486.5
926.4
694.2
503.0
Total expenditure
493.0
663.6
1521.9
1256.0
922.3
Note: May not add due to rounding.
7.2 Reasons for the Decision
At the time of the last price review, the distributors’ proposed levels of expenditure for the 200105 period were substantially higher than the average rate of expenditure for the 1996-99 period.
The proposed increases ranged from 26 per cent (Powercor) to 54 per cent (SP AusNet80) and the
final benchmarks established represented a substantial increase over historic expenditure levels,
although they were lower than the distributors’ proposals. The forecast increase in capital
expenditure was attributed to growth in demand and customer numbers, improved quality and
reliability of supply, an increasing requirement to replace aged assets, the costs of full retail
competition, compliance with safety regulations and reduced up-front contributions by customers
to the costs of connection (ORG 2000a, p. 48-49).
This projected increase in capital expenditure did not eventuate. Instead, the level of capital
expenditure that has been undertaken over the 2001 to 2004 period has been closer to the levels
of capital expenditure undertaken in the 1995 to 2000 period (see Figure 7.1). At the same time,
most distributors have generally maintained or improved service levels despite higher growth in
customer numbers than forecast.
80
Formerly TXU
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Figure 7.1:
Total gross capital expenditure, industry aggregate, actual and benchmark
capital expenditure 1996-04, $million, real $2004
600
500
$million
400
300
200
100
0
1996
1997
1998
1999
2000
2001
Benchmark 1996-2005 Gross CAPEX
2002
2003
2004
2005
Actual Gross CAPEX
The fact that capital expenditure has been lower than forecast may be due to a combination of
factors:
•
efficiency gains achieved over the period;
•
the deferral of capital expenditure projects between regulatory periods;
•
changes in external drivers of expenditure, for example lower than anticipated peak
demand; and/or
•
the overstatement of capital expenditure requirements at the time the previous benchmarks
were set.
7.2.1 Commission’s objectives
In assessing a reasonable level of capital expenditure, the Commission must have regard to its
objectives under the Essential Services Commission Act 2001, particularly its primary objective
to protect the long term interests of Victorian consumers with regard to the price, quality and
reliability of electricity distribution services. It must also have regard to its facilitating objectives
including to facilitate efficiency in the electricity distribution industry and the incentive for
efficient long-term investment, and to facilitate the financial viability of the electricity
distribution industry.
The challenge associated with this balance was recognised by the Productivity Commission. In
its Review of the National Access Regime, the Productivity Commission (PC 2004, p. 102):
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considered the tradeoff between regulatory errors that overcompensate service providers
and those that undercompensate. Regulatory error that undercompensates service
providers could discourage investments of considerable benefit, with flow-on effects for
investment in related markets. On the other hand, regulatory error that overcompensates
service providers distorts decision making. The Commission considered that both types of
regulatory error are likely to distort investment and have adverse efficiency implications.
If the capital expenditure forecast overcompensates the distributor, then customers will pay more
than they otherwise would and the distributor will earn higher returns. If the capital expenditure
forecast undercompensates the distributor, then the distributor may not invest in the network and
this will impact on the long term reliability of the network.
The regulatory framework in place encourages the distributors to meet their obligations more
efficiently and thus outperform the Commission’s forecasts. Distributors are able to retain the
benefits of any out-performance against the forecasts for the length of the regulatory period.
Conversely, if distributors undertake a level of capital expenditure that is higher than that
forecast, the initial financing costs of this investment will not be recoverable although the actual
capital expenditure is rolled into the regulatory asset base at the following regulatory reset. This
is not expected to be a significant issue because any investment greater than the annual profile
would be expected to occur towards the end of the regulatory period. This is particularly so
where the profile of investment in the forecasts includes a ‘step change’ in expenditure rather
than a gradual increase.81 In this case, any additional financing costs will only be incurred over a
relatively short period.
Distributors will not be able to carryover any efficiency gains associated with capital expenditure
efficiencies achieved during the 2006-10 regulatory period into the 2011 regulatory period (see
Chapter 10). However, the removal of the efficiency carryover mechanism on capital expenditure
incurred in the 2006-10 regulatory period also means that distributors will receive no penalty
through this mechanism from spending more than forecast. Further, they will most likely benefit
in subsequent regulatory periods by earning a return on an increased asset base.
The increased incentive rates in the service incentive scheme for the 2006-10 regulatory period
will provide a greater incentive for the distributor to undertake economically efficient projects to
improve reliability (see Chapter 3). Given the differential between the existing incentive rates
and the new incentive rates, the Commission expects that the distributors will have a
significantly enhanced incentive to identify projects that will be funded through the service
incentive scheme at a much higher rate than the cost of the project. There will therefore be
greater opportunities for the distributors to profit through the service incentive scheme.
The Commission considers that the opposing incentives to underspend relative to the forecasts to
increase returns, and to not underspend relative to the forecasts so as to avoid incurring the
increased penalties for deteriorating performance under the service incentive mechanism, will
provide the appropriate disciplines on the distributors to ensure that investment is efficient and
effective in delivering service outcomes.
81
The increase in gross capital expenditure from 2004 to 2006 is 47 per cent from AGLE, 30 per cent for CitiPower, 11 per
cent for Powercor, 10 per cent for SP AusNet and 32 per cent for United Energy.
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7.2.2 Framework and approach
Given that capital expenditure has remained at similar levels over the last 10 years, the
Commission’s approach to assessing the distributors’ proposed capital expenditure levels in this
price review has been to place emphasis on past levels of capital expenditure as a starting point
for determining the efficient levels of future capital expenditure. To this end, the Commission
began its analysis of the distributors’ proposals by comparing each distributor’s proposed capital
expenditure with the level of average capital expenditure undertaken during the 2001-04 period.
In arriving at its Final Decision, the Commission has also reflected on the experience and
behaviour of the distributors in response to the incentives under the regulatory framework. This
includes recognising the incentive the distributors have to over-estimate their expenditure at the
time of a price review to maximise their revenue requirement. In doing so, the distributors are
able to benefit under the regime without achieving efficiencies, as the estimates are greater than
what is actually required from the outset of the next regulatory period. In this regard, the
Commission notes that the distributors’ capital expenditure proposals for the 2006-10 regulatory
period are considerably higher than the level of expenditure undertaken in the 2001-04 period
(see Figure 7.2).
Figure 7.2:
Total gross capital expenditure, industry aggregate, actual capital
expenditure 1996-04,a distributor forecast 2005 and distributor proposal
2006-10, $million, real $2004
900
800
700
600
500
$M
400
300
200
100
0
1996
1997
1998
1999
2000
Actual capex (inc meters)
a
2001
2002
2003
2004
DB proposed CAPEX (ex meters)
2005
2006
2007
2008
2009
2010
DB proposed CAPEX (inc meters)
Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs.
As set out in the Position Paper, the Commission was of the view that establishing a starting
point for expenditure levels through the use of trend analysis (based on out-turn information) is
the most effective means to assess the reasonableness of expenditure claims. Whilst trends
cannot be completely determinative of future requirements, they do provide a reasonable basis
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for assessing variations in capital expenditure for the 2006-10 regulatory period compared to
history.
Given the incentives that distributors have to over-state their future capital expenditure
requirements, the Commission also considered that it was appropriate to apply considerable
discipline on the distributors to support their expenditure proposals. For this reason, the
Commission believed that any assessment of future capital expenditure should take into account
historic levels of capital expenditure, with variations from such historic levels being supported
by cogent reasons.
It was for this reason that the Commission identified the need for distributors to provide it with
their asset management plans and strategies. This information was sought to assist the
Commission to identify the need for, and the distributors’ ability to implement, the expenditure
associated with capital works outlined in the distributors’ proposals for the 2006-10 regulatory
period.
In the course of this price review, some distributors have criticised the Commission’s use of
historic information. United Energy (2005c, p. 22-23) stated that the Commission’s approach
was ‘flawed’ and that:
The Commission’s predecessor also encouraged the distributors to think that actual capital
expenditure “revealed” in one period would not be used as a basis for setting future
benchmarks.
However, the Commission notes that, in the last price review, the Office of the RegulatorGeneral (ORG) decided that it would take the distributors’ historic and forecast costs of
delivering an electricity distribution service as its starting point when setting the
2001-05 benchmarks (ORG 2000a, p. 47).
7.2.3 Distributors’ proposed capital expenditure
The distributors have proposed gross capital expenditure of $3.4 billion over the
2006-10 regulatory period, compared to historic expenditure over the 2001-04 period (expressed
on a five year basis) of $2.2 billion.
The distributors’ submissions are summarised by asset category in Table 7.5 and by year in
Table 7.6.
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Table 7.5:
Capital expenditure forecasts by asset category, all distributors, 2006-10,
$million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Reinforcements
71.5
157.4
183.9
125.3
103.5
New customer connections
83.5
172.7
265.6
335.9
101.2
Load Movement
0.0
23.0
0.0
0.0
0.0
Reliability & quality maintained
74.5
153.3
282.4
185.7
233.6
Reliability & quality improved
1.3
0.0
41.9
27.2
5.4
Environmental, safety and legal
33.5
40.2
76.7
102.7
84.6
SCADA/Network control
14.0
6.9
16.2
28.9
0.0
Non-network assets – IT
43.7
41.1
77.9
11.7
60.9
Non-network assets – other
22.2
6.5
56.0
1.6
14.7
Total gross capex
344.1
601.0
1,000.6
819.0
603.9
Increase in gross capex relative
to historic expenditure
92%
61%
40%
53%
56%
Customer contributions
23.6
35.6
128.8
95.8
19.3
320.5
565.4
871.8
723.1
584.6
Total net capex
a
Note: May not add due to rounding. Most likely expenditure based on exemptions to the Electricity Safety
Regulations. AGLE does not support this scenario and remains of the view that more expenditure is required for the
distributors to comply with the Regulations within the 2006-10 regulatory period.
Table 7.6:
Capital expenditure (gross) forecasts by year, all distributors, 2006-10,
$million, real $2004
2006
2007
2008
2009
2010
Total
AGLE a
68.4
70.1
69.3
62.2
74.1
344.1
CitiPower
114.3
115.9
120.3
134.0
116.40
601.0
Powercor
187.3
202.7
205.7
202.1
202.8
1,000.6
SP AusNet
149.3
159.2
161.0
170.1
179.4
819.0
United Energy
121.9
118.7
114.4
121.0
128.0
603.9
a
Note: May not add due to rounding. Most likely expenditure based on exemptions to the Electricity Safety
Regulations. AGLE does not support this scenario and remains of the view that more expenditure is required for the
distributors to comply with the Regulations within the 2006-10 regulatory period.
According to the distributors’ price-service proposals, the forecast increase in capital expenditure
is being driven by an increase in reinforcement and replacement expenditure, new customer
connections and environmental, safety and legal requirements. CitiPower also proposed
additional capital expenditure of $50.4 million (including capitalised indirect overheads) to
upgrade the security of supply to the Melbourne CBD.
In the Position Paper, the Commission expressed its concern regarding the increases in the
proposed expenditure relative to the historic levels. The concern was that:
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On reviewing the historic trends in capex and the distributors’ capex forecasts, the
Commission is not convinced that the distributors’ forecasts of expenditure are more
appropriate than assessing variations to trend as outlined in its Framework and
Approach. The Commission therefore maintains the view that its Final Framework and
Approach will provide an appropriate balance between adequate investment in the
networks (particularly in the light of improved and maintained reliability over the past
period) and ensuring customers pay no more than is required for efficient investment.
(ESC 2005a, p. 71)
The challenge associated with the distributors overstating their requirements together with the
asymmetry of information is recognised widely by regulatory bodies and approaches have been
developed to address it.
Ofgem faced similar issues to those faced by the Commission with substantial increases in
proposed capital expenditure relative to historic trends, and similar incentives for the distributors
to overstate their requirements. It therefore introduced a ‘sliding scale’ mechanism that sets the
allowed expenditure and efficiency incentive based upon a ratio of the distributor’s proposed
expenditure to a benchmark established for Ofgem by PB Power (Ofgem 2004b).
Such a mechanism aims to address the situation where a distributor proposes more expenditure
than required and benefits through the period when it spends less because of the overestimation
rather than through the achievement of efficiency gains. The principles and objectives of the
Ofgem scheme are to:
•
retain an incentive for efficiency throughout;
•
reduce the emphasis on Ofgem’s or its consultant’s view of the appropriate level of capital
expenditure;
•
reduce the perceived risk that the price control causes under-investment;
•
allow but not encourage overspend (expenditure in excess of the ‘allowance’);
•
reduce the possibility of ‘high’ capital expenditure distributors making very high returns
from underspend;
•
reward the ‘low’ capital expenditure distributors if they deliver what they propose; and
•
avoid strong incentives to underspend by cutting corners and not delivering outputs or by
storing up problems for subsequent periods.
The regulator in Queensland (the Queensland Competition Authority) was faced with similar
concerns regarding substantial increases in capital expenditure proposed by Energex, in
particular, and its ability to deliver the proposed capital works program given the state of its
workforce planning. QCA allowed 80 per cent of the capital expenditure proposed by Energex
and introduced a mechanism to pass through additional capital expenditure if it could be
demonstrated that it was required to meet minimum service standards.
Whilst the Commission’s preferred approach was to assess the distributors’ proposals using its
stated framework and approach, the Commission indicated that it would consider the inclusion of
a ‘sliding scale’ type mechanism in the price controls, similar to that developed by the UK
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regulator (Ofgem), if this was the means required to achieve outcomes consistent with its Final
Framework and Approach.
However, the Commission was satisfied that the Draft Decision was consistent with its Final
Framework and Approach and it did not need to further consider the introduction of a ‘sliding
scale’ type mechanism.
7.2.4 Review of the distributors’ proposals
Wilson Cook and Co was engaged to assist the Commission in reviewing the variations in capital
expenditure proposed by the distributors relative to historic expenditure, and their asset
management processes. Wilson Cook and Co was required to:
•
assess whether the distributors’ proposed expenditure would provide appropriate service
outcomes for Victorian electricity customers for the least cost;
•
assess the information provided by the distributors to support variations from the historic
trend in capital expenditure; and
•
report on the links between capital expenditure, operating and maintenance expenditure
and the distributors’ asset management plans (Wilson Cook and Co 2005, p. 123).
In assessing the reasonableness of the distributors’ proposed capital expenditure, Wilson Cook
and Co had regard to the Commission’s framework and approach. It therefore adopted a threepart approach to the review of the distributors’ capital expenditure proposals:
(a) we compared the average annual levels of capex during the current period with those
proposed for the next; (b) we examined the reasons given for the distributors’ capex
proposals (including a review of trends in reinforcement and replacement capex and a
high-level examination of the main factors or projects that made up their projections);
and (c) as a final step, we reviewed the reasonableness of the overall level of capex
proposed by each distributor. (Wilson Cook and Co 2005, p. 8)
Wilson Cook and Co produced a report prior to the Draft Decision, which identified a number of
specific instances where it considered the distributors’ proposals to be overstated and
recommended corresponding downward adjustments.
In arriving at its Draft Decision on the capital expenditure set out in the distributors’ priceservice proposals, the Commission had regard to:
•
the distributors’ proposed capital expenditure under each asset category;
•
the relationship between the proposed capital expenditure and historic expenditure;
•
the information that the distributors had provided in support of their proposals and the
reasons they provided for the variation in expenditure;
•
the opinion of Wilson Cook and Co; and
•
the comments and information provided by other stakeholders.
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Having had regard to the facts before it at that time, the Commission was generally of the view
that Wilson Cook and Co’s recommendations were reasonable, but considered that a number of
further adjustments were required to appropriately reflect labour cost escalation, the level of
capitalised indirect overheads, and the removal of capital expenditure to improve reliability as
this was to be provided through the service incentive mechanism (refer Chapter 3).
The Draft Decision on capital expenditure, with a comparison to historic expenditure, is set out
in Table 7.7.
Table 7.7:
Draft Decision on gross capital expenditure, all distributors, $million, real
$2004
Historic expenditurea
Draft Decision
Increase relative to
historic expenditure
AGLE
179.1
236.6
32%
CitiPower
374.3
403.2
8%
Powercor
712.5
765.7
7%
SP AusNet
534.0
623.6
17%
386.9
465.2
20%
United Energy
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period)
In their submissions to the Draft Decision, the distributors criticised Wilson Cook and Co’s
report and the way in which the Commission had relied upon this report. For example:
AGLE believes that, because of:
y
The obviously inappropriate outcomes of the adjustments recommended;
y
The errors in the high level assessment of a reasonable level of CAPEX which is used
to justify the overall adjustments recommended; and
y
The qualitative, confused and superficial nature of the analysis of the individual
expenditure categories,
the Commission would be making a significant error if it placed much weight on the
recommendations of the Wilson Cook report. (AGLE 2005f, p. 53)
Similarly CitiPower (2005i, pp 10-11) and Powercor (2005u, pp10-11) were of the view that:
The Commission does not have unfettered discretion in relation to the methodology it
uses to determine capital expenditure allowances. Indeed, the Commission’s
methodology for capital expenditure must produce outcomes and/or incentives that are
consistent, inter alia, with the Commission’s primary objective and efficiency-related
objectives. … The Commission’s Draft Decision fails to provide for an efficient level of
capital expenditure, because it has relied extensively on advice from Wilson Cook that is,
itself, factually flawed.
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In response to the Draft Decision, further meetings were held between the Commission and
Wilson Cook and Co, and the distributors, and some distributors provided additional
information. Additionally, three of the five distributors revised their capital expenditure
proposals downwards.
Wilson Cook and Co and the Commission reviewed the additional supporting information
provided by the distributors, including their submissions to the Draft Decision. Wilson Cook and
Co reported to the Commission on the impact of the additional information on the opinions it
expressed in its original report. It has quantified the consequential adjustments where possible,
and relied on professional judgement otherwise. This report (which is contained in a letter to the
Commission) is available on the Commission’s website.
In particular, in response to the comments from the distributors regarding its assessment of a
reasonable level of overall expenditure, Wilson Cook and Co has made a number of amendments
to its analysis. On the basis of this revised analysis, the distributors’ proposed capital
expenditure, with a limited number of adjustments recommended by Wilson Cook and Co, was
considered by Wilson Cook and Co to be reasonable, and the level of historic capital expenditure
was considered to be below a reasonable level.
Wilson Cook and Co’s recommended that increases for the distributors of between 31 per cent
and 66 per cent in gross capital expenditure (excluding indirect capitalised overheads and labour
cost escalation) relative to historic gross capital expenditure could be supported.
However, Wilson Cook and Co (2005b, p. 3) has indicated in its report that there are a number of
matters which the Commission will need to review for the purpose of making the appropriate
adjustments. These matters are:
•
capital expenditure for electrical safety compliance;
•
capitalised indirect overheads;
•
labour cost escalation incorporated in the capital expenditure;
•
capital expenditure to maintain reliability and quality; and
•
in CitiPower’s case, the proposed expenditure for the CBD security of supply project.
After the Commission’s review and adjustment for these matters (see Section 7.2.9), the resulting
increases in the capital expenditure for the distributors would be between 35 per cent and 62 per
cent relative to historic gross capital expenditure. This compares to increases for the distributors
of between 7 per cent and 32 per cent relative to historic gross capital expenditure in the Draft
Decision.
In short, if all Wilson Cook and Co’s recommendations are adopted, this would result in levels of
capital expenditure for 2006-10 that are at a significantly higher level than has been experienced
since privatisation.
A reconciliation between the Draft Decision on gross capital expenditure and the forecast gross
capital expenditure at the asset category level, following the review by Wilson Cook and Co and
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the Commission’s adjustments for labour cost escalation and other matters, is provided in
Table 7.8.
Table 7.8:
Reconciliation of gross capital expenditure, all distributors, $million, real
$2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Draft Decision
236.6
403.2
765.7
623.6
465.2
Increase relative to
historica
32%
8%
7%
17%
20%
Change in Wilson Cook
and Co adjustment since
Draft Decision
69.7
121.9
277.9
76.2
136.6
Change in distributor’s
proposal since Draft
Decision
-1.7
-43.4
-179.8
-0.3
-43.1
Other changes since Draft
Decision b
-15.0
77.7
101.1
69.3
6.6
Forecast at asset category
level (based on Wilson
Cook’s further report)
289.6
559.5
964.9
768.8
565.3
Increase relative to
historica
62%
49%
35%
44%
46%
Note: May not add due to rounding. a Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Other changes includes, for example, changes in labour cost escalation, changes in
capitalised indirect overheads, and removal of capital expenditure for reliability improvements. The movement in
the other changes between the Draft Decision and the Final Decision is largely as a result of the distributors revising
their requirements which offset adjustments made in the Draft Decision.
Notwithstanding its review of the detailed information provided by the distributors, Wilson Cook
and Co (2005b, p. 5) has indicated in its report that areas of subjectivity remain where judgement
is required to be exercised, for example:
•
the weighing-up of costs and benefits;
•
the treatment of provisions for future expenditure that may not arise; and
•
the treatment of projected expenditures in circumstances where deferral to a later period is
possible.
The Commission also notes that the scope of work undertaken by Wilson Cook and Co did not
require them to:
•
consider the Commission’s objectives, including forming a judgement as to the appropriate
balance of interests between the distributors and customers;
•
consider the workings of the incentive-based regulatory framework, including the
operation of the efficiency carryover mechanism and the service incentive mechanism; or
•
make a judgement as what the distributors will actually spend.
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It is ultimately the Commission’s responsibility (as the regulator) to make these judgements and
determine the expenditure allowances that are to be included in the forward looking revenue
requirements, having regard to these things, among others.
In discharging this responsibility, the Commission will, of course, have regard to the advice of its
technical consultants, as well as to all other relevant information (such as the submissions of the
distributors and other stakeholders. However, it is not obliged to simply adopt the views or of
any other stakeholder, in fulfilling its functions. On the contrary, it must form its own view on
these matters, taking into account all relevant information.
The Commission is concerned that the aggregate level of capital expenditure recommended in
the further report by Wilson Cook and Co (2005b) is not reasonable given the task that would
confront the distributors in delivering the capital works programs implied in the expenditure
forecasts with the resource constraints identified in their price-service proposals.
7.2.5 Aggregate level of capital expenditure
In its Position Paper, the Commission noted that the trend in historic expenditure was more
evident at the aggregate level of capital expenditure rather than at an asset category level:
The Commission maintains the view that the trend in capex continues to be an
appropriate starting point for considering each distributor’s capex forecasts for the
2006-10 regulatory period. The Commission notes that capex at a disaggregated level
may be lumpy, but exhibits a trend at an aggregated level (ESC 2005a, p. 58).
Wilson Cook and Co (2005, p. 16) also considered that it was reasonable to assess capital
expenditure at the aggregated level. In its earlier report it commented that:
Some distributors proposed a ‘bottom-up’ estimate of capex requirements instead of the
use of past trends. However, ‘bottom-up’ estimates – those prepared when project-byproject analyses are undertaken as part of conventional network planning and asset
management planning exercises – tend to over-estimate capex requirements. Thus in our
view it is still necessary to consider the reasonableness of the overall level of capex
proposed.
Furthermore Wilson Cook and Co (2005, p. 14) stated that:
Although each individual capex project or programme may be justified when considered
in isolation, it is still necessary that the aggregated expenditure projection of each
distributor be reasonable.
When the expenditure is considered in aggregate, overlaps in projects are identified, and projects
are prioritised to reflect the resource (labour, machinery and financial) constraints. This is similar
to the budgeting process within a large organisation where the individual budgets of business
areas tend to be reduced when aggregated at the company level as the needs of the organisation
are prioritised.
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As a result of this prioritisation process, projects may be delayed or deferred.
The level of preparation of the projects and programmes we reviewed was appropriate
for planning purposes, recognising that plans do not constitute, by themselves, a
justification for proceeding with work until detailed studies have been prepared and the
relevant criteria met. In this context it is normal for some work to be advanced later on,
for other work to be deferred, for some to be amended and for other items to be dropped
altogether. (Wilson Cook and Co 2005, p. 14)
In its earlier report Wilson Cook and Co checked the adjustments recommended at the asset
category level by assessing the reasonableness of the resultant expenditure proposals in
aggregate. The approach adopted for this reasonableness check was to (1) estimate the
replacement cost of the asset base, and (2) compare the capital expenditure as a proportion of the
replacement cost of the asset base to the rate of replacement of the asset base (2 per cent based
on an average life of 50 years) and the rate of growth in energy consumption.
Wilson Cook and Co made further adjustments to the capital expenditure proposals where the
capital expenditure did not appear to be reasonable at the aggregate level. These adjustments at
the aggregate level were not incorporated by the Commission into its Draft Decision, principally
because they were not material relative to the other adjustments recommended by Wilson Cook
and Co.
Wilson Cook and Co’s approach to checking the reasonableness of the capital expenditure at the
aggregate level was criticised by the distributors on the basis that:
•
the replacement cost of the asset base had been underestimated;
•
in rolling forward the asset base, an inappropriate index was used; and
•
the appropriate measure of growth is peak demand rather than energy consumption.
Wilson Cook and Co therefore amended its analysis in its further report (2005b, p. A30) which
increased the reasonable range of capital expenditure indicated by this approach. It concluded
that (Wilson Cook and Co 2005b, p. 4):
The [reasonableness] test leads to the conclusion that the companies’ revised
expenditure proposals, after our revised adjustments, cannot be considered unreasonable
when tested by this measure.
The reasonable range, as determined using Wilson Cook and Co’s analysis, expressed relative to
historic expenditure is provided in Table 7.9.
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Table 7.9:
Comparison of average annual historic gross capital expenditure with Wilson
Cook and Co’s reasonable range (based on peak demand growth), all
distributors, $million, real $2004
Historic
expenditurea
Reasonable
range
Increase in
historic
expenditure –
low end of
range
Increase in
historic
expenditure – mid
point of range
Increase in
historic
expenditure high end of
range
AGLE
35.8
37 - 55
3.4%
28.5%
53.6%
CitiPower
74.9
64 – 95
-14.3%
6.4%
27.2%
Powercor
142.5
152 - 228
6.3%
32.9%
59.4%
SP AusNet
106.8
119 - 178
11.4%
39.0%
66.6%
United
Energy
77.4
98 - 148
26.6%
58.9%
91.2%
Note: May not add due to rounding. a Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period).
Table 7.9 indicates that the range considered by Wilson Cook to be reasonable is extremely
broad. It also indicates that an increase in gross capital expenditure of at least 27 per cent relative
to historic expenditure is required to ensure that all of the distributors are within Wilson Cook
and Co’s reasonable range when the range is calculated based on peak demand growth.
The Commission also notes that, when the reasonable range is calculated based on peak demand
growth, Wilson Cook and Co’s recommendations place the forecast capital expenditure for
AGLE and CitiPower at the high end of the reasonable range, and for Powercor, SP AusNet and
United Energy towards the mid point of the reasonable range.
If the reasonable range is calculated based on energy consumption growth, consistent with
Wilson Cook and Co’s earlier report, then the forecast capital expenditure with Wilson Cook and
Co’s recommended adjustments is towards the high end of the reasonable range for SP AusNet,
and above the high end of the range for the other distributors.
7.2.6 Implementation of capital works programs
An issue for consideration by the Commission is whether the distributors will actually spend the
forecast capital expenditure, particularly where it is a significantly greater level of expenditure
than the historic expenditure.
Distributors have no obligation to undertake the capital works programs that underpin their
proposals for capital expenditure. Instead, subject to meeting required service standards, the
incentive-based regulatory framework encourages distributors to defer the capital works and
benefit from the avoided financing costs.
Additionally, the distributors may not have the labour resources to undertake an increased capital
works program. In their price-service proposals, the distributors identified concerns regarding the
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shortage of skilled labour in the electricity industry. For example, CitiPower (2004e, pp 77-79)
noted that:
•
Skill imbalances take some time to resolve, as entry into electricity distribution field work
requires a four year apprenticeship to be undertaken, and a further two years of on-job
training and experience.
•
The shortage of new skilled labour is exacerbated by the fact that 40 per cent of
tradespeople currently in the electricity sector are aged 45 years or more. An ageing
workforce impacts on labour productivity through increases in time taken to complete tasks
and/or inability to undertake more strenuous activities.
•
The demand for labour resources in Victoria will increase with the mandatory roll out of
interval meters commencing in 2006 (refer Chapter 13).
•
The demand for labour resources has increased across South East Australia, with
significant increases in capital expenditure forecast in South Australia, New South Wales
and Queensland.
In this regard, Wilson Cook and Co (2005b, p. 5) noted that the ability of the distributors to
implement their plans:
… can only be conjectured, we see no reason why the companies, along with others in the
country and worldwide, cannot gear up for the additional workload foreseen, providing
they take concerted action for that purpose. … We expect that expenditure will ramp up
over the period due to the need to increase the resource base …
The Commission notes that the pattern of expenditure over the 2001-05 regulatory period is
consistent with a ramp up there has already been a ramp up in capital expenditure, during the
current regulatory period, which may reflect labour and/or financial constraints.
7.2.7 Information asymmetry
The balance between overcompensating and undercompensating the distributors for their
expenditure requirements is made more complex for the regulator given the information
asymmetry that exists between the regulator and the distributors. Investment in the distribution
network involves a large number of relatively small projects. This contrasts with investment in
the transmission network which involves a small number of relatively large projects, which may
more readily be assessed on a project-by-project basis.
As demonstrated in this price review, when requested to provide supporting information, the
distributors are able to produce a large amount of material to support individual projects.
However, this material does not constitute a commitment to execute those projects nor an
assessment of their capacity to execute them within the regulatory period. This requires that the
distributors’ proposals for future expenditure must be subject to careful scrutiny.
However, the Commission does not have the information necessary to develop the counterfactual
at this project by project level. The Commission must therefore largely rely on the facts before it
which are at an aggregate level, and include the levels of historic expenditure.
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7.2.8 Commission’s determination of capital expenditure requirements
Having regard to the matters discussed above, the Commission considers that its approach should
be to make a determination as to the reasonable capital expenditure requirements of the
distributors for the 2006-10 regulatory period at an aggregate level rather than at an asset
category level. Nevertheless, in section 7.2.9 the Commission reviews each of the distributors’
proposed capital expenditures at an asset category level. The reason for this is that it is the total
of the allowed capital expenditure at the asset category level that is the basis for the expenditure
cap for each distributor (discussed below).
As stated above, the historic out-turn capital expenditure for the 2000-04 period appears to much
more closely reflect the historic out-turn capital expenditure in the 1995 to 2000 period than the
distributors’ forecasts for the 2001-05 regulatory period or the Commission’s benchmarks (see
also ESC 2005a, p. 18). The Commission is therefore of the view that the historic expenditure
over the 2001-04 period should continue to be an important consideration in determining the
forecast capital expenditure at the aggregate level for the 2006-10 regulatory period.
The Commission recognises that there are reasons as to why a reasonable forecast of capital
expenditure for 2006-10 may be different from historic expenditure, including:
•
growth in peak demand;
•
the ageing of the asset base – which may lead to an increase in expenditure;
•
the removal of expenditure for reliability improvements from the forecasts; and
•
expenditure to comply with new regulatory obligations such as amendments to the
Electricity Safety Regulations.
In this regard, the Commission notes that:
•
The distributors’ most recent proposals represent increases in gross capital expenditure that
vary between 40 per cent and 92 per cent above historic expenditure.
•
Wilson Cook and Co’s further report, excluding any adjustments for labour cost escalation,
capitalised indirect overheads or electrical safety compliance, recommends increases in
gross capital expenditure of between 31 per cent and 66 per cent relative to historic
expenditure.
•
After adjustments for labour cost escalation, capitalised indirect overheads and electrical
safety compliance have been considered, the increases in gross capital expenditure
recommended by Wilson Cook and Co.’s further report are between 35 per cent and 60 per
cent relative to historic expenditure;
•
Wilson Cook and Co’s reasonableness check indicates that an increase in gross capital
expenditure of at least 27 per cent relative to historic expenditure is required to ensure that
all distributors are within its reasonable range.
•
At the last review, the distributors’ proposed gross capital expenditure was 34 per cent
higher than historic expenditure, on average, and the Final Decision provided for gross
capital expenditure of 23 per cent more than historic expenditure. However, in the current
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regulatory period, the distributors have only spent 8 per cent more than historic expenditure
on average.
•
If capital expenditure was assumed to increase at the same rate as peak demand growth,
then the capital expenditure would be expected to increase by approximately 22 per cent.82
•
The gross capital expenditure proposed by the distributors is between 1.4 and 2 times
greater than the proposed regulatory depreciation, which is incongruous in the longer term.
Furthermore, the proposed rates of regulatory depreciation has increased from levels of
around 4.6 per cent prior to 2001 to 6.1 per cent from 2006, with the rate of depreciation
increasing significantly for CitiPower from 2006 and for the other distributors from 2001
(see Chapter 8).
•
The risk to the distributors of requiring more expenditure than the forecast expenditure
allowance is to a degree mitigated by the removal of capital expenditure from the
efficiency carryover mechanism. This means that the cost to the distributor of investing
more than the forecast allowance is limited to the financing costs for capital expenditure in
excess of the forecast allowance.
•
Where expenditure is required above the forecast, distributors will have access to
additional revenue where the investment leads to improved service outcomes.
Taking into account all of the information before it, it is for the Commission to exercise its
judgement regarding a reasonable level of gross capital expenditure at the aggregate level for
each distributor. There is no formulaic approach to adopt in exercising such judgement rather
there is a range of factors for the Commission to consider. The information before the
Commission suggests that a lower bound for an increase in forecast gross capital expenditure
relative to historic expenditure may be 8 per cent, based on the experience during the current
period, and that a higher bound may be between 35 per cent and 60 per cent, based on the review
of the expenditure at the asset category level.
After taking all the matters referred to earlier in this Chapter into account, and erring on the side
of caution, the Commission has decided that a reasonable forecast of gross capital expenditure at
the aggregate level for each distributor over the 2006-10 regulatory period is an amount that is
30 per cent greater than the historic expenditure incurred by that distributor over the
2001-04 period. The Commission recognises that this increase may include projects that can be
deferred or are not required at all. However, it considers that the cost of providing more capital
expenditure than required is likely to be less than the cost of providing less than required.
The adoption of a forecast on this basis ensures that customers only pay for a level of capital
expenditure that the Commission reasonably expects will be incurred by the distributors over the
next regulatory period, given the level of historic expenditure.
The Commission notes that it could have made a range of adjustments to take into consideration
differences in the historic expenditure by distributor due to, for example, different growth rates,
different profiles of asset age, different strategies for deferral of expenditure and different
82
Assumes peak demand growth of 4 per cent per annum compounded over five years.
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maintenance regimes. However, this would have drawn the Commission into attempting to
interpret detailed information, not all of which is available to the Commission. Additionally the
Commission considers that the magnitude of the 30 per cent increase relative to historic
expenditure is sufficiently high to render it unlikely that the forecast capital expenditure that has
been determined by the Commission for each distributor will be below that which is reasonably
required for the 2006-10 period.
Moreover, the Commission considers that the 30 per cent increase in forecast capital expenditure
relative to historic expenditure is reasonably generous given the concerns raised by the
distributors regarding the availability of skilled resources to undertake capital works programs.
Nonetheless, the Commission recognises that this approach is subject to some risk in that it is
conceivable that a distributor’s capital expenditure requirements during the 2006-10 period
might exceed the forecast capital expenditure. It therefore considers that there should be further
flexibility where the distributor requires additional investment. Accordingly, the Commission has
decided that, when the capital expenditure incurred by a distributor exceeds the forecast capital
expenditure included in its revenue requirement (excluding expenditure associated with
reliability improvements or CitiPower’s Melbourne CBD security of supply project)83 the
distributor should be able to apply to have the financing costs associated with this higher level of
capital expenditure, up to a cap, rolled into the regulatory asset base in 2011. However, the
decision on whether to permit such a roll-in of financing costs is ultimately one that is at the
discretion of the relevant regulator at that time based on the circumstances that give rise to the
additional expenditure.
Together with the removal of capital expenditure from the efficiency carryover mechanism, such
an approach retains an incentive for efficiency throughout the regulatory period, provides for
(but does not encourage) spending more than the forecast expenditure and reduces the incentives
to underspend.
The Commission is of the view that the appropriate cap to apply under this approach is the total
of the expenditure that has been determined based on the review by Wilson Cook and Co with
additional adjustments by the Commission for labour rate escalation, capitalised indirect
overheads and safety compliance.
In short, the actual gross capital expenditure in 2006-09 and the forecast gross capital
expenditure for 2010 will be rolled into the regulatory asset base at the next price review.
However, to the extent the actual gross capital expenditure in 2006-09 and the forecast gross
capital expenditure for 2010 (excluding capital expenditure associated reliability improvements
or CitiPower’s Melbourne CBD security of supply project) is greater than the forecast
expenditure for 2006-10 but equal to a less than the expenditure cap, the financing costs
associated with that additional capital expenditure may also be rolled into the regulatory asset
base at the next price review.
For this price review, the capital expenditure that has been rolled into the regulatory asset base
for 2005 is the forecast determined as part of the last price review. Under the approach adopted
83
Thse are dealt with through separate mechanisms in the price controls.
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to forecasting capital expenditure at the aggregate level for this price review, the Commission
considers there is merit in the potential for reforecasting the capital expenditure for 2010 as part
of the next price review, prior to rolling it into the regulatory asset base.
Table 7.10 sets out a comparison of the gross capital expenditure as proposed by the distributors,
their historic expenditure, the applicable expenditure cap for each of them and the Commission’s
decision on the distributors’ gross capital expenditure for the 2006-10 regulatory period.
Table 7.10:
Comparison of Final Decision on gross capital expenditure to historic
expenditure, the distributors’ revised proposals and the aggregate by asset
category, all distributors, 2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Historic expenditurea
179.1
374.3
712.6
534.0
386.9
Distributor’s revised proposals
344.1
601.0
1000.6
819.0
603.9
Increase relative to historic
92.1%
60.6%
40.4%
53.4%
56.1%
Expenditure cap
289.5
559.5
964.9
768.8
565.3
Increase relative to historic
61.7%
49.5%
35.4%
44.0%
46.1%
Commission’s Final Decision
232.8
486.5
926.4
694.2
503.0
30.0%
30.0%
30.0%
30.0%
30.0%
Increase relative to historic
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period)
The Commission’s decision on capital expenditure by asset category has been determined by
prorating the difference between the Final Decision at the aggregate level and the expenditure
cap across asset categories with the following exceptions:
•
Environmental, safety and legal expenditure has not been adjusted; and
•
The new customer connections and customer contributions have not been adjusted where
the forecasts are consistent with the historic levels of expenditure.
7.2.9 Assessment of the distributors’ capital expenditure proposals by asset
category
In this section, the Commission reviews the distributors’ proposed capital expenditures at an
asset category level. For the reasons given previously, the Commission has determined the
distributors’ capital expenditure requirements for 2006-10 at an aggregate level rather than an
asset category level. However, subject to the constraints previously identified, this review at the
asset category level confirms that the Commission’s determination as to the aggregate capital
expenditure requirements for each distributor for the 2006-10 regulatory period is reasonable.
While the incentive framework provides an allowance for capital expenditure at the aggregate
level, it does not prescribe the amounts that must be spent on particular projects or by asset
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category. It is a matter for the distributor to prioritise and undertake expenditure consistent with
its own requirements.
However, the outcome of the review of the capital expenditure at the asset category level
provides an expenditure cap. As discussed previously, the purpose of the expenditure cap is to
provide a limit on the additional capital expenditure above that included in the revenue
requirement for which the financing costs may be rolled into the regulatory asset base in 2011.
In some of the detailed tables that follow, the amount included in the expenditure cap is higher
than the expenditure proposed by the distributor. Where this occurs, this is due to the
incorporation of upward adjustments for labour cost escalation and capitalised indirect
overheads, which have been reviewed by the Commission rather than by Wilson Cook and Co.
For example, United Energy included labour cost escalation as a step change in operating and
maintenance expenditure and did not include labour cost escalation in its capital expenditure
forecasts. To ensure that the capital expenditure proposed by each of the distributors has been
assessed on a consistent basis, the Commission has added an amount for labour cost escalation to
United Energy’s proposed capital expenditure for each asset category. As a result, and in the
absence of offsetting adjustments, the amount included in the expenditure cap for an asset
category may sometimes be higher than the amount proposed by United Energy.
Labour costs
Labour cost escalation was included in the proposed capital expenditure by all distributors,
except United Energy. Instead, United Energy forecast labour cost escalation as a step change in
operating and maintenance expenditure.
The approach that the Commission has taken to assess the labour costs included in the
distributors’ capital expenditure forecasts is the same as that used to assess the labour costs
included in the distributors’ operating and maintenance expenditure forecasts. The reasons for
escalating labour costs and the approach to determining an appropriate rate to escalate these costs
are discussed in detail in Chapter 6.
In the Draft Decision, a real labour cost escalation of 1.5 per cent annum was included in the
capital expenditure forecasts, based on a nominal labour cost escalation of 4.0 per cent per
annum, determined by reference to the Enterprise Bargaining Agreements negotiated in Victoria,
and a CPI of 2.5 per cent per annum.
In response to the Draft Decision, further information was provided by the distributors regarding
the nominal labour cost escalation. As discussed in Chapter 6, the Commission has forecast the
nominal labour cost increase for the 2006-10 regulatory period to be 5.0 per cent per annum.
Based on a forecast CPI of 2.77 per cent (see Chapter 9), this equates to a real labour cost
increase of 2.23 per cent per annum.
The Final Decision on the labour cost escalation is summarised in Table 7.11 together with the
distributors’ proposals and the Draft Decision. The adjustment for labour cost escalation has
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been prorated across the asset categories based on the labour costs84 for each asset category as
advised by the relevant distributor.
Table 7.11:
Adjustments to capital expenditure for labour cost escalation, all
distributors, 2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ original proposal
17.8
32.4
50.1
37.8
0.0
Draft Decision
9.2
11.6
18.0
13.6
22.2
Distributors’ revised proposal
17.8
12.1
16.7
32.6
0.0
Commission’s adjustment
-4.0
6.1
8.4
-10.3
30.8
Amount included in
expenditure cap
13.8
18.2
25.1
22.3
30.8
Capitalised indirect overheads
AGLE, CitiPower and Powercor have included costs arising from the capitalisation of indirect
(corporate) overheads in their capital expenditure forecasts. This is consistent with their
treatment of indirect (corporate) overheads in the current regulatory period — each of these
distributors currently capitalise some of its indirect (corporate) overheads.
SP AusNet and United Energy have expensed all of their indirect (corporate) overheads.
Accordingly, all the indirect (corporate) overheads incurred by SP AusNet and United Energy,
and that part of the indirect (corporate) overheads that is not capitalised by AGLE, CitiPower and
Powercor, have been included in their proposed operating expenditure requirements for the
2006-10 regulatory period.
To ensure that these costs are treated in a consistent manner across distributors, and unless there
is a change in the capitalisation policies of AGLE, CitiPower and Powercor between 2004 and
2006, the Commission is of the view that the indirect (corporate) overheads should be assessed in
the same way as it has assessed the distributors’ operating and maintenance expenditure forecasts
(see Chapter 6). That is, the capitalised indirect overheads should be rolled forward from 2004 to
2005 and from 2005 to 2006-10 using the same assumptions for the rate of change (including the
impact of growth) as for the operating and maintenance expenditure for that distributor.
The Commission has not been able to identify any change to the capitalisation policies of AGLE,
CitiPower and Powercor. Consequently, the Commission has adjusted the amount of indirect
(corporate) overhead costs included in the capital expenditure forecasts by an amount equal to
the difference between the indirect (corporate) overhead costs forecast by the distributors over
the 2006-10 regulatory period and those calculated in accordance with the Commission’s
operating and maintenance expenditure framework and approach based on 2004 reported indirect
(corporate) overheads.
84
For each asset category, the distributors have provided a breakdown of the capital expenditure into materials, labour, direct
overhead and indirect overhead.
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Additionally, consistent with the decision on operating expenditure, the capitalised indirect
overheads for CitiPower in 2004 are assumed to be $2.0 million higher than that reported by
CitiPower (see Chapter 5).
In the Draft Decision, the Commission made adjustments to CitiPower’s and Powercor’s indirect
(corporate) overheads of $21.2 million and $41.3 million, respectively. In subsequent
submissions, CitiPower and Powercor substantially reduced their capitalised indirect (corporate)
overheads to be in line with the Commission’s Draft Decision. Their revised proposals are based
on the capitalised indirect overheads in their 2004 regulatory accounting statements, and do not
incorporate any change over time with the rate of change and the impact of growth, or the
increase in capitalised indirect overheads assumed by the Commission for CitiPower.
The Final Decision on the capitalised indirect overheads is summarised in Table 7.12 together
with the distributors’ proposal and the Draft Decision. The adjustment between the distributors’
proposed capitalised indirect (corporate) overheads and the Commission’s view of an appropriate
level of capitalised indirect (corporate) overheads for the 2006-10 regulatory period has been
prorated across the asset categories, based on the level of indirect (corporate) overheads allocated
to each capital expenditure asset category by the relevant distributor.
Table 7.12:
Adjustments to capital expenditure for indirect (corporate) overheads, all
distributors, 2006-10 regulatory period, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ original proposal
16.6
74.0
98.2
0.0
0.0
Draft Decision
9.1
52.8
56.9
0.0
0.0
Distributors’ revised proposal
16.6
52.2
56.2
0.0
0.0
Commission’s adjustment
-7.1
13.8
3.4
0.0
0.0
Amount included in
expenditure cap
9.5
66.0
59.6
0.0
0.0
Note: May not add due to rounding.
The Commission recognises that the distributors have different capitalisation policies. In this
price review, the Commission has been able to assess the level of indirect overheads capitalised
based on the information available from the last price review. The distributors have provided
more detail regarding their proposed capitalisation of direct overheads and indirect overheads for
the 2006-10 regulatory period during the course of this price review. The Commission will use
this information for the next price review to ensure that any reported information is compared on
a like-fore-like basis with the forecasts in the revenue requirement, particularly given the
removal of capital expenditure from the efficiency carryover mechanism.
Reinforcement capital expenditure
Distributors undertake reinforcement capital expenditure in order to meet growing demand upon
the network. Reinforcement capital expenditure involves augmentation of network components
to ensure they have sufficient capacity to meet high peak demand days.
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The distributors proposed a level of reinforcement capital expenditure over the
2006-10 regulatory period that was greater than was spent in the 2001-04 period to accommodate
forecast increases in peak demand. The increases in expenditure proposed ranged between 48 per
cent (United Energy) and 199 per cent (SP AusNet). The distributors’ proposed capital
expenditure on reinforcement is set out in Table 7.13, along with the actual level of
reinforcement capital expenditure undertaken over the 2001 to 2004 period.
Table 7.13:
Proposed capital expenditure — reinforcements, all distributors, $million,
real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to
historic
expenditure
Distributors’
revised proposals
relative to historic
expenditure
23.9
199%
57%
199%
CitiPower
80.1
b
142%
30%
97%b
Powercor
70.7
212%
115%
160%
SP AusNet
41.9
197%
134%
199%
United Energy
69.9
66%
22%
48%
AGLE
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period) b Includes $44.1 million (excluding indirect overheads) to improve the security of
supply in the Melbourne CBD area. This project is discussed separately in the next section. Excluding this project,
the proposed increase in CitiPower’s reinforcement expenditure from 2001-04 to 2006-10 is 39 per cent.
The reasons the distributors gave for their proposed increases in reinforcement expenditure
include forecast increases in peak demand, increased utilisation levels and a need to maintain
utilisation within prudent levels, and the increased penetration of air conditioning. The
distributors’ reasons cited for the increase in reinforcement expenditure required are set out in
Table 7.14.
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Table 7.14:
Reasons cited for proposed increase in reinforcement capital expenditure
Reasons
AGLE
AGLE commissioned PB Associates to develop a generic model for estimating demand-related
capital expenditure and load demand growth, to compare to its own estimates. AGLE’s
estimates, which were $2.6 million higher than PB Associates’ estimates, were included in its
price-service proposal. Additionally AGLE included expenditure for projects not recognised in
the PB Associates modelling:
• conversion of 6.6kV network assets in the Preston area to 22kV ($14 million);
• sub-transmission line augmentation resulting from the augmentation of terminal
stations; and
• augmentation where prescribed voltage levels are breached before plant/line ratings
are exceeded.
CitiPower
Reinforcement capital expenditure in 2006-10 regulatory period is expected to exceed that in
previous periods due to:
• increasing focus on the value of the security of electricity supply by the community
and state and local governments; and
• the need to reinforce and augment the network to meet demand growth while
maintaining utilisation within prudent operating levels as scope to efficiently utilise
existing capacity reduces compared with previous periods.
CitiPower included $44.1 million, excluding indirect overheads, to improve the security of
supply in the Melbourne CBD. For the purposes of the Commission’s analysis, this has been
excluded from reinforcement expenditure and is considered separately in the next section.
Powercor
The main factors said to be driving reinforcement capex are the high level of utilisation of the
network, growth in localised pockets and the increasing penetration of air conditioning.
SP AusNet
SP AusNet’s proposed increased spending in the 2006-10 regulatory period is said to be driven
by increased peak demand levels caused by increased penetration of air-conditioning, the
associated load at risk, increased utilisation levels above that generally considered to be
prudent, and service outcomes.
United Energy
The significant increase in reinforcement expenditure compared with the current period is said
to be a result of lower demand than expected in the period 2001-05; the effects of projected
demand growth for the period 2006-10; and the need to maintain prudent levels of utilisation
and reliability performance.
Source: AGLE 2004, pp. 43-44; CitiPower 2004, p. 50; Powercor 2004, pp. 60-62; SP AusNet 2004, pp. 71-72;
United Energy 2004, p. 89.
Each of the distributors has spent less than their estimated requirements for reinforcement capital
expenditure set at the last price review. Some of the savings may be due to efficient deferral
since actual peak demand growth over the current period has been lower than that forecast at the
last price review. However some may also reflect an overstating of the forecasts at the last price
review.
Wilson Cook and Co assessed whether the reinforcement projects proposed by the distributors
were achievable and whether the associated expenditure was reasonable. In assessing the
achievability of the proposed expenditure, Wilson Cook and Co reviewed the consistency of
distributors’ forecasts with other processes and plans (including workforce management plans
and asset management plans), the weighted average remaining life of assets, load at risk,
expected utilisation levels and supporting information provided by the distributors.
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Wilson Cook and Co considered that the network development proposals reasonably reflected
the growth rates projected and were satisfied that individual projects were reasonable for
inclusion in the distributors’ network development plans. However, in terms of the
reasonableness of the distributors’ proposed expenditure, Wilson Cook and Co believed that the
expenditure proposals were overstated. The extent to which it considered the distributors’
proposals to be overstated was reduced relative to its view at the time of the Draft Decision.
AGLE
AGLE engaged PB Associates to verify its forecasts of reinforcement capital expenditure.
Wilson Cook and Co observed that AGLE had not required 50 per cent of the expenditure
estimated for the 2001-05 regulatory period and that service levels did not appear to be affected,
although AGLE’s current expenditure appeared low.
Wilson Cook and Co also observed that AGLE’s capital expenditure estimate was higher than
PB Associates’ estimate, and that this was not consistent with the expectation that estimates
derived from a detailed planning approach should generally lead to lower projections than a
deterministic model (due to synergies). This suggested that AGLE’s projections may be
overstated.
Wilson Cook and Co also noted that there may be double-counting due to the way estimates have
been categorised and prepared, and thus some provisions need not be accepted in full.
Wilson Cook and Co endorsed AGLE’s program for converting the 6.6kV network in the Preston
area to 22kV, noting that it will allow greater network flexibility and the rationalisation of
equipment as well as additional capacity.
In response to additional information provided by AGLE, Wilson Cook and Co accepted that the
expenditure under this category is low in the current period and ought to be increased. However,
it remained unconvinced that the proposed increased is required in full. In conclusion, it
expressed the view that AGLE’s reinforcement capital expenditure proposal was overstated by
$10.0 million, excluding the impact of indirect (corporate) overheads and labour cost escalation.
This compares to an adjustment of $31.4 million recommended by Wilson Cook and Co at the
time of the Draft Decision.
CitiPower
CitiPower engaged PB Associates to verify its forecasts for reinforcement capital expenditure.
However, in making the comparison between PB Associates’ estimates and its own estimates,
CitiPower identified an amount of $51 million for items that were not included in the PB
Associates’ estimates.
In response to the Draft Decision, CitiPower provided further information to support the items
removed by Wilson Cook and Co. These items related to labour cost escalation, the Roads
Management Act, indirect overheads, and Docklands connection expenditure (the expenditure
for which has subsequently been transferred to new customer connections). Additionally,
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CitiPower reduced its proposed expenditure for reinforcements, excluding labour cost escalation
and indirect overheads, from $193.8 million to $157.4 million (a reduction of $36.4 million).
With the exception of the expenditure to comply with the Road Management Act, and the capital
expenditure to improve the security of supply in the Melbourne CBD which is discussed in the
next section, Wilson Cook and Co was satisfied that, on the information made available to it, the
individual projects were reasonable for inclusion in CitiPower’s network development plans, and
the nature of the reinforcement expenditure proposed by CitiPower was justified.
With regard to the proposed expenditure on the Road Management Act, Wilson Cook and Co
made an adjustment of 50 per cent ($1.5 million) on the basis that the expenditure proposed was
provisional in nature. This compares to a total adjustment to the reinforcement capital
expenditure of $34.6 million, excluding the reduction for the CBD security of supply project, at
the time of the Draft Decision.
Powercor
Similar to CitiPower, Powercor had PB Associates verify its forecasts of reinforcement capital
expenditure. As with CitiPower, Wilson Cook and Co questioned the identification by Powercor
of $81 million of expenditure that was not included in the comparison between Powercor’s own
estimates and PB Associates’ estimates.
Powercor provided further information to support the items removed by Wilson Cook and Co.
These items related to labour cost escalation, the Roads Management Act, indirect overheads,
service pits and non reinforcement activities. Additionally, Powercor reduced its proposed
expenditure for reinforcements, excluding labour cost escalation and indirect overheads, from
$220.3 million to $183.9 million (a reduction of $36.4 million).
With the exception of the expenditure to comply with the Road Management Act, Wilson Cook
and Co was satisfied that, on the information made available to it, the individual projects were
reasonable for inclusion in Powercor’s network development plans, and the nature of the
reinforcement expenditure proposed by Powercor was justified.
With regard to the proposed expenditure on the Road Management Act, Wilson Cook and Co
made an adjustment of 50 per cent ($7.3 million) on the basis that the expenditure proposed was
provisional in nature. This compares with a total adjustment to the reinforcement capital
expenditure of $63.6 million at the time of the Draft Decision.
SP AusNet
Wilson Cook and Co noted that the unit costs used to estimate some items of SP AusNet’s
reinforcement expenditure might be too high. In most cases, Wilson Cook and Co was of the
view that the costs were substantially higher than the standard unit costs used in other
jurisdictions. Additional information provided by SP AusNet since the Draft Decision did not
convince Wilson Cook and Co that the unit rates were reasonable.
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Wilson Cook and Co expressed the view that the adjustment for unit costs in SP AusNet’s
reinforcement capital expenditure of $17.0 million, excluding the impact of labour cost
escalation, recommended at the time of the Draft Decision should be retained.
United Energy
In the Draft Decision, concern was expressed regarding the use by United Energy of a 10 per
cent POE and high economic growth assumption in modelling the reinforcements expenditure.
Since the Draft Decision, United Energy has remodelled its reinforcement expenditure based on
a medium growth scenario which has resulted in a reduction in its proposal from $115.7 million
to $93.2 million (a reduction of $22.5 million).
The Commission remains concerned with the use of a 10 per cent POE growth forecast, but is
satisfied that on this occasion United Energy has adapted the PB Associates’ models to reflect a
risk based planning approach. Additionally the Commission notes that the growth rate in the 10
per cent POE forecast is approximately the same as the growth rate in the 50 per cent POE
forecast.
Wilson Cook and Co noted that the company’s zone substation utilisation is at a high level and
accepted the need for increased expenditure. However, Wilson Cook and Co remained of the
view that some projects will be delayed or deferred, as in the past. Considering both of these
issues, it reduced the recommended adjustment from $34.7 million to $10.3 million.
Including adjustments for indirect (corporate) overheads and labour cost escalation, Table 7.15
summarises the capital expenditure for reinforcements for each of the distributors for the
2006-10 regulatory period.
Table 7.15:
Capital expenditure — reinforcements, all distributors, 2006-10 regulatory
period, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
71.5
157.4
183.9
125.3
103.5
Wilson Cook and Co adjustment
-10.0
-1.5
-7.3
-17.0
-10.3
b
-44.1
CBD security of supply
c
-2.3
4.7
2.3
-1.5
5.3
Amount included in expenditure
cap (2006-10)
59.2
116.5
178.9
106.8
98.5
Historic expenditure (2001-04)a
23.9
80.1
70.7
41.9
69.9
Variance
35.3
36.4
108.2
64.9
28.6
148%
45%
153%
155%
41%
Commission’s adjustment
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b The expenditure to improve the security of supply in the Melbourne CBD is not
incorporated in the expenditure requirement for reinforcement. It is considered separately in the next section. c
Includes adjustments for labour cost escalation (refer Table 7.11) and indirect (corporate) overheads (refer
Table 7.12)
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CBD security of supply
CitiPower proposed $50.2 million to strengthen the security of supply to the Melbourne CBD
(see Table 7.16) based on a proposal to move from the existing planning criterion for the CBD of
“N-1” to “N-1 Secure”. The proposed cost of this project includes $6 million of indirect
(corporate) overheads and labour cost escalation.
Table 7.16:
Proposed capital expenditure — CBD security of supply, CitiPower,
2006-10 regulatory period, $million, real $2004
Distributors’ revised proposal
2008
2009
2010
Total
12.7
17.1
20.4
50.2
Under the existing “N-1” planning criterion, the CBD network can withstand any credible single
contingency fault at subtransmission or zone substation level without sustained interruption to
customers, but not a second contingency event. Under the proposed “N-1 secure” planning
criterion, the network would be able to withstand a second contingency event without sustained
interruptions to customers, within 30 minutes of the first event occurring.
CitiPower engaged SKM to analyse a range of future CBD supply options. SKM (2004b) were of
the view that:
•
Melbourne CBD’s security of supply is the second lowest of comparable CBDs reviewed
by SKM in terms of maximum demand, energy at risk and planning criteria.
•
The number of people potentially affected by a supply failure is over 8 times higher than
the number of CitiPower’s CBD customers.
•
A supply failure to the CBD would be comparable in effect to a major transmission failure
elsewhere on the power system.
•
Loss of supply to the CBD would impact on people in many ways including traffic chaos,
loss of supply to many hospitals, health and safety issues, loss of economic activity and an
adverse effect on consumer activities.
The Commission is of the view that ensuring ongoing security of supply to the Melbourne CBD
area is of primary importance to the Victorian economy. As demonstrated when power failed to
the CBD area in 2002 and in the power failures that occurred in Auckland and New York, the
disruption of supply to the CBD has a significant impact on the economy. Hence, the
Commission fully supports CitiPower’s proposed project and considers it a positive step,
especially given the low comparative rating that SKM has given to the level of security of supply
that currently exists in Melbourne’s CBD.
However, the cost of the work proposed is significant. Given the incentive properties of the
regulatory framework, the Commission is concerned that to include the project in the revenue
requirement may result in customers paying for the project even if it did not proceed.
Additionally, the Commission is of the view that a project of this type should be subject to
sufficient review and consultation on the need for the change in the planning standard, what
planning standard is appropriate, the cost of meeting the planning standard and how it should be
paid for.
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The Commission proposed in its Draft Decision that the capital expenditure associated with this
project should be excluded from CitiPower’s revenue requirement but that, where the project
proceeds, the expenditure associated with the project (including compensation for financing costs
incurred) should be rolled into the regulatory asset base at the end of the regulatory period,
subject to the regulator’s satisfaction that the regulatory test under the National Electricity
Rules85 has been appropriately applied, and that the project has been executed in a prudent and
efficient manner.
Under the Commission’s proposed approach, customers would only fund the project if the
planning standard is changed and the project is identified as cost effective through an appropriate
public consultation process. CitiPower also has an incentive to ensure that the expenditure
associated with the project is efficient because the expenditure associated with the project would
only be rolled into CitiPower’s regulatory asset base where it could be demonstrated that it was
executed in a prudent and efficient manner.
In response, CitiPower provided a detailed submission concluding that it would not proceed with
the Melbourne CBD security of supply project within the 2006-10 regulatory period on the basis
set out in the Commission’s Draft Decision. CitiPower indicated that in its view:
•
The Commission had not assessed the proposal against its statutory objectives, in particular
the implications of its proposed decision for the incentives for efficient investment.
•
The regulatory test under the National Electricity Rules was not applicable as the project
has been proposed for economic reasons, rather than reliability reasons. The CitiPower
distribution system will not exceed its technical limits in normal conditions, or following a
single credible contingency event, in the absence of the CBD security of supply project.
•
It had already undertaken extensive consultation which had been positive.
•
The Commission is unable to bind any future regulator as is proposed under the approach.
•
The proposed treatment of the CBD security of supply project is somewhat novel in
Australian regulatory terms.
CitiPower also noted that recent Design, Reliability and Performance Licence Conditions
imposed on NSW distributors by the Minister of Energy and Utilities require that the planning
standard for the Sydney CBD has a security of supply standard not dissimilar to the ‘N-1 secure’
standard proposed by it.
The Commission issued an Open Letter on 11 August 2005 to further consult on this project.
Given the in principle support for this project from City of Melbourne and Victoria Police, the
Commission specifically sought comments from those parties, as well as other interested
stakeholders, as to the detail of CitiPower’s proposal, and particularly the impact on prices to
customers.
With regard to the most appropriate cost recovery mechanism, the Commission consulted on the
following options for recovering the costs of the project:
85
Formerly the National Electricity Code
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•
Include the costs in the revenue requirement and recover them from customers as proposed
by CitiPower.
•
Exclude the costs from the revenue requirement and recover them from customers from
2011 if the project proceeds, as proposed in the Draft Decision.
•
Recover the costs from customers through a pass through mechanism if an obligation is
placed on CitiPower (through the Electricity Distribution Code) to proceed with the
project.
•
Recover the costs from customers but pass them back if an obligation is not placed on
CitiPower (through the Electricity Distribution Code or any other regulatory instrument) to
proceed with the project.
Whilst Victoria Police did not respond to the open letter, the City of Melbourne (2005, p. 1)
indicated that it was not in a position to speak on behalf of the business and residential
community with respect to their willingness to pay for the extra security of supply through an
increase in electricity pricing, nor was it able to comment on whether CBD customers should pay
extra compared to non-CBD customers for the additional benefit of a secure supply. Furthermore
it was unable to comment on whether the consultation process undertaken by CitiPower to date
was appropriate for a project of this magnitude.
In its response to the open letter, CitiPower (2005y, pp. 2-3) reaffirmed its view that:
The CBD security of supply project should be accorded the same regulatory treatment as
all other distribution capital expenditure. Such a treatment would accord with the
approach to ex-ante capital expenditure in the ACCC/AER Principles and therefore be
consistent with the Commission’s facilitating objectives under the Essential Services
Commission Act 2001, the Electricity Industry Act 2000 and the Victorian Electricity
Industry Tariff Order (sic), in view of the Commission’s findings of fact with respect to
the importance of the CBD security of supply project to the Victorian economy.
… The project produces broad economic benefits to Melbourne’s CBD and surrounds
and as such the costs for the project should be recovered from all customers … Although
the beneficiary pays pricing is a desirable goal, CitiPower is of the view that the
efficiency benefits created from such pricing will be minor given the current average
pricing and the additional administrative costs of a separate tariff. The broad nature of
the beneficiaries of the project will further reduce efficiency signals as it would be very
difficult to clearly partition and bill all the customers that should contribute to the
project.
The Hon. Minister Theophanous (2005, p. 2) indicated that:
The importance of CBD supply reliability for the smooth running of the economy, and the
broader Victorian community is widely acknowledged. However, it takes on even greater
importance when the efficient and effective management of major community
emergencies (that may or may not be directly caused by an electricity supply problem) is
required. Many emergency services rely on the reliability of CBD electricity supply, as
do many of the emergency management coordination functions that are the crucial
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responsibilities of Government, its agencies and key infrastructure. I therefore urge that
the issue of providing an appropriately secure supply to the CBD is investigated.
Additionally, Powercor’s Customer Consultative Group (2005, p. 1) suggested that the costs
should be recovered from all Victorians. The Commission notes that there is currently no
mechanism for recovering costs for this project in this way and that such an approach may raise
issues regarding equity.
The Commission remains concerned that there is currently no obligation on CitiPower to
strengthen the security of supply in the CBD area. Accordingly, if the expenditure for this project
is included in the revenue requirement there is no guarantee that the project would proceed.
Given the magnitude of this project relative to those normally associated with the distribution
network, there is a potential for large windfall gains (or losses) for customers or CitiPower
should the project be funded and not proceed, or not be funded and then proceed during the
regulatory period. In each case there would be no sharing of risk — either CitiPower or its
customers would bear the entire risk of the project until the next Price Determination takes effect
in 2011.
CitiPower has clearly articulated that the project will not proceed if the expenditure is excluded
from the revenue requirement and recovered in the 2011 regulatory period if the project
proceeds. It prefers an option in which the expenditure is recovered from customers but returned
if an obligation is not placed on CitiPower to proceed with the project.
The Commission recognises CitiPower’s concerns about the risk of the project not being
undertaken if it is not able to recover the financing costs until the next regulatory period.
However, it does not consider that customers should pay for the project if it does not proceed.
Therefore, the Commission considers a within period pass through mechanism would be
appropriate once the planning standard has been altered. The pass through mechanism has
precedents in other jurisdictions, with similar mechanisms introduced in South Australia for
expenditure associated with connection point and subtransmission line projects, and in
Queensland for identified capital projects with a value greater than $5 million and a probability
of less than 80 per cent.
The Commission will undertake a consultation process to consider an amendment to the
Electricity Distribution Code. The Commission will consult on:
•
the most appropriate planning standard for the Melbourne CBD;
•
the most appropriate project to deliver that outcome; and
•
who should pay for the project, for example, electricity distribution customers in the
Melbourne CBD area, CitiPower’s electricity distribution customers, all electricity
distribution customers or all Victorians.
The Commission anticipates working with CitiPower to identify the planning standard options
and project options to consult on, with an Issues Paper to be released in June 2006.
If this consultation process leads to a change in the Electricity Distribution Code, the pass
through mechanism (referred to in Chapter 12 and implemented in clause 5 of the Volume 2) to
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allow CitiPower to recover the forecast expenditure for the CBD security of supply project
should it proceed.
Additionally should the project proceed, the Commission will require separate reporting of the
expenditure associated with this project in CitiPower’s regulatory accounting statements and will
exclude this expenditure from out-turn expenditure for the purposes of assessing historic
expenditure in this category.
Furthermore, the Commission has aligned the incentive rates under the S-factor scheme for the
CBD area with the $60 000 per MWh value identified by CitiPower and SKM to be the value of
lost load in the Melbourne CBD (refer Chapter 3).
New customer connections
Distributors incur new customer connection capital expenditure to establish new customer
connections to the network. Part of this cost may be recovered from customers through customer
contributions. The level of customer contributions for the 2006-10 regulatory period is discussed
in the next section.
Whilst some distributors have proposed increases in new customer connections capital
expenditure over the 2006-10 regulatory period (see Table 7.17), others have proposed
decreases. Table 7.18 sets out the reasons for the forecast changes.
Table 7.17:
a
Proposed gross capital expenditure — new customer connections, all
distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to
historic
expenditure
Distributors’
revised proposals
relative to historic
expenditure
AGLE
72.0
16%
-10%
16%
CitiPower
107.4
55%
-20%
61%
Powercor
276.5
1%
-33%
-4%
SP AusNet
246.2
42%
3%
36%
United Energy
130.4
-7%
-17%
-22%
Assumes all customer contributions are for customer connections.
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Table 7.18:
Reasons for proposed changes in new customer connections capital
expenditure
Reasons
AGLE
Forecast of new customer connections prepared by NIEIR
CitiPower
Number of new connections expected to remain relatively consistent over the period until 2010
Powercor
Growth in new customer connections is reasonably consistent throughout the period, however
there is an upturn in growth due to an anticipated economic upturn in 2010
SP AusNet
Growth rates, as forecast by NIEIR, are similar to those experienced during 2001-05. Increase
in gross connection expenditure reflects an increase in cogeneration costs for several windfarm
projects in the Gippsland area ($17 million) and an increase in underground estate costs relating
to the application of the Commission’s Electricity Industry Guideline No. 14.
United Energy
Reduction in forecast for the 2006-10 regulatory period primarily driven by the exclusion of
meters and the anticipated reduction in fully funded capital works
Source: AGLE 2004, p. 44; CitiPower 2004, p. 56; Powercor 2004, p. 63; SP AusNet 2004, p. 68; United Energy
2004, p. 92.
Prior to the Draft Decision, Wilson Cook and Co suggested a number of adjustments to the
capital expenditure for new customer connections proposed by the distributors based on an
apparent discrepancy in the proposed ratio of new connections to new customers compared to
historic data, and the unit cost of new connections. On further review following the Draft
Decision, Wilson Cook and Co had doubts about the veracity of the historic data for new
customer numbers which may have led to distorted ratios between historic new customer
numbers and new connection numbers.
As a result, in its further report it has removed the reductions for AGLE, Powercor and United
Energy of $13.7 million, $74.3 million and $18.4 million respectively that were recommended in
its earlier report.
CitiPower
In its price-service proposal, CitiPower proposed capital expenditure of $23.0 million for load
movement. Given the uncertainty on whether capital expenditure would be categorised as a load
movement or a new customer connection, Wilson Cook and Co considered the capital
expenditure for load movement in conjunction with its assessment of capital expenditure for new
customer connections.
Wilson Cook and Co noted that the capital expenditure proposed by CitiPower for new customer
connections, having regard to the additional expenditure associated with the Docklands
development, was high relative to historic expenditure. The number of new connections was
forecast to be on average 12 per cent higher than historic levels, when the other distributors were
forecasting similar or lower levels of new connections.
Wilson Cook and Co therefore proposed a reduction in its adjustment for capital expenditure for
new customer connections from $65.4 million to 10 per cent ($17.5 million).
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SP AusNet
In its earlier report, Wilson Cook and Co recommended a reduction to SP AusNet’s proposed
capital expenditure for new customer connections of $56.2 million. SP AusNet has since
indicated that the increase in the proposed capital expenditure for new customer connections was
due to the adoption of an “underground only” policy (endorsed by ESV) for new LV services. In
response to further questions from Wilson Cook and Co, SP AusNet advised that the cost of
these underground connections was $5 million less than originally proposed. Wilson Cook and
Co therefore recommended in its further report that SP AusNet’s proposed expenditure be
reduced by $5 million.
Wilson Cook and Co queried the increase in the proposed capital expenditure for new customer
connections compared to historic expenditure. Whilst the undergrounding of LV services and
increases in unit costs explain some of the increase relative to historic expenditure, they did not
justify all of this proposed increase. In its further report, Wilson Cook and Co therefore
recommended that SP AusNet’s proposed expenditure be reduced by a further 5 per cent
($15.7 million).
The Commission notes that SP AusNet has proposed expenditure of $17 million and customer
contributions of $15.3 million over the period to connect new wind farms to its network.
Recovery of connection costs associated with windfarms is defined by the Electricity Industry
(Wind Energy Development) Act 2004, and should therefore be excluded from the expenditure
forecast. Therefore the Commission has removed $17 million from new customer connections
and $15.3 million from customer contributions.
Including adjustments for indirect (corporate) overheads and labour cost escalation, the capital
expenditure for new customer connections for each of the distributors for the 2006-10 regulatory
period is summarised in Table 7.19.
Table 7.19:
Capital expenditure (gross) — new customer connections, all distributors,
2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
83.5
172.7
265.6
335.9
101.2
Wilson Cook and Co adjustment
0.0
-17.5
0.0
-20.7
0.0
Commission’s adjustment b
-3.5
6.5
3.3
-20.9
5.2
Amount included in expenditure
cap (2006-10) (a)
80.0
161.7
268.9
294.3
106.4
Historic expenditure (2001-04)a (b)
72.0
107.4
276.5
246.2
130.4
Variance (a-b)
8.0
54.3
-7.6
48.1
-24.0
11%
50%
-3%
20%
-18%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission
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Customer contributions
Customers are required to contribute towards the capital cost of new customer connections where
the incremental cost of the connection is greater than the incremental revenue.
All distributors have proposed reductions in customer contributions over the 2006-10 regulatory
period (see Table 7.20).
Table 7.20:
Proposed customer contributions, all distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to historic
expenditure
Distributors’
revised proposals
relative to historic
expenditure
AGLE
28.1
-16%
-32%
-16%
CitiPower
44.8
-28%
-58%
-21%
Powercor
166.8
-23%
-42%
-23%
SP AusNet
124.7
-10%
-31%
-23%
United Energy
49.4
-51%
-58%
-61%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period).
In the last Price Determination, the ORG proposed new guidelines for calculating customer
contributions to the cost of network connection and augmentation by customers, developers,
embedded generators and other parties. The proposed new guidelines were significantly different
from those employed by four of the five distributors, whose policies were inherited from the
former State Electricity Commission of Victoria. The impact of the proposed new guidelines was
that the level of capital contributions by customers would generally fall, thereby lowering the
barriers to connection faced by customers.
This policy change was not fully promulgated by the Commission until April 2004 with the
release of an updated Electricity Industry Guideline 14.
The delayed implementation of the new Guidelines means that the level of customer
contributions during the 2001-04 period does not necessarily reflect the likely level of customer
contributions for the 2006-10 regulatory period.
Customer contributions as a proportion of gross new customer connections expenditure, as
reported for 2004 and as proposed by the distributors for 2006, are set out in Table 7.21.
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Table 7.21:
Customer contributions as a proportion of gross new customer connections
capital expenditure, all distributors, per cent
2004
2006
As reported
Distributors’ revised
proposals
AGLE
32.4
28.0
CitiPower
40.4
19.0
56.2
48.7
47.6
25.9
22.5
19.1
Powercor
SP AusNet
a
United Energy
a
Excludes $17 million for windfarms in the new customer connection capital expenditure and $15.3 million as a
customer contribution
Customer contributions as a proportion of gross new customer connections capital expenditure
decreased for all distributors from 2004 to 2006. However it is difficult for the Commission to
assess a reasonable proportion given the different mix of projects undertaken by the distributors
(and therefore the different levels of contribution by customers), the absence of historic
information (given the change in approach over the current regulatory period), and the different
levels of compliance by the distributors to the requirements of the Guideline. Whilst the
Commission has concerns regarding the level of customer contributions proposed by some of the
distributors, given the level of uncertainty, the Commission has not made any adjustments based
on the proportion. However it expects that more consistent information will be available at the
next review to make a more thorough assessment.
In public information sessions convened by the Commission during this price review (see
Appendix A), customers, particularly in the Bendigo area, raised a number of concerns over the
costs they were being quoted by Powercor for connection to the network. However, these quotes
were provided by Powercor prior to the updated Guideline. Powercor has indicated that quotes
for customer contributions have reduced since the implementation of its new connection policies
and principles consistent with the Guideline.
Wilson Cook and Co has recommended that the level of customer contributions be reduced
proportionally to the reduction in capital expenditure for new customer connections. If the capital
expenditure on new customer connections is reduced, then the customers’ contribution to those
costs would also be expected to reduce. With the reduction in the adjustments to new customer
connections, there is also a reduction in the adjustments to customer contributions.
In its further report, Wilson Cook and Co’s adjustments to the customer contributions of AGLE,
Powercor and United Energy of $4.4 million, $39.2 million and $3.7 million have been removed.
Wilson Cook and Co has also reduced the adjustments to CitiPower’s and SP AusNet’s customer
contributions from $12.0 million to $3.5 million, and from $9.5 million to $4.8 million
respectively.
The Commission has adjusted the customer contributions proportionally to any adjustments to
the capital expenditure for new customer connections. It is also of the view that customer
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Final Decision
contributions attributable to the connection of windfarms ($15.3 million) should be removed
from SP AusNet’s proposed customer contributions, consistent with the treatment of new
customer connections capital expenditure.
The level of customer contribution for each distributor is set out in Table 7.22. In determining
these amounts, the Commission has accepted Wilson Cook and Co’s recommendations regarding
customer contributions and has removed SP AusNet’s contributions for windfarms.
Table 7.22:
Customer contributions, all distributors, 2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
23.6
35.6
128.8
95.9
19.3
Wilson Cook and Co adjustment
0.0
-3.5
0.0
-4.8
0.0
-1.0
1.4
1.6
-16.3
1.0
Amount included in expenditure
cap (2006-10) (a)
22.6
33.5
130.4
74.8
20.3
Historic expenditure (2001-04)a (b)
28.1
44.8
166.8
124.7
49.4
Variance (a-b)
-5.5
-11.3
-36.4
-49.9
-29.1
-20%
-25%
-22%
-40%
-59%
Commission’s adjustment
b
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission
Load movement
Distributors undertake capital expenditure on load movement to accommodate customers who
relocate within a network. The movement of customers within a network (for example, due to
changes of residences or business locations) does not generally change the total load on the
network. However, a distributor may need to augment the capacity of the part of the network to
which the customer relocates to accommodate the higher level of demand within that area.
CitiPower was the only distributor to forecast capital expenditure relating to load movement over
the 2006-10 regulatory period. CitiPower originally forecast load movement capital expenditure
of $24.1 million over the period, which was reduced to $23.1 million since the Draft Decision.
The reasons CitiPower cited for this expenditure included changes in network configuration
required by inner city and CBD residential development and asset relocations to allow adjacent
construction activities to maintain the prescribed clearance from its network.
Wilson Cook and Co originally recommended that this proposed expenditure not be accepted
because it considered that it had already been considered elsewhere. In response, CitiPower
provided further supporting information. As a result, in its further report, Wilson Cook and Co
re-assessed this expenditure in conjunction with CitiPower’s proposed capital expenditure for
new connections, and recommended that no adjustment be made. Accordingly, the only
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adjustments that the Commission has made relate to changes in labour cost escalation and
capitalised indirect overheads.
The load movement capital expenditure for each distributor for the 2006-10 regulatory period is
set out in Table 7.23.
Table 7.23:
Capital expenditure — load movements, all distributors, 2006-10 regulatory
period, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
0.0
23.0
0.0
0.0
0.0
Wilson Cook and Co adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.3
0.0
0.0
0.0
Amount included in expenditure
cap (2006-10) (a)
0.0
23.3
0.0
0.0
0.0
Historic expenditure (2001-04)a (b)
0.0
34.8
0.0
0.0
0.0
Variance (a-b)
0.0
-11.5
0.0
0.0
0.0
0%
-33%
0%
0%
0%
Commission’s adjustment
b
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), and indirect
(corporate) overheads (refer Table 7.12)
Reliability and quality maintained
Capital expenditure to maintain reliability and quality relates to expenditure undertaken to
replace and renew existing network assets. With time, network assets age and deteriorate and, if
not replaced, may fail, resulting in a deteriorating level of service reliability and quality.
The distributors have proposed capital expenditure to maintain reliability and quality over the
2006-10 regulatory period that exceeds the historic expenditure (see Table 7.24). Table 7.25 sets
out the reasons cited by the distributors for this increased level of expenditure.
Table 7.24: Annual average capital expenditure — reliability and quality maintained, all
distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to historic
expenditure
Distributors’ revised
proposals relative to
historic expenditure
AGLE
33.7
121%
69%
121%
CitiPower
71.9
122%
75%
113%
Powercor
168.5
76%
24%
68%
SP AusNet
125.2
33%
11%
48%
United Energy
73.1
227%
143%
220%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period).
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Table 7.25:
Reasons for proposed increase capital expenditure to maintain reliability and
quality
Reasons
AGLE
PB Associates modelled replacement expenditure for AGLE. Estimates from this modelling
were consistent with AGLE’s own estimates and were based on an increasing number of poles,
overhead service conductors, and cross arms that will need replacement during the 200610 regulatory period. Communications and protection schemes associated with the sub
transmission system are to be replaced due to age. There are also increasing failure rates of
porcelain surge diverters, and premature failure of early manufactured XLPE cable, and
overhead high voltage single blade isolators. There is an ongoing project to refurbish some of
the zone substation buildings.
CitiPower
The main driver of the proposed expenditure is said to be the ageing nature of the assets – over
12 per cent of them will reach the end of their lives by the end of the regulatory period, of
which the majority will require replacing. A key project proposed is to replace ageing 22kV
subtransmission cables and two 22/11kV zone substations on the southern fringe of the CBD.
Powercor
PB Associates undertook an independent verification of Powercor’s expenditure forecasts and
SKM was engaged to verify the unit rates used in the PB Associates’ model. Powercor’s
estimates (excluding indirect overheads) were below PB Associates’ estimates. The proposed
expenditure is largely condition-driven. The main features of this proposal are the replacement
of wooden cross-arms, wooden and concrete poles, older zone substation equipment, and
overhead and underground cable replacement. The latter is driven, in part, by some premature
failures of XLPE cables.
SP AusNet
The main drivers of the proposed expenditure are:
• additional expenditure on pole replacement, reflecting the trend of increasing
condemnation rates, ageing profile and higher failure rates;
• additional expenditure on overhead conductor replacement (due to increasing failure
rates of copper and steel conductors) and pole top structures (reflecting the expected
increase in condemnation rates of cross-arms and insulators); and
• the rebuilding of ten zone substations with packaged solutions.
United Energy
United Energy “is entering a period in which the requirement for assets replacement
expenditure will substantially increase. This increase in replacement expenditure reflects the
age profile of the asset population, the large proportion of assets installed beginning in the early
1960s, and the fact [that] many of the assets installed at that time are approaching the end of
their expected lives” (United Energy 2004, p. 95). United Energy states that its replacement
expenditure is driven by life extension programmes cost-effectively deferring expenditure from
the current period to the next; increasing condemnation rates for poles; replacement of
underground cable and low voltage pillars; and increases in the replacement of supervisory
cables together with aged relays in a 10-year programme that commenced in 2003.
Source: AGLE 2004, pp. 46-53; CitiPower 2004, pp. 60-65; Powercor 2004, pp. 66&68-69; SP AusNet 2004,
pp. 78-80; United Energy 2004, p. 96.
Wilson Cook and Co reviewed and analysed the consistency of the proposed replacement
expenditure with the forecasts of weighted average remaining lives and other age profile
information as well as asset management plans and processes. Its view was that the approach
used by distributors to estimate replacement expenditure was consistent with normal planning
procedures, and that the capital expenditure was targeted appropriately and could be considered
reasonable. However, Wilson Cook and Co recommended that the expenditure provision be
reduced in some areas.
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AGLE
In its earlier report, Wilson Cook and Co recommended an adjustment to AGLE’s proposed
expenditure to maintain reliability and quality of $13.1 million on the basis that it was overstated
— the proposed expenditure was twice that of the 2001-03 period and programs such as the
Preston network conversion project (categorised as reinforcement capital expenditure) had the
potential for duplication with replacement capital expenditure.
In its submission to the Draft Decision, AGLE (2005f, p. 56) was of the view that Wilson Cook
and Co had not adequately taken into account two factors in reaching its conclusion to reduce the
expenditure proposed. Firstly, the expenditure trend for this category of expenditure, and
secondly, the age profile of the AGLE network.
On further review of the supporting information provided by AGLE, Wilson Cook and Co noted
that the increase in expenditure, including an adjustment of $13.1 million, was 70 per cent above
historic expenditure. It considered this to be appropriate to allow for the ageing of assets and
therefore retained the adjustment of $13.1 million.
CitiPower
CitiPower engaged PB Associates to verify its proposed capital expenditure to maintain
reliability and quality. However, in making the comparison between PB Associates’ estimates
and its own estimates, CitiPower identified an amount of $42 million for items that were not
included in PB Associates’ estimates. In its earlier report, Wilson Cook and Co made an
adjustment for this amount.
In response to the Draft Decision, CitiPower provided further information to support the items
removed by Wilson Cook and Co. These items related to labour cost escalation, direct overheads,
indirect overheads, and the replacement of aluminium neutral screen service lines.
Additionally, CitiPower increased its proposed expenditure to maintain reliability and quality,
excluding labour cost escalation and indirect overheads, from $109.4 million to $130.5 million
(an increase of $21.1 million).
In light of the further information, Wilson Cook and Co considered that the expenditure
proposed by CitiPower was reasonable, with the exception of the rate at which CitiPower
proposed to replace aluminium neutral screen service lines. In its further report Wilson Cook and
Co. therefore recommended an adjustment to this expenditure of 50 per cent ($4.1 million).
Powercor
When comparing PB Associates’ estimate to its own estimate, Powercor, like CitiPower,
identified $39.9 million from its own forecasts for indirect (corporate) overheads and labour cost
escalation and another $47.0 million for the Road Management Act, fault capital expenditure,
chemical treatment of poles and bird covers, and safety compliance (service replacement and
CMEN-related capital expenditure) that were not included in PB Associates’ estimates. In its
earlier report, Wilson Cook and Co recommended that an adjustment of $63.8 million be made
for these items.
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Powercor subsequently provided further supporting information. Additionally, Powercor
increased its proposed expenditure to maintain reliability and quality, excluding labour cost
escalation and indirect overheads, from $191.4 million to $257.5 million (an increase of
$66.1 million).
Following review of the additional information provided by Powercor, Wilson Cook and Co
came to the view in its further report that the expenditure proposed by Powercor to maintain
reliability and quality was reasonable.
SP AusNet
In its earlier report, Wilson Cook and Co suggested that SP AusNet’s proposed expenditure in
this category was overstated by $15.2 million on the basis that it could not say with certainty that
the forecast expenditure would be undertaken during the 2006-10 regulatory period.
Following the Draft Decision, SP AusNet proposed two increases to its proposed capital
expenditure to maintain reliability and quality — $10.9 million to replace ‘white stringy-bark’
poles and $5.05 million for terminal station works in conjunction with SPI Powernet’s asset
replacement program.
On review of further information provided by SP AusNet, Wilson Cook and Co noted in its
further report that the expenditure proposed by SP AusNet to maintain reliability and quality was
48 per cent higher than historic expenditure, and that the expenditure in this category had
increased considerably over the past two years. Nevertheless, based on this increase in
expenditure, Wilson Cook and Co was of the view that the expenditure proposed by SP AusNet
was reasonable and removed the adjustment of $15.2 million.
United Energy
In its earlier report, Wilson Cook and Co observed that the level of capital expenditure to
maintain reliability and quality proposed by United Energy was 220 per cent higher than the
historic expenditure and proposed a reduction of $71.8 million.
In response to the Draft Decision, United Energy stated that the Commission was failing to meet
its primary objective under the Essential Services Commission Act unless United Energy was
provided with sufficient capital expenditure to maintain existing levels of reliability and quality.
Furthermore, it stated that if the age profile of its asset base is permitted to become progressively
older, reliability and quality will diminish unless countervailing measures are taken by it to
deliver improvements.
Additionally, further supporting information was provided by United Energy, including a
reconciliation between the historic expenditure and proposed expenditure.
Wilson Cook and Co accepted United Energy’s arguments in principle, but given the increase in
proposed expenditure above historic levels, remained concerned that some projects may be
deferred or delayed as in the past. In its further report, Wilson Cook and Co therefore reduced its
recommended adjustment to this expenditure from $71.8 million to $23.4 million (10 per cent).
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The levels of projected capital expenditure to maintain reliability and quality for each of the
distributors for the 2006-10 regulatory period are set out in Table 7.26. The adjustment includes
adjustments for indirect (corporate) overheads and labour cost escalation, as discussed in
Sections 7.2.5 and 7.2.6.
Table 7.26:
Capital expenditure — reliability and quality maintained, all distributors,
2006-10, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
74.5
153.3
282.4
185.7
233.6
Wilson Cook and Co adjustment
-13.1
-4.1
0.0
0.0
-23.4
-2.7
6.0
4.3
-2.6
14.7
Amount included in expenditure
cap (2006-10) (a)
58.7
155.4
286.7
183.1
224.9
Historic expenditure (2001-04)a (b)
33.7
71.9
168.5
125.2
73.1
Variance (a-b)
25.0
83.6
118.2
57.9
151.8
74%
116%
70%
46%
208%
Commission’s adjustment
b
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission
Reliability and quality improved
While the distributors undertake asset renewal and replacement to ensure the maintenance of
current service reliability and quality levels, they also undertake investment in the network to
improve service reliability and quality levels.
The levels of capital expenditure proposed by the distributors to improve reliability and quality
during the 2006-10 regulatory period are set out in Table 7.27.
Table 7.27:
Proposed capital expenditure — reliability and quality improved, all
distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to
historic
expenditure
Distributors’ revised
proposals relative to
historic expenditure
AGLE
3.6
-64%
-100%
-65%
CitiPower
5.9
-100%
-100%
-100%
Powercor
46.5
-5%
-63%
-10%
SP AusNet
56.4
-13%
-56%
-52%
United Energy
26.9
-57%
-80%
-80%
a
Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure
has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period).
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With the exception of CitiPower, each of the distributors proposed expenditure in their original
price-service proposals to improve the reliability of supply:
•
AGLE proposed $1.3 million to improve areas of poor reliability.
•
Powercor proposed approximately $11 million to improve the overall reliability
performance to customers/areas currently receiving the lowest level of service and improve
the ability to automatically detect outages through automated fault indicators. Powercor
also proposed approximately $6.6 million to continue with existing reliability programs
which will maintain the 2005 average reliability over the 2006-10 regulatory period.
•
SP AusNet proposed around $23 million to address reliability in its worst served areas —
Murrindindi, Kinglake, Newmerella, Cann River, Mount Dandenong, Sassafras and
Upwey.
•
United Energy proposed $12 million to, among other things, reduce the frequency of
momentary interruptions and improve its performance in its worst served areas.
In their enhanced offerings,86 CitiPower and Powercor proposed additional capital expenditure to
achieve certain outcomes:
•
CitiPower proposed $28 million to, among other things, increase the number of customers
who remain served during planned or unplanned transmission network contingencies and
to underground network assets on the CBD fringe.
•
Powercor proposed $54 million to, among other things, improve reliability performance by
targeting key feeders and reducing the impact and incidence of pole fires, and $38 million
to improve the security of supply.
Some distributors also made proposals to improve quality of supply:
•
Powercor proposed expenditure of $26.4 million to improve the quality of supply to
customers/areas where the quality of supply is not compliant with the requirements of the
Electricity Distribution Code, and to improve the proactive identification and rectification
of supply quality issues.
•
SP AusNet proposed expenditure of $24 million to resolve quality of supply issues to
ensure it complies with the Electricity Distribution Code and to install equipment to
measure harmonics and flicker.
•
United Energy proposed $1.05 million per annum to improve the quality of supply
delivered to customers so that it improves its compliance with the Electricity Distribution
Code.
In their enhanced offerings, CitiPower and Powercor also proposed additional expenditure to
improve quality of supply:
•
86
CitiPower proposed expenditure of $28 million to, among other things, reduce the number
of voltage sags of duration less than 1 second in commercial/retail areas.87
Under CitiPower and Powercor’s enhanced offerings, customers would receive less of a real average price reduction in the
next regulatory period in return for the delivery of these offerings.
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•
Powercor proposed expenditure of $54 million over the 2006-10 regulatory period to,
among other things, reduce the extent and impact of voltage fluctuations.
While in the current regulatory period, expenditure was incorporated in the revenue requirement
for distributors to improve service reliability, in the next regulatory period the focus is on
retention of current average reliability levels and the cost of any improvements in average
reliability is to be recovered through the service incentive mechanism (see Chapters 2 and 3).
This decision is based on the limited information available to suggest that, notwithstanding
pockets of poor reliability, customers do not value further improvements in the average level of
reliability. Further, any additional funding for improvements in reliability should be linked to
measurable outcomes.
Consequently, the Commission considers that the revenue requirement should not include
expenditure associated with further improvements in average reliability. Where improvements do
occur distributors will receive additional revenue for these improvements through the S-factor
scheme and the avoided GSL payments. Therefore, the Commission has excluded the
distributors’ proposed capital expenditure on reliability improvements.
Prior to the Draft Decision SP AusNet and United Energy had included expenditure to improve
reliability. This has subsequently been removed from their proposed expenditure.
Conversely, AGLE and Powercor indicated that the new incentive arrangements would not
provide sufficient funding to improve the reliability for their worst served customers. The
Commission notes that, even if the expenditure was provided to these distributors, there is no
guarantee that the outcome would be delivered. The distributors have an incentive to defer these
works and thereby improve their profitability.
The incentive rates in the new service incentive arrangements have increased substantially
relative to the existing rates. This will provide an incentive to the distributors to be innovative in
delivering improved outcomes to these customers, and will provide a mechanism to increase
revenue to fund these works.
In contrast to the approach to expenditure for reliability improvements, the Commission has
decided to incorporate amounts in the revenue requirement for improvements in the quality of
supply where it is determined that a distributor is not currently in compliance with the quality
standards set out in the Electricity Distribution Code, and recognising that there is currently no
financial incentive under which additional revenue will be provided to the distributors where
quality of supply improves.
Wilson Cook and Co reviewed the expenditure proposed by the distributors to improve quality of
supply to meet the standards set out in the Electricity Distribution Code. In its earlier report,
Wilson Cook and Co expressed the view that the expenditure proposed by SP AusNet and United
Energy was reasonable, but that the expenditure proposed by Powercor was not. Wilson Cook
and Co considered that the amount proposed by Powercor constituted a provision.
87
Proposed commercial/retail areas to be targeted by CitiPower include Armadale, Camberwell Junction, Prahran/Richmond,
Collingwood, South Melbourne, Albert Park and Port Melbourne.
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Based on additional supporting information provided by Powercor, Wilson Cook and Co in its
further report reduced its earlier recommended adjustment from $11.5 million for the Draft
Decision to $7 million.
The Commission has received a large amount of feedback at public information sessions and in
submissions that indicates that stakeholders, particularly in rural and regional areas, are
concerned with the quality of supply that they currently receive (see Chapter 2).
Given these concerns, the Commission considers that additional monitoring of supply quality in
rural areas is required and that the cost of increasing the number of voltage monitoring devices
installed by 20 per cent should be incorporated into the revenue requirement (see Chapter 2). The
data obtained from this additional monitoring will assist the Commission, the distributors and
customers in understanding the distributors’ level of compliance with the Electricity Distribution
Code’s requirements, the level of quality received by customers and where improvements should
be made.
To this end, the Commission has decided to include in the revenue requirement:
•
an additional 27 sophisticated voltage monitoring devices to be installed by Powercor
during 2006, at a cost of $648 000; and
•
an additional 17 sophisticated voltage monitoring devices to be installed by SP AusNet
during 2006, at a cost of $408 000.
The levels of capital expenditure for each of the distributors for the 2006-10 regulatory period to
improve reliability and quality, including adjustments for indirect (corporate) overheads and
labour cost escalation, is set out in Table 7.28.
Table 7.28:
Capital expenditure — reliability and quality improved, all distributors,
2006-10 regulatory period, $million, real $2004
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
Distributors’ revised proposals
1.3
0.0
41.9
27.1
5.4
Wilson Cook and Co adjustment
-1.3
0.0
-22.4
0.0
0.0
Commission’s adjustmentb
0.0
0.0
0.9
0.1
0.3
Amount included in expenditure cap
(2006-10) (a)
0.0
0.0
20.4
27.2
5.7
Historic expenditure (2001-04)a (b)
3.6
5.9
46.5
56.4
26.9
Variance (a-b)
-3.6
-5.9
-26.1
-29.2
-21.2
-100%
-100%
-56%
-52%
-79%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure is divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission
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Environmental, safety and legal
Capital expenditure for environmental, safety and legal matters refers to expenditure that
distributors may need to undertake to ensure that they are compliant with the requirements of
Energy Safe Victoria (ESV), the Environmental Protection Agency (EPA) and other legal and
regulatory requirements.
The distributors proposed very large increases in environmental, safety and legal capital
expenditure over the next regulatory period (see Table 7.29). This expenditure has been proposed
to comply with:
•
electricity safety regulations;
•
environmental obligations;
•
infrastructure security obligations;
•
the Road Management Act 2004; and
•
safety obligations.
Additionally, some distributors proposed capital expenditure for:
•
undergrounding; and
•
a Technology Development Fund.
Table 7.29:
Proposed capital expenditure — environmental, safety and legal, all
distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to
historic
expenditure
Distributors’ revised
proposals relative to
historic expenditure
AGLE
7.2
364%
241%
364%
CitiPower
1.2
3637%
2590%
3378%
Powercor
22.6
488%
196%
239%
SP AusNet
0.0
0%
0%
0%
United Energy
13.2
613%
155%
540%
a
Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure
has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period).
The Commission has been in discussions with ESV and the distributors regarding the expected
costs to comply with the electrical safety regulations over the 2006-10 regulatory period. On the
basis of these discussions the Commission has made adjustments to the capital expenditure
proposed by AGLE and CitiPower, which are discussed in more detail in the following sections.
Wilson Cook and Co reviewed the balance of the expenditure proposed by the distributors. In
summary, Wilson Cook and Co’s recommendations, which are discussed in more detail in the
following sections, are:
•
Environmental — reduction in expenditure proposed by AGLE;
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•
Infrastructure security — no reductions in expenditure;
•
Road Management Act — reduction in expenditure proposed by AGLE;
•
Safety — reduction in expenditure proposed by SP AusNet;
•
Undergrounding — expenditure proposed by United Energy should not be included in
revenue requirements; and
•
Technology Development Fund — expenditure proposed by United Energy should not be
included in revenue requirements.
The levels of capital expenditure for environmental, safety and legal (including adjustments for
indirect overheads and labour rate escalation) for each of the distributors for the
2006-10 regulatory period are set out in Table 7.30.
Table 7.30:
Capital expenditure — environmental, safety and legal, all distributors,
2006-10, $million, real $2004
Distributors’ revised proposals
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
33.5
40.2
76.7
102.7
84.6
Wilson Cook and Co adjustment
c
d
-1.1
0.0
0.0
-5.2
-35.0e
Commission’s adjustmentb
-13.9
-1.4
1.3
0.7
2.9
Amount included in expenditure
cap (2006-10) (a)
18.5
38.8
78.0
98.2
52.5
Historic expenditure (2001-04)a (b)
7.2
1.2
22.6
0.0
13.2
Variance
11.3
37.6
55.3
98.2
39.3
157%
3253%
244%
0%
297%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period. b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and adjustments by the Commission associated with the electrical safety regulations. c
Includes an adjustment of $0.7 million for environmental and $0.4 million for the Road Management Act. d
Adjustment to the proposed expenditure associated with safety. e Includes an adjustment of $10 million for
undergrounding and $25 million for the Technology Development Fund
Electrical safety regulations
The distributors are required to comply with a variety of legislative and regulatory requirements
including the Electricity Safety (Network Assets) Regulations 1999. A major audit was conducted
by the former Office of the Chief Electrical Inspector during the 2001-05 regulatory period
which identified that the distributors did not comply with a number of the regulations,
specifically:
•
Regulation 13 — Minimum distances between aerial lines and the ground, particularly
those over driveways
•
Regulation 17 — Minimum distances between aerial lines and parts of tramway systems
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•
Regulation 22 — Substations – minimum distances for pole mounted substations
•
Regulation 23 — Earthing and electrical protection – a low voltage network asset must be
earthed so that the resistance of the neutral conductor of the service line is not more than 1
ohm to earth
•
Regulation 27 — Inspection and testing – earth systems must be tested every ten years.
The Electricity Safety Act 1998 provides the opportunity for distributors to apply for variations to
the Regulations by means of exemptions from the Regulations to achieve equal or better safety
outcomes applicable to networks through the establishment of electricity safety management
schemes (ESMSs). The Act also provides the opportunity for persons authorised under an
approved scheme to be exempt from certain sections of the Act or from the Regulations.
The distributors have each developed and submitted Electricity Safety Management Schemes
(ESMSs) to Energy Safe Victoria (ESV).88 At the time the price-service proposals were received,
none of the distributors’ ESMSs had been gazetted through an Order in Council. However, the
Commission understands that all distributors have now had their ESMSs gazetted in the form
submitted.
Additionally, the distributors have submitted Electricity Safety Management Plans (ESMPs) to
ESV identifying plans to achieve compliance with specific regulations. In developing their
ESMPs, the distributors have assumed that ESV will be able to grant exemptions to certain safety
regulations. At the time the price-service proposals were received, ESV’s powers to grant
exemptions were unclear, however the legislation was recently amended to clarify ESV’s
powers. ESV is now able to recommend to the Governor in Council that a scheme be accepted
where it:
is satisfied that the level of safety to be provided by the scheme minimises as far as
practicable –
(i)
the hazards and risks to the safety of any person arising from the upstream
network to which the scheme applies; and
(ii)
the hazards and risks of damage to the property of any person arising from the
upstream network to which the scheme applies.
Whilst some distributors, principally SP AusNet and United Energy, have been undertaking
works to improve their compliance with the Regulations, other distributors, principally
CitiPower and Powercor, have focused on risk assessments and seeking exemptions to the
Regulations.
Since the Draft Decision, the Commission has met with the distributors and ESV to obtain a
better understanding of the regulations that the distributors do not currently comply with and the
actions that will be required to move towards compliance over the 2006-10 regulatory period.
88
ESV includes the functions of the former Office of the Chief Electrical Inspector (OCEI)
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Each distributor has provided more detail in regard to the expenditure that will be required for
this purpose and has detailed the actions that will be undertaken.
Furthermore, ESV has now granted an exemption to CitiPower in relation to the height of aerial
service lines and has been in discussions with Powercor regarding its exemption in relation to the
height of aerial service lines.
In their original price-service proposals, each distributor identified large expenditures associated
with achieving compliance with the ESV regulations. The distributors submitted forecast costs
on the basis of two scenarios:
•
a risk management approach — which assumes certain exemptions to the safety
regulations are granted by ESV; and
•
literal compliance — which assumes the distributors must literally comply with the safety
regulations.
The Commission considered the expenditure proposed by the distributors under a risk
management approach in assessing a reasonable level of expenditure for the Draft Decision. In
response, AGLE (2005f, p. 2) reaffirmed that its ‘Current Regulatory Obligations’ scenario is
applicable because no exemptions have been granted to it.
The Commission considers that any amount included in the expenditure requirements should
represent the requirements of an efficient distributor. It does not appear that the approach
adopted by AGLE is consistent with the approach that would be expected to be taken by an
efficient distributor. The Commission has sought further information from AGLE regarding the
most likely costs it would incur in complying with the safety regulations on the assumption that
it is granted exemptions from compliance, similar to those that have been, or are likely to be,
granted to the other distributors. This information has now been provided.
The Commission considered this information when assessing the reasonable expenditure for
AGLE for each regulation.
CitiPower (2005e, p. 1) and Powercor indicated that their proposals were based on a risk
management approach in anticipation that ESV would grant exemptions from literal compliance.
To date, an exemption has only been provided to CitiPower for aerial service lines. In the event
that exemptions were not granted for any items prior to the Final Determination, CitiPower and
Powercor suggested that a pass through should be considered.
The Commission has given consideration to this proposal. However, it considers that there is
sufficient certainty regarding the actions to be undertaken by the distributors to improve
compliance with each of the regulations, except regulation 23(11),89 for a reasonable level of
expenditure to be forecast.
The Commission was initially of the view that a pass through mechanism should be included in
the price controls to allow the pass through of costs to comply with regulation 23(11) and any
89
Regulation 23(11) relates to the resistance of the neutral service conductor to earth, particularly in rural areas.
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associated exemptions when there is greater certainty over what these costs will be. However,
with the Commission’s approach to assessing a reasonable level of capital expenditure in
aggregate, the Commission no longer considers it necessary to include such a mechanism. Where
a distributor spends more than forecast, the capital expenditure will be rolled into the regulatory
asset base. Additionally, the Commission has foreshadowed that, at the time of the next price
review, the regulator has the discretion to roll the financing costs associated with the additional
capital expenditure incurred up to a cap, into the regulatory asset base.
Hence, the Commission has included a level of capital expenditure that is consistent with ESV’s
current understanding of the actions that are required to meet the conditions of any exemptions
granted or to be granted.
In assessing the capital expenditure proposals, the Commission notes that $168.3 million (in
1999 dollars) was included in aggregate in the distributors’ capital expenditure forecasts for the
2001-05 regulatory period for compliance with environmental, safety and legal obligations. The
distributors have significantly underspent relative to this forecast. Of this aggregate amount,
$34.2 million (in 1999 dollars) was included for compliance with the electricity safety
regulations.
Regulation 13 — Minimum distances between aerial lines and the ground, particularly those
over driveways
The forecast expenditure proposed by the distributors as being required to improve compliance
of aerial line clearance heights, together with the distributors’ assumptions, is set out in
Table 7.31. The forecast operating expenditure and capital expenditure is also provided to
appropriately compare where different capitalisation policies has been adopted.
Table 7.31:
Distributors’ proposed expenditure, aerial service lines, all distributors,
2006-10, $million, real $2004
Opex
Capex
Total
AGLE
0.0
5.5
5.5
CitiPower
1.7
5.8
7.5
Powercor
8.4
16.9
25.3
SP AusNet
3.1
12.6
15.7
United Energy
0.4
24.8
25.1
Assumptions
Based on precedent in CitiPower’s and
Powercor’s exemption application
Approx 792 aerial service lines to be
rectified per annum
Approx 3,450 aerial service lines to be
rectified per annum
Prorated based on Powercor’s risk
analysis and the number of residential
customers
Additional 2000 service audits per
annum, Priority 1 and 2 services to be
replaced in years 1-4, priority 3
services in year 5
Discussions with ESV have indicated that CitiPower’s and Powercor’s assumptions are
reasonable based on the information provided to ESV in support of their exemption applications.
In the absence of an application for an exemption, SP AusNet forecast its expenditure by
prorating Powercor’s costs based on the ratio of residential customers. The Commission
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considers this approach to be reasonable. However, the Commission also notes that Powercor’s
forecast expenditure has increased since SP AusNet submitted its costs due to a late change to
Powercor’s exemption application by ESV. The Commission has therefore prorated these
additional costs for SP AusNet and increased its forecast expenditure from $12.6 million to
$14.6 million accordingly.
AGLE’s and United Energy’s forecast expenditure were determined by prorating the expenditure
proposed by CitiPower and Powercor respectively, based on the number of residential customers.
Whilst United Energy’s expenditure appears reasonable using this approach, AGLE’s appears
low. Accordingly AGLE’s proposed expenditure has been adjusted upwards from $5.5 million to
$8.2 million.
The forecast step change in operating and maintenance expenditure was considered by the
Commission in Chapter 6.
Regulation 17 — Minimum distances between a.c. aerial lines and parts of tramway systems
The forecast expenditure proposed by the distributors as being required to improve compliance
of tramway assets, together with the distributors’ assumptions, is set out in Table 7.32. The
forecast operating expenditure and capital expenditure is also provided to appropriately compare
where different capitalisation policies have been adopted.
Table 7.32:
Distributors’ proposed expenditure, tramway assets, all distributors, 200610, $million, real $2004
Opex
AGLE
0.1
Capex
1.8
Total
Assumptions
1.9
Opex - Inspection of all 1585 poles
shared with tramways and a survey of
unattached aerial crossings of about
37km of tram track. Capex - 174 low
voltage lines to be modified over five
years
Opex – additional minor works
procedures, replace 10 tramways
owned poles per year. Capex –
relocation of CitiPower overhead assets
in vicinity of tramway assets
CitiPower
0.3
5.0
5.3
Powercor
0.0
0.0
0.0
SP AusNet
0.0
0.0
0.0
United Energy
0.1
0.3
0.4
Opex – one off survey. Capex – rectify
some level of non compliance
Discussions with ESV have indicated that the level of non-compliance with this particular
regulation is very high. ESV therefore expects the distributors to submit an application for an
exemption and that minimal rectification work will be required.
Given that minimal rectification work is expected to be required, the capital expenditure
proposed by AGLE and United Energy appears reasonable. However the capital expenditure
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Final Decision
proposed by CitiPower appears high relative to that proposed by AGLE. The Commission has
exercised its judgement to adjust downwards CitiPower’s capital expenditure relative to its
proposal, from $5.0 million to $2.0 million.
The forecast step change in operating and maintenance expenditure was considered by the
Commission in Chapter 6.
Regulation 22 — Substations – minimum distances for pole mounted substations
The forecast expenditure proposed by the distributors as being required to improve compliance
of pole mounted substations, together with the distributors’ assumptions, is set out in Table 7.33.
The forecast operating expenditure and capital expenditure is also provided to appropriately
compare where different capitalisation policies have been adopted.
Table 7.33:
Distributors’ proposed expenditure, pole mounted substations, all
distributors, 2006-10, $million, real $2004
Opex
Capex
Total
Assumptions
AGLE
0.3
1.1
1.3
CitiPower
0.4
7.0
7.4
Powercor
0.0
10.0
10.0
Opex – 700 inspections per annum
Opex – 800 inspections per annum and
additional monitoring of 60 substations
per annum. Capex – 200 aerial
substations to be replaced per annum
Capex – 400 aerial substations to be
replaced per annum
SP AusNet
0.0
0.0
0.0
United Energy
0.0
9.7
9.7
Opex – Program commenced in 2005
and is due to be completed by the end
of 2008.
Discussions with ESV indicate that the activity proposed by the distributors appears reasonable.
The Commission is therefore of the view that the capital expenditure proposed by the distributors
to improve compliance with this particular regulation is reasonable.
The forecast step change in operating and maintenance expenditure was considered by the
Commission in Chapter 6.
Regulation 23 – Earthing and electrical protection – a low voltage network asset must be
earthed so that the resistance of the neutral conductor of the service line is not more than 1
ohm to earth
The forecast expenditure proposed by the distributors as being required to improve compliance
with the earthing requirements, together with the distributors’ assumptions, is set out in
Table 7.34. The forecast operating expenditure and capital expenditure is provided to
appropriately compare where different capitalisation policies have been adopted.
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Table 7.34:
Distributors’ proposed expenditure, earthing and electrical protection, all
distributors, 2006-10, $million, real $2004
Opex
Capex
Total
AGLE
10.4
15.8
26.2
CitiPower
2.0
0.0
2.0
Powercor
9.5
0.3
9.8
SP AusNet
0.0
0.1
0.1
United Energy
17.1
0.0
17.1
Assumptions
Opex – a more sophisticated test of half
services @ $93 per test
Opex – 15,000 tests per annum @ $35
per test, plus a controlled sample test of
1,500 services per annum @ $50 per
test
Opex – 52,000 tests per annum @ $35
per test, plus a controlled sample test of
1,500 services per annum @ $50 per
test
Opex and capex based on a risk
management approach. Cost to comply
with current regulations is $87.5m over
the five year period. If all service
cables tested every 10 years, then $16.4
million over 5 years based on 563,000
services.
Opex – 132,500 tests per year until
2010 and 62,000 tests in 2010 @ $32
per test.
Discussions with the ESV and the distributors indicate there is currently no certainty regarding
what actions are to be taken by the distributors to ensure that the resistance of the neutral
conductor of the service line is not more than 1 ohm to earth, particularly in rural areas, although
information is available regarding the tests to be undertaken to determine the resistance.
With the exception of AGLE, the distributors have forecast an immaterial level of capital
expenditure to meet the requirement that the resistance of the neutral conductor of the service
line is not more than 1 ohm to earth. Given the uncertainties associated with this regulation, the
capital expenditure forecast by AGLE has been removed.
The forecast step change in operating and maintenance expenditure was considered by the
Commission in Chapter 6.
Regulation 27 — Inspection and testing – earth systems must be tested every ten years
The forecast expenditure proposed by the distributors as being required to improve compliance
of inspection and testing, together with the distributors’ assumptions, is set out in Table 7.35.
The forecast operating expenditure and capital expenditure is provided to appropriately compare
where different capitalisation policies have been adopted.
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Table 7.35:
Distributors’ proposed expenditure, inspection and testing, all distributors,
2006-10, $million, real $2004
Opex
Capex
Total
AGLE
0.3
4.1
4.3
CitiPower
0.7
0.7
1.3
Powercor
4.0
3.1
7.1
SP AusNet
0.8
7.4
8.2
United Energy
0.0
0.9
0.9
Assumptions
Opex - additional testing of earths in
rural areas approximately 320 test per
annum @ $155 per test
Opex – test regime of high risk assets
(580 tests per annum @ $125 per test)
and random sample across network
(500 tests per annum @ $125 per test)
Opex – targeted test regime ($125,000
per annum) and additional program for
SWER distribution substations
($675,000 per annum)
Opex – 10,700 tests of SWER isolators
and substations ($0.9m, incremental
cost = $0.8m)
The capital expenditure proposed by the distributors to improve compliance with inspection and
testing requirements appears reasonable.
The forecast step change in operating and maintenance expenditure was considered by the
Commission in Chapter 6.
The forecast capital expenditure to improve safety compliance that will be included in the
distributors’ revenue requirement is set out in Table 7.36.
Table 7.36:
Forecast capital expenditure for safety compliance, all distributors, 2006-10,
$million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Aerial service lines
8.2
5.8
16.9
14.6
24.8
Tramway assets
1.8
2.0
0.0
0.0
0.3
Substation heights
1.1
7.0
10.0
0.0
9.7
Earthing and electrical
protection
0.0
0.0
0.3
0.1
0.0
Inspection and testing
4.1
0.7
3.1
7.4
0.9
Total
15.2
15.5
30.3
22.1
35.7
Electric line clearance
The Electricity Safety (Electric Line Clearance) Regulations 2005 were promulgated on 1 July
2005. These Regulations clarify various issues relating to the encroachment of vegetation
towards electric lines.
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Only United Energy proposed capital expenditure to comply with these Regulations. It submitted
a plan to ESV to remove overhangs by replacing bare overhead conductor with aerial bundled
conductor. The amount proposed ($5.9 million) enables them to continue with this program. The
Commission considers that the amount proposed is reasonable.
Environmental
Each of the distributors proposed additional capital expenditure to bring them into compliance
with legislative changes impacting on their environmental obligations. These proposals include:
•
Oil containment — the bunding of some large transformers and other items of oil filled
plant that are claimed to not conform to ‘literal’ compliance with current EPA regulatory
requirements and Australian Standard (AS 1940 – 1993) requirements.
•
Noise abatement — distributors are required to maintain noise at the nearest residence to
within levels complying with the State Environment Protection Policy (Control of Noise
from Commerce, Industry and Trade) No N-1. With increased urbanisation, the distributors
anticipate that, prior to 2010, at least some zone substations will become the subject of
complaint from the occupants of nearby residences.
•
Asbestos regulations — during 2003 the State Government imposed more rigorous
restrictions on the use and control of asbestos products and materials containing asbestos.
The new regulations, the Occupational Health and Safety (Asbestos) Regulations 2003,
combined with recent prohibitions made under the auspices of the Dangerous Goods Act
1985, require distributors to reduce potential exposure to asbestos.
•
Compliance with EPA guidelines — an increasing industry focus on compliance with EPA
Guidelines (led by NSW distribution businesses) has highlighted potential areas that are
claimed to need addressing in the 2006-10 regulatory period.
Environmental-related expenditure proposed by the distributors was as follows:
•
AGLE — asbestos regulations ($1.2 million), oil containment ($0.6 million), noise
abatement ($1.8 million).
•
CitiPower — noise abatement and management of oil spills ($13.1 million in total).
•
Powercor — relocation of overhead lines for vegetation clearance and bushfire mitigation
($52 million).
•
SP AusNet — asbestos regulation, compliance with EPA guidelines, management of oil
spills and noise abatement ($10.5 million in total).
•
United Energy — noise abatement ($2.5 million), EMF tolerances ($1.5 million), and
bushfire mitigation ($1.7 million).
Wilson Cook and Co reviewed this proposed expenditure and was of the view that, with the
exception of AGLE, it was reasonable, although it regards the expenditure proposed by
CitiPower for oil containment works as provisional. An adjustment of $0.7 million to AGLE’s
expenditure was recommended on the basis that the amount was considered to constitute a
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provision that may not be needed in full, the timing of projects of this nature can change, and the
work might be deferred.
The environmental-related capital expenditure is included in Table 7.30.
Infrastructure security
AGLE, SP AusNet and United Energy proposed capital expenditure of between $1.2 million and
$16.6 million to improve the security of infrastructure (see Table 7.37). With this expenditure,
these distributors aimed to prevent or minimise the impacts of acts of terrorism.
Table 7.37:
Distributors’ proposed total expenditure associated with infrastructure
security, all distributors, $million, real $2004
Expenditure item
AGLE
CitiPower
Powercor
SP
AusNet
United
Energy
Capital expenditure
1.2
0.0
0.0
16.6
4.8
Operating expenditure
0.3
1.9
2.9
3.2
1.5
Total
1.5
1.9
2.9
19.8
6.3
Note: May not add due to rounding.
AGLE’s proposed expenditure in this area is aimed at increasing the security of zone substations,
while United Energy’s proposed expenditure is to:
•
assist in providing a consistent approach to identify and prioritise critical infrastructure;
•
consistently assess and treat security risks;
•
identify specific assets that, if immobilised, would result in widespread community impact;
•
identify specific actions and liaise with state emergency response agencies; and
•
provide assurance to the Government and community groups of pro-active preventative
measures in respect to critical infrastructure assets.
SP AusNet linked its proposal to obligations established under the Terrorism (Community
Protection) Act 2003. SP AusNet stated that the expenditure is required to increase security
measures at critical infrastructure sites and to develop contingency capabilities to manage loss of
key infrastructure.
Wilson Cook and Co reviewed this expenditure and in its opinion the majority of the expenditure
proposed by distributors in this category was reasonable.
The capital expenditure to secure the distributors’ infrastructure is included in the amounts set
out in Table 7.30.
Road Management Act 2004
The Road Management Act 2004 (RMA) aims to establish a coordinated management system for
public roads that is intended to promote safe and efficient State and local public road networks
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and the responsible use of road reserves for other legitimate purposes, such as the provision of
utility services. The RMA came into effect for utilities on 1 January 2005.
Whilst all distributors have identified the RMA as impacting upon their operating and
maintenance expenditure (see Chapter 6), AGLE is the only distributor to identify an impact on
capital expenditure ($4.6 million) in this asset category for the 2006-10 regulatory period.
However, CitiPower and Powercor have proposed additional capital expenditure for
reinforcements and replacements for compliance with the RMA.
AGLE has indicated that its proposed expenditure is required to:
•
reflect the increase in the cost of all capital works due to the resultant increase in
complexity of work planning and reporting processes; and
•
install protective barriers or bury assets where lines are proposed.
While the Commission considers the RMA is a new obligation and so additional expenditure
relative to historic expenditure is justified, it notes that Wilson Cook and Co did not accept
AGLE’s notification and permit component ($348 000 over the period) and considered the
balance to be high. Wilson Cook and Co recommended an adjustment of $0.4 million in total to
the capital expenditure proposed by AGLE to comply with the RMA.
The capital expenditure for complying with the Road Management Act is included in Table 7.30.
Safety
AGLE and SP AusNet proposed capital expenditure relating to safety. Specifically, this
expenditure was for:
•
compliance with regulations regarding “working at heights” ($1.0 million) (AGLE); and
•
accelerated replacement of selected assets (above that indicated by age and condition
assessments) which may reduce fire ignitions and safety incidents ($37.3 million) (SP
AusNet).
The Commission notes the advice of Wilson Cook and Co, who commented that:
•
AGLE’s expenditure on working at heights was reasonable, and could be accepted in lieu
of an operating expenditure step change for this expense; and
•
in SP AusNet’s case, this work, if carried out, would result in savings in asset
replacements. Wilson Cook and Co therefore considered that it was likely that offsetting
savings could be made in other capital expenditure categories as a result of the work
proposed, and so recommended that consideration should be given to a reduction in the
overall level of capital expenditure to account for duplication with other works. An
adjustment of $5.2 million was recommended.
The safety-related capital expenditure is included in Table 7.30.
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Undergrounding
United Energy forecast capital expenditure of $10 million to underground parts of its network
which, according to its submission, is driven by three key factors relating to its 22kV distribution
assets:
•
improvements in public safety;
•
enhancement of the visual amenity; and
•
improvements in system reliability and performance.
United Energy suggested that arrangements could be put in place to provide assurance to all
stakeholders that its revenue requirement would be adjusted to permit it to recover only the cost
of works actually completed under this program.
At the time of the last price review, the ORG did not allow expenditure of this type to be
reflected in the price controls for this regulatory period because the ORG believed that there was
no sound basis for requiring all customers to contribute to the cost of a project that benefits
particular customers only. However, it was noted that there were sound arguments for requiring
distributors to contribute their avoided costs to such projects (ORG 2000a, p. 75).
The ORG (2000a, p. 77) also noted that its decision did not prevent United Energy’s proposal
from being further developed in consultation with municipalities and customers.
VicRoads (2005, p. 1) indicated its support for United Energy’s proposed expenditure on
undergrounding.
An annual program of $2 million would be a relatively modest commitment given the scope
of the problem of collisions with utility poles. However, it is considered that the returns to
the community through a carefully targeted program developed in conjunction with
VicRoads would be significant, both in economic terms and the broader impacts of road
trauma.
United Energy (2005c) also commented that:
In regard to the general undergrounding program UED would be looking to support local
council and community projects where undergrounding of network assets would provide
environmental, safety, aesthetic and network operational benefits. Again however, the
direct benefit to UED as the distributor is likely to be marginal in comparison to the
community benefit derived.
The Commission notes that United Energy and VicRoads were strong proponents of
undergrounding during the last Price Review (ORG 2000a, p. 75-77).
Conversely, the EUCV (2005b, p. 38) supported the Commission’s view that no additional
funding for undergrounding should be considered as part of this review.
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The Commission has decided that where undergrounding is required it should be paid for by
those who require it. Where it is considered that a public benefit would result, the Commission
encourages the distributor and other proponents to seek support from policy makers. This
decision does not prevent undergrounding projects from being undertaken. It does however
prevent these projects from being paid for by customers who do not value them.
The Commission also notes that, following the last Price Review, the State Government
established a Powerline Relocation Scheme. Under this scheme, the Government funds up to
50 per cent of the cost of placing powerlines underground, or otherwise relocating them, where a
community benefit will result. This is considered to be a more appropriate mechanism for
obtaining the funds required to underground network assets where there is a community benefit.
Additionally, the Commission is of the view that the incentive-based nature of its framework and
approach will provide suitable stimulus to ensure that distributors assess such projects on their
merits, and undertake undergrounding where the benefit to the distributor outweighs the cost.
The Commission does not consider an allowance should be made for capital expenditure for
undergrounding.
Technology Development Fund
United Energy proposed to contribute $5 million per annum to a Technology Development Fund,
to provide practical and financial support to groups and institutions to undertake research and
development activities to facilitate improvements in reliability, power quality and service
performance. United Energy proposed that the Commission adjust its revenue requirement so
that it only recovers the costs of work actually completed under the program.
Wilson Cook and Co noted that the object of the fund was desirable, although other bodies carry
out this work nationally and internationally. In addition, most if not all electricity distributors
develop new techniques and improve their understanding of such issues in the normal course of
their work.
United Energy (2005c, p. 36) noted that the proposed technology fund was similar to the
Innovation Funding Incentive allowed by Ofgem.
UED has proposed an independent governance structure for the Community Program
(which would oversee funding of the Technology Development Fund). Under the proposed
arrangements, funding would only be available for works actually carried out, thus
effectively addressing the Commission’s concern that funds may be allocated to R&D but
not expended.
EUCV (2005b, p. 40) supported the Commission’s view that inadequate support or justification
had been provided by United Energy.
The Commission is of the view that, where a distributor can identify benefits in pursuit of
efficiencies, the power of the incentive-based framework would promote the distributors’
development of such programs without any additional funding. In relation to reliability benefits,
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Final Decision
where projects can provide a measurable impact on reliability, the distributor benefits through
the S-factor scheme and the avoided payment of GSL payments.
The Commission does not consider that an allowance should be made for capital expenditure for
a Technology Development Fund.
SCADA/Network control
SCADA/Network control assets are used in the monitoring and control of network systems,
including their associated main stations, remote terminal units and communication links.
The level of expenditure proposed by the distributors under this category varied, with some
distributors proposing large increases and others proposing declines over the 2006-10 regulatory
period (see Table 7.38). Table 7.39 sets out the reasons for the distributors’ proposed level of
expenditure.
Table 7.38:
Proposed capital expenditure — SCADA/Network control, all distributors,
$million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to
historic
expenditure
Distributors’
revised proposals
relative to historic
expenditure
AGLE
1.1
1167%
1076%
1169%
CitiPower
8.0
-8%
-16%
-14%
Powercor
46.5
-63%
-73%
-65%
SP AusNet
3.0
832%
792%
861%
United Energy
0.0
-
-
-
a
Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure
has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period).
Table 7.39:
Reasons cited for the proposed SCADA/Network control capital expenditure
Reasons
AGLE
New SCADA system required over 2008 and 2009. Work to replace the ageing copper
communications network with a modern fibre optic network will continue during the 2006-10
period.
CitiPower
Does not own a SCADA system as it contracts this service from SPI Powernet. Works
proposed include replacement of aged communications equipment, upgrading zone substation
monitoring and control systems, additional SCADA data security and security monitoring, and
replacement of aged remote fault monitoring units.
Powercor
Works proposed include rationalisation and integration of control centre operational systems,
migration to a fibre optic network, continuing investment in network monitoring and control,
establishment of back-up SCADA communications links, alternate communications medium to
trunk radio network, and improving communications capacity and SCADA polling time.
SP AusNet
Replace existing SCADA systems, increase the scale and scope of network monitoring and
control, provide real-time monitoring and control of the total electricity network.
United Energy
No expenditure proposed.
Source: AGLE 2004, pp. 57-58; CitiPower 2004, p. 71; Powercor 2004, p. 76; SP AusNet 2004, p. 93.
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Expenditure on SCADA/Network control assets is highly variable because of the need to
upgrade these assets only periodically. Expenditure in excess of that incurred in previous
regulatory periods will be necessary if the systems in place require upgrading and this did not
occur in the previous regulatory period.
Wilson Cook and Co’s view was that the estimates of expenditure under this category were
reasonable based on the information that it had available.
The level of SCADA/Network control capital expenditure for each distributor for the 2006-10
regulatory period (including adjustment for indirect (corporate) overheads and labour cost
escalation) is set out in Table 7.40.
Table 7.40:
Capital expenditure — SCADA/Network
2006-10 regulatory period, $million, real $2004
control,
all
distributors,
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
14.0
6.9
16.2
28.9
0.0
Wilson Cook and Co adjustment
0.0
0.0
0.0
0.0
0.0
-0.6
0.3
0.2
-0.3
0.0
Amount included in expenditure
cap (2006-10) (a)
13.4
7.2
16.4
28.6
0.0
Historic expenditure (2001-04)a (b)
1.1
8.0
46.5
3.0
0.0
Variance
12.3
-0.8
-30.0
25.6
0.0
1115%
-10%
-65%
852%
0%
Commission’s adjustment
b
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission
Non-network general assets — IT
The distributors undertake expenditure on non-network general assets — IT to install or upgrade
computer systems such as customer service systems, billing and collection systems, project
management systems, fault recording systems, GIS systems, asset management databases, fleet
management systems and security systems. There are also the usual corporate systems such as
accounting and financial reporting systems, management reporting systems, payroll and HR
systems and administrative systems.
Relative to the actual level of IT expenditure undertaken between 2001 and 2004, the distributors
are proposing either increases or decreases in the level of IT expenditure in the
2006-10 regulatory period (see Table 7.41). The reasons the distributors have given for the level
of expenditure that they are proposing are set out in Table 7.42.
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Table 7.41:
Proposed capital expenditure — non-network general assets — IT, all
distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to historic
expenditure
Distributors’
revised proposals
relative to historic
expenditure
AGLE
24.4
87%
-7%
80%
CitiPower
52.0
-20%
-21%
-21%
Powercor
41.7
90%
50%
87%
SP AusNet
45.8
-85%
-86%
-75%
United Energy
42.9
17%
-6%
42%
a
Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure
has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period).
Table 7.42:
Reasons cited for the proposed non-network general assets — IT capital
expenditure
Reasons
AGLE
Works proposed include a major system replacement program to deliver full ring fencing and
interval meter roll out compliance, the replacement of hardware that has reached the end of its
useful life, and costs for licence and system updates.
CitiPower
Works proposed include distribution systems, customer service systems, corporate IT
requirements, IT infrastructure and security.
Powercor
Works proposed include distribution systems, customer service systems, corporate IT
requirements, IT infrastructure and security.
SP AusNet
Works proposed include works associated with the Enterprise Asset Management System,
Revenue Management System, Enterprise Application Integration, Knowledge Management
System, Reporting and Data Interrogation, and Accessibility and Mobility Automation.
United Energy
Works proposed include works associated with technology infrastructure such as PC/LAN
network and printers, billing systems, asset management systems, financial systems and storage
and hardware.
Source: AGLE 2004, pp. 59-64; AGLE (2005 ref); CitiPower 2004, pp. 68-70; Powercor 2004, pp. 72-74; SP
AusNet 2004, p. 91; United Energy 2004, p. 99.
As with SCADA/Network control assets, IT-related assets only require upgrading periodically.
Consequently, it is expected that the level of expenditure undertaken under this category of
capital expenditure will fluctuate from one regulatory period to another. Above-average
expenditure relative to actual expenditure will be necessary if systems that were not upgraded in
the last regulatory period now require replacement or upgrading.
Wilson Cook and Co reviewed the proposed IT-system plans and associated expenditure of each
of the distributors and generally considered the expenditure reasonable on the basis of the
information that was before it.
In its earlier report, Wilson Cook and Co recommended an adjustment to the expenditure
proposed by AGLE and United Energy of $22.7 million and $10.0 million respectively.
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However, following the provision of additional supporting information to justify their proposed
expenditure, Wilson Cook and Co has concluded in its further report that the expenditure
proposed by these distributors is reasonable and so has removed these adjustments.
Wilson Cook and Co noted that the plans for IT expenditure proposed by Powercor appeared
only preliminary, that detailed designs for the work had not yet been undertaken in all cases, and
that there may be room for expenditure reductions or deferrals as the work proceeds. It was of
the view that Powercor’s proposed expenditure was overstated by $18.5 million, excluding
indirect overheads and labour cost escalation. No additional supporting information was
provided by Powercor for Wilson Cook and Co to change its view in this regard.
To prepare for the roll out of interval meters (refer Chapter 13), the distributors are proposing
significant investment in IT systems. In assessing a reasonable level of capital expenditure
allocated to the DUoS price control and to the metering price control, the Commission has
adopted the principle that the costs of those IT systems that are required for all customers should
be recovered under the DUoS price control. The costs of those IT systems that are required only
for customers that have the distributor’s meter installed should be recovered through the
metering price control.
The proportion of expenditure in IT systems allocated to the DUoS price control and to the
metering price control varies by distributor. United Energy expressed concern that, because
different consultants were reviewing the IT expenditure for DUoS and for metering, some
expenditure could “slip through the net”. In this regard, the Commission notes that AGLE for
example has proposed relatively low IT expenditure for the metering price control and relatively
high IT expenditure for the DUoS price control, whilst SP AusNet has proposed relatively high
IT expenditure for the metering price control and relatively low IT expenditure for the DUoS
price control.
To ensure IT expenditure does not “slip through the net”, in assessing the IT expenditure in this
asset category the Commission has also included the difference between the distributor’s
proposed IT expenditure for prescribed metering services and the Commission’s forecast for the
metering revenue requirement.
This has resulted in an increase in the IT expenditure for CitiPower and SP AusNet, with little
change to the IT expenditure for AGLE and United Energy.
With regard to Powercor, Wilson Cook and Co has already made an adjustment to the proposed
expenditure on the basis that it did not appear to be reasonable. The Commission has therefore
not transferred any IT expenditure from the metering price control to the DUoS price control.
The levels of capital expenditure required for non-network assets — IT (including adjustments
for indirect (corporate) overheads and labour cost escalation) for the 2006-10 regulatory period
are set out in Table 7.43.
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Table 7.43:
Capital expenditure — non-network general assets — IT, all distributors,
2006-10 regulatory period, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
43.7
41.1
77.9
11.7
60.9
Wilson Cook and Co adjustment
0.0
0.0
-18.5
0.0
0.0
Commission’s adjustmentb
-2.3
9.0
0.1
17.4
1.7
Amount included in expenditure
cap (2006-10) (a)
41.4
50.1
59.5
29.1
62.6
Historic expenditure (2001-04)a (b)
24.4
52.0
41.7
45.8
42.9
Variance
17.0
-1.9
17.8
-16.7
19.7
70%
-4%
42%
-36%
46%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission.
Non-network general assets — other
Distributors undertake expenditure on non-network general assets — other for the purchase or
replacement of vehicles, tools and equipment, buildings and other property.
Two of the five distributors have proposed expenditure above the levels incurred in 2001-04 on
non-network general assets — other capital expenditure over the 2006-10 regulatory period (see
Table 7.44). The reasons cited are set out in Table 7.45.
Table 7.44:
Proposed capital expenditure — non-network general assets — other, all
distributors, $million, real $2004
Historic
expenditurea
Distributors’
original proposals
relative to historic
expenditure
Draft Decision
relative to historic
expenditure
Distributors’ revised
proposals relative to
historic expenditure
AGLE
13.2
68%
29%
68%
CitiPower
12.9
-4%
-29%
-49%
Powercor
39.6
103%
50%
41%
SP AusNet
15.6
-90%
-90%
-90%
United Energy
30.5
-54%
-52%
-52%
a
Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure
has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period).
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Table 7.45:
Reasons cited for the proposed non-network general assets — other capital
expenditure
Reasons
AGLE
Replacement of heavy vehicles, light vehicles, and rebuilding of the Broadmeadows depot.
CitiPower
Replacement of all Personal Data Entry devices by 2010, refurbishment of the Rooney Street
site.
Powercor
Replacement of all Personal Data Entry devices by 2010, significant motor vehicle and plant
investment due to the proposed capital expenditure program, upgrade of zone substation
fencing, development of a site in Western Melbourne, refurbishment of the Market Street site,
and refurbishment of an aged and obsolete supervisory cable system.
SP AusNet
General equipment, motor vehicles and mobile plant, office furniture, property and
telecommunications.
United Energy
Fleet, miscellaneous tools and equipment, furniture and equipment and property alterations.
Source: AGLE 2004, p. 64; CitiPower 2004, p. 71; Powercor 2004, p. 77; SP AusNet 2004; United Energy 2004,
p. 100.
Wilson Cook and Co reviewed the expenditure proposals of the distributors, noting that
CitiPower and Powercor had reduced their proposed expenditure from $12.4 million to
$6.5 million and from $80.4 million to $56.0 million respectively since the Draft Decision.
Wilson Cook and Co. commented that the distributors’ estimates were reasonable based on the
information available. However it recommended that the proposals be reduced in some areas, for
the following reasons:
•
Wilson Cook and Co observed that AGLE’s projected expenditure on other non-network
capital expenditure was higher than for other distributors. It had reservations about the
level of expenditure planned for other non-network capital expenditure, and was of the
view that the level of expenditure proposed was overstated by $4.0 million, excluding
indirect overheads and labour cost escalation. No additional information was provided to
justify the increase relative to historic expenditure and therefore the adjustment has been
retained.
•
Wilson Cook and Co noted that, prior to reducing its proposed expenditure, Powercor’s
projected expenditure was higher than that for the other four distributors, and considered
that it may be overstated by $12.8 million, excluding indirect overheads and labour cost
escalation. This adjustment was not considered necessary after Powercor reduced its
proposed expenditure and therefore the adjustment was removed in Wilson Cook and Co’s
further report.
The capital expenditure for non-network general assets — other (including adjustments for
indirect (corporate) overheads and labour cost escalation) for each distributor for the 2006-10
regulatory period is set out in Table 7.46.
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Final Decision
Table 7.46:
Capital expenditure — non-network general assets — other, all distributors,
2006-10 regulatory period, $million, real $2004
AGLE
CitiPower
Powercor
SP AusNet
United
Energy
Distributors’ revised proposals
22.2
6.5
56.0
1.6
14.7
Wilson Cook and Co adjustment
-4.0
0.0
0.0
0.0
0.0
Commission’s adjustmentb
0.0
0.0
0.1
0.0
0.0
Amount included in expenditure
cap (2006-10) (a)
18.2
6.5
56.1
1.6
14.7
Historic expenditure (2001-04)a (b)
13.2
12.9
39.6
15.6
30.5
Variance
5.0
-6.4
16.5
-14.0
-15.8
37%
-50%
42%
-91%
-52%
a
Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a
like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to
represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate)
overheads (refer Table 7.12) and other adjustments by the Commission
Enhanced offerings
In their original price-service proposals under ‘enhanced offerings’, CitiPower and Powercor
proposed expenditure of $37.1 million and $26.2 million respectively over the 200610 regulatory period for undergrounding.
CitiPower proposed funding of $5 million per annum through the Powerline Relocation
Committee to assist funding for projects within the CitiPower area which, according to its
submission, have been assessed for significant community benefit. An additional $10.5 million
was proposed for undergrounding all new high voltage (11 kV and above) extensions. Powercor
proposed to commence undergrounding in the areas of highest fire danger.
Whilst CitiPower and Powercor have stated that significant community benefit will be achieved
as a result of their forecast capital expenditure on undergrounding, they have not quantified the
benefit or shown how that benefit was determined. The results of a customer survey provided by
the distributors indicate that their electricity customers are willing to pay more than the estimated
cost of undergrounding, although the survey was based on a small number of customers.
In its submission to the Position Paper, CitiPower (2005cc, p. 3)) stated that the
Commission has an obligation to investigate the benefits associated with undergrounding
both from the standpoint of ensuring it meets its own objectives, but also from a societal
perspective given the benefits from undergrounding largely accrue to the community as a
whole.
Powercor provided a similar response.
As indicated earlier, the Commission notes that, following the last Price Review, the State
Government established a Powerline Relocation Scheme. Under this scheme, the Government
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Final Decision
funds up to 50 per cent of the cost of placing powerlines underground, or otherwise relocating
them, where a community benefit will result. This is considered to be a more appropriate
mechanism for obtaining the funds required to underground network assets, where there is a
community benefit.
Additionally, the Commission is of the view that the incentive-based nature of its framework and
approach will provide suitable stimulus to ensure that distributors assess such projects on their
merits, and undertake undergrounding where the benefit to the distributor outweighs the cost.
Furthermore, customers may contribute to the cost of undergrounding cables where they are
willing to pay.
The Commission has therefore not included expenditure for CitiPower and Powercor for
undergrounding.
Additionally, Powercor proposed:
•
the trialling of energy efficient technologies in a 600 site new estate in Melbourne’s north
west using solar and photovoltaic technologies at a cost of $11 million; and
•
a $5 million distribution loss factor reduction strategy targeting high loss feeders.
In its Position Paper, the Commission noted that trials of efficient technologies are already
occurring, despite the lack of an explicit expenditure allowance. The Commission recognises that
developers can charge a premium for land on the basis that energy efficient technology has been
installed. As compensation can be acquired through direct means, the Commission is of the view
that Powercor cannot expect all customers to contribute to such costs.
With regard to the distribution loss factor reduction strategy, the Commission queried the
efficiency of this strategy. Assuming losses are valued at $30 per MWh, the $5 million of capital
expenditure may only result in a reduction in energy costs of $214 500 per annum.
EUCV (2005b, p. 40) supported the Commission’s view.
The Commission has therefore not included expenditure for Powercor for the trialling of energy
efficient technologies or the proposed distribution loss factor reduction strategy. Nevertheless, if
Powercor continues to believe that such expenditure is justified and proceeds to invest, then the
capital expenditure will be presumed to be efficient and rolled into the regulatory asset base at
the discretion of the relevant regulator.
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8 REGULATORY ASSET BASE
The distributors’ regulatory asset bases represent the value, as assessed by the Commission, of
past or sunk network investments. This is the value on which the owner of the business can
expect to earn a return (return on capital), and the value that is returned to the asset owner over
the economic life of the assets (as regulatory depreciation).
The Victorian Tariff Order sets out requirements that the Commission must comply with when
determining the distributors’ regulatory asset bases. The Tariff Order sets out regulatory asset
bases for each distributor as at 1 July 1994 and requires that at each regulatory period these
values be adjusted for inflation, capital expenditure, depreciation, customer contributions and
disposals over regulatory periods. This is referred to as the roll forward method.
This Chapter sets out the Final Decision on the distributors’ regulatory asset bases for the
2006-10 regulatory period. The Chapter also sets out the information the Commission has
considered in making its decision and the reasons for its decision.
8.1 Final Decision
The regulatory asset bases that have been used to determine the return on capital and return of
capital components of the distributors’ revenue requirements for each year of the
2006-10 regulatory period are set out in Table 8.1. These values have been determined in
accordance with the Victorian Tariff Order requirements, adjusting for inflation, gross capital
expenditure, customer contributions, disposals and regulatory depreciation.
An adjustment has also been made for any difference between the assumed and actual net capital
expenditure (and disposals) in the year 2000. Any under- or over-spend in actual capital
expenditure (and disposals) in 2000 relative to the assumed capital expenditure and disposals has
been subtracted from/added to the regulatory asset base as actual data for 2000 was not available
to the Commission at the time the 2001 price determination was made.
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Table 8.1:
Regulatory asset base, by distributor, 2006-10, $million, real $2004
2006
2007
2008
2009
2010
578.4
588.6
591.1
595.5
593.9
50.7
44.3
46.6
41.9
49.3
Customer Contributions
4.4
4.5
4.2
4.4
5.1
Disposals
0.0
0.0
0.0
0.0
0.0
36.0
37.4
38.0
39.1
39.5
Closing RAB
588.6
591.1
595.5
593.9
598.7
Average RAB
583.5
589.9
593.3
594.7
596.3
Opening RAB
990.9
1,022.1
1,049.5
1,075.5
1,114.7
Gross Capital Expenditure
101.3
96.7
95.3
104.6
88.7
Customer Contributions
5.7
5.6
5.5
6.0
6.0
Disposals
0.0
0.0
0.0
0.0
0.0
64.3
63.8
63.8
59.4
60.6
Closing RAB
1,022.1
1,049.5
1,075.5
1,114.7
1,136.9
Average RAB
1,006.5
1,035.8
1,062.5
1,095.1
1,125.8
1,626.5
1,671.3
1,729.5
1,790.7
1,847.1
171.8
186.2
190.4
187.6
190.3
25.9
26.1
26.0
26.0
26.5
0.0
0.0
0.0
0.0
0.0
101.2
101.9
103.2
105.3
106.3
Closing RAB
1,671.3
1,729.5
1,790.7
1,847.1
1,904.6
Average RAB
1,648.9
1,700.4
1,760.1
1,818.9
1,875.9
1,307.2
1,362.9
1,404.2
1,441.2
1,481.8
139.3
132.8
133.9
140.1
148.2
12.9
13.5
13.9
12.0
14.1
0.0
0.0
0.0
0.0
0.0
70.8
78.0
83.0
87.4
92.0
Closing RAB
1,362.9
1,404.2
1,441.2
1,481.8
1,523.8
Average RAB
1,335.1
1,383.5
1,422.7
1,461.5
1,502.8
AGLE
Opening RAB
Gross Capital Expenditure
Regulatory Depreciation
CitiPower
Regulatory Depreciation
Powercor
Opening RAB
Gross Capital Expenditure
Customer Contributions
Disposals
Regulatory Depreciation
SPAusNet
Opening RAB
Gross Capital Expenditure
Customer Contributions
Disposals
Regulatory Depreciation
(Continued next page)
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Table 8.1:
Regulatory asset base, by distributor, 2006-10, $million, real $2004
2006
2007
2008
2009
2010
1,220.3
1,228.8
1,229.9
1,228.7
1,248.2
101.1
95.0
95.5
102.1
109.4
Customer Contributions
4.2
4.2
3.9
3.8
4.1
Disposals
0.0
0.0
0.0
0.0
0.0
88.4
89.7
92.8
78.7
69.6
Closing RAB
1,228.8
1,229.9
1,228.7
1,248.2
1,283.8
Average RAB
1,224.5
1,229.4
1,229.3
1,238.4
1,266.0
United Energy
Opening RAB
Gross Capital Expenditure
Regulatory Depreciation
The measure of inflation that the Commission has used to roll forward the regulatory asset bases
for the 2001-05 period is the All Groups Consumer Price Index — Average of the Eight State
Capitals, as published by the Australian Bureau of Statistics.
The depreciation used to establish the opening regulatory asset bases in 2006 is the regulatory,
rather than actual, depreciation determined in the 2001 price review. The values of regulatory
depreciation that the Commission has used to establish the regulatory asset bases for the 2006-10
period are calculated using the depreciation profiles (straight-line on an inflation indexed asset
base) and effective lives proposed by the distributors. The depreciation that will be used to
establish the opening regulatory asset bases in 2011 will also be the regulatory, rather than
actual, depreciation.
The opening regulatory asset bases used to set the revenue requirements for the
2006-10 regulatory period have been based on the assumed capital expenditure (and disposals)
for 2005. For the purposes of the next regulatory period, an adjustment will be required for any
difference between assumed and actual year 2005 capital expenditure (and disposals).
8.2 Reasons for the Final Decision
To calculate the opening regulatory asset base for each distributor at 1 January 2006, the
following formula is used.
Opening Regulatory Asset Base2006 = Opening Regulatory Asset Base2001 + Capital
Expenditure2001-2005 – Customer Contributions2001-2005 – Regulatory Depreciation2001-2005 –
Disposals2001-2005
Once the opening value has been established, the same approach is then used to determine the
opening value for each year of the regulatory period. Forecasts of capital expenditure, customer
contributions, regulatory depreciation and disposals are used in this calculation.
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8.2.1 Opening value of the asset base (1 January 2006)
To determine the regulatory asset base at 1 January 2006, the Commission has used the capital
expenditure amounts set out in Chapter 5. These capital expenditure amounts and each
distributor’s reported customer contributions and disposals have been used to roll forward the
1 January 2000 value of the regulatory asset base to 1 January 2005. An adjustment has also been
made for the difference between the forecasts for year 2000 used in the last price review and the
actuals reported, except for depreciation which is the regulatory depreciation estimate made for
2000.
The Commission does not have all the information it requires to update the value of the
distributors’ regulatory asset bases to 1 January 2006 because information on capital
expenditure, customer contributions and disposals for the year 2005 is not available. As a result
the Commission has used the estimates of capital expenditure, customer contributions, disposals
and regulatory depreciation used in the 2001 price review to determine the 2005 revenue
requirements.
An adjustment will be made in 2010 for any difference between assumed and actual net capital
expenditure for 2005, when the opening regulatory asset bases are calculated for the next
regulatory period (which begins in January 2011). Regulatory depreciation will remain the same
as that estimated for this price review. Table 8.2 sets out the resulting values of the regulatory
asset base at 1 January 2006.
Table 8.2:
Regulatory asset base, by distributor, 2000-05, $million, real $2004
2000
2001
2002
2003
2004
2005
569.2
572.4
577.9
567.6
558.1
550.4
42.3
42.6
34.6
38.9
38.1
72.2
Customer Contributions
8.3
4.3
6.6
7.0
4.6
1.8
Disposals
0.4
0.1
1.7
2.5
0.1
0.0
30.4
32.7
36.7
39.0
41.0
42.5
Closing RAB
572.4
577.9
567.6
558.1
550.4
578.4
Average RAB
570.8
575.2
572.8
562.8
554.3
564.4
848.2
887.7
913.9
935.9
947.2
968.4
86.7
83.8
73.7
65.7
78.6
77.8
Customer Contributions
7.8
8.8
8.1
8.9
10.1
7.7
Disposals
2.6
7.0
0.2
0.3
0.3
0.0
36.8
41.8
43.3
45.2
47.0
47.6
Closing RAB
887.7
913.9
935.9
947.2
968.4
990.9
Average RAB
867.9
900.8
924.9
941.5
957.8
979.6
AGLE
Opening RAB
Gross Capital Expenditure
Regulatory Depreciation
CitiPower
Opening RAB
Gross Capital Expenditure
Regulatory Depreciation
(Continued next page)
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Table 8.2:
Regulatory asset base, by distributor, 2000-05, $million, real $2004
2000
2001
2002
2003
2004
2005
1,540.9
1,587.6
1,605.3
1,593.6
1,585.3
1,592.2
175.3
158.3
139.21
149.6
161.9
163.6
42.4
25.5
32.0
38.8
37.1
17.6
3.5
0.9
2.2
1.4
1.5
0.0
82.7
114.1
116.7
117.7
116.5
111.7
Closing RAB
1,587.6
1,605.3
1,593.6
1,585.3
1,592.2
1,626.5
Average RAB
1,564.2
1,596.4
1,599.4
1,589.5
1,588.8
1,609.4
1,201.3
1,211.7
1,237.2
1,214.3
1,216.0
1,244.3
Gross Capital Expenditure
94.0
119.3
79.2
108.1
128.4
145.5
Customer Contributions
18.6
19.3
23.0
29.9
27.6
9.8
Disposals
13.2
1.0
1.6
0.2
0.0
0.0
Regulatory Depreciation
51.7
73.6
77.5
76.3
72.4
72.7
Closing RAB
1,211.7
1,237.2
1,214.3
1,216.0
1,244.3
1,307.2
Average RAB
1,206.5
1,224.5
1,225.7
1,215.1
1,230.1
1,275.7
1,180.5
1,206.7
1,195.5
1,198.8
1,199.0
1,189.5
109.3
79.2
89.5
87.1
83.2
121.5
Customer Contributions
18.5
14.2
11.7
7.7
5.9
1.1
Disposals
11.0
0.0
1.2
0.7
1.1
0.0
Regulatory Depreciation
53.6
76.1
73.3
78.4
85.7
89.6
Closing RAB
1,206.7
1,195.5
1,198.8
1,199.0
1,189.5
1,220.3
Average RAB
1,193.6
1,201.1
1,197.2
1,198.9
1,194.2
1,204.9
Powercor
Opening RAB
Gross Capital Expenditure
Customer Contributions
Disposals
Regulatory Depreciation
SPAusNet
Opening RAB
United Energy
Opening RAB
Gross Capital Expenditure
Adjustment for the allocation of CitiPower’s IT assets
The approach to rolling forward the distributors’ asset bases has been established to be consistent
with the treatment of ‘pre-vesting’ assets as set out in the Tariff Order90 and to value investments
since privatisation at cost (net of customer contributions). It does not provide for the re-valuation
of assets already included in the regulatory asset base.
In 2002, CitiPower made a $30 million adjustment to its regulatory accounts to transfer the
proportion of the value of certain IT-related assets previously allocated to CitiPower’s retail arm
into the distributor’s asset base. This transfer was made following the sale of CitiPower’s retail
90
Clause 2.1(b) of the Tariff Order. ‘Pre-vesting’ assets are the assets in place as at 1 July 1994.
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Final Decision
arm to Origin Energy and justified by CitiPower on the basis that these IT-related assets were
now solely used by the distribution business.
In subsequent discussions with the Commission, CitiPower reduced the value of the adjustment
to these IT-related assets to $18 million so that it reflected the depreciated value of these assets.
In its Draft Decision the Commission considered that CitiPower’s distribution customers had not
benefited from the sale of the retail arm but, under CitiPower’s proposed approach, they were
being expected to finance the IT assets previously allocated to the retail business.
The Commission’s Regulatory Accounting Guideline No. 3 (Issue 4) is not prescriptive in terms
of cost allocation. However, it does require costs that are directly attributable to the distributor be
assigned accordingly and costs that are not directly attributable to the distributor be allocated to
the distributor on a causation basis where a causation relationship exists. Where costs are
allocated, the distributor is required to provide supporting information including the amounts that
have been allocated, the basis of allocation, and the numeric quantity of each allocator. Capital
expenditure is directly attributed or allocated to the appropriate business segments in the year in
which it is incurred.
The effect of CitiPower’s adjustment is to increase its regulatory asset base through a change in
allocation policy rather than through the methodology outlined in the 2001-05 price review and
reconfirmed for the 2006-10 price review. A change in allocation policy between the distribution
and retail business does not constitute additional capital expenditure and thus should not result in
an addition to the regulatory asset base of the distribution business.
Allowing CitiPower to adjust its 2002 regulatory accounts for these IT-related assets is not
consistent with the roll forward approach to establishing the asset base — CitiPower has not
demonstrated that it has outlaid capital to acquire the balance of these assets.
To now require distribution customers to pay more despite no additional costs being incurred
would provide CitiPower with additional revenue for no corresponding increase in service
capacity.
Since the release of the Commission’s Draft Decision CitiPower has not responded to this issue.
However Origin Energy (2005, p. 1) (the purchaser of the retail arm) supported this conclusion
in response to the Position Paper, suggesting that:
There is little justification for transferring IT expenditure allocated to CitiPower’s retail
business to its distribution business simply as a result of the retail business having been
sold off to a different owner. The decision to separate the businesses was taken by the
former owner to maximise the aggregate sale price, and it seems unreasonable to ask
distribution customers to pay more as a consequence.
Consistent with the Draft Decision the Commission has excluded the addition of the value of IT
assets claimed by CitiPower when rolling forward the asset base.
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Measure of inflation
To establish a value for the opening regulatory asset base for the 2006-10 regulatory period,
adjustments have been made to the actual outcomes of the 2001-05 regulatory period using an
appropriate measure of inflation.
The purpose of indexing asset values with inflation is to preserve the real value of the asset
owners’ investment, thereby minimising inflation risk to the asset owner. It follows that the
measure of inflation adopted should be that which provides the best measure of changes in the
purchasing power of money in Australia.
To establish each distributor’s regulatory asset base as at 1 January 2006, the Commission has
applied the same methodology to adjust for inflation that was utilised in the 2001-05 price
review. Specifically, this involves:
•
adopting the All Groups Consumer Price Index — Average of the Eight State Capital Cities
(published by the Australian Bureau of Statistics) as the measure of actual inflation which
is relevant for changes to the purchasing power of money in the Australian market;
•
using the CPI from nine months prior to a point in time as a proxy for the price level at that
point in time, mirroring the treatment in the 2001-05 price controls; and
•
assuming all past and future revenue and expenditure is received or incurred at the
midpoint of each calendar year.
8.2.2 Rolled forward values of the regulatory asset base (2006-10)
Having determined the opening value of regulatory asset bases at 1 January 2006, estimates of
the regulatory asset bases for each year of the 2006-10 regulatory period have been determined
using the roll forward approach.
Capital expenditure
The estimates of gross capital expenditure rolled into the asset base are those determined in
accordance with the Commission’s building block approach (see Chapter 7).
Regulatory depreciation
The purpose of allowing a ‘return of’ capital through depreciation when setting regulated charges
is to return to investors the value of the capital that has been invested. This form of depreciation
is consistent with the accounting concept of financial capital maintenance. The Commission has
adjusted the components of the regulatory asset base for inflation over time, which implies that
financial maintenance is preserved in real terms (that is, inflation adjusted) and depreciation
reflects the return of the real cost of the asset. Ideally the rate of depreciation should be
consistent with the economic potential of the asset over its physical life.
In the consultation process, the Commission provided stakeholders with the opportunity to
propose alternative methods for the calculation of regulatory depreciation. When considering
alternatives, the Commission was concerned to ensure increased transparency for all stakeholders
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Final Decision
to understand the derivation of regulated charges and the extent to which costs have been
allocated between current and future users of the regulated services. However, there was general
support for the continued use of straight-line depreciation applied to an asset base that is indexed
for inflation. In their October 2004 price-service proposals all of the distributors proposed
straight-line depreciation. Such an approach is consistent with that implemented by regulators in
other Australian jurisdictions.
The Commission has applied the straight-line method for the calculation of regulatory
depreciation for the 2006-10 period. In application, this methodology is transparent and easily
replicated, and is also consistent with a stable growth in demand. This approach returns invested
capital to the investor at a constant rate (in real terms) over the life of the asset.
In applying the straight-line method for the calculation of regulatory depreciation, the
Commission has not required the adoption of a standardised set of asset lives or classes. That is,
it has adopted the asset lives proposed by the distributors. This ‘hands-off’ approach to
determining regulatory depreciation reflects the fact that the rate of depreciation affects only the
timing (rather than value) of cash flows. Additionally, consistent with the approach outlined in
the 2001 Electricity Distribution Price Review, the Commission simply deducts the regulatory
depreciation reflected in the price controls to determine the regulatory asset values in future
regulatory periods — it does not recalculate the depreciation allowance for actual expenditure
over the period.
The Commission notes that it has received late proposals from AGLE and CitiPower that
represent a significant change in the amount of regulatory depreciation recovered over the
2006-10 regulatory period. Similarly, the ORG received late proposals at the time of the last
price review.
The proposal provided by AGLE entails a change in estimate regarding the depreciable life of
SCADA from 20 years to 5 years. AGLE stated that the change in estimate was considered
appropriate as the technical life of SCADA equipment was considered to be much shorter than
20 years, because the hardware upon which it is built rarely has an available life longer than
4 years, thereby resulting in shorter manufacturer support periods (AGLE 2005, p. 93). This
proposal will result in an increase in AGLE’s total amount of regulatory depreciation for the
2006-10 regulatory period by approximately $5 million (real $2004).
The proposal provided by CitiPower entails a change in the calculation of regulatory
depreciation for assets acquired before 1 January 2006 due to an error that CitiPower has
identified in the model that calculated depreciation for its original October 2004 price-service
proposals. CitiPower had incorrectly calculated depreciation rates by using new, rather than
assumed remaining asset lives, thus resulting in depreciation rates lower than they ought to have
been. The correction of this apparent has a significant impact upon CitiPower’s total amount of
regulatory depreciation for the 2006-10 regulatory period, increasing that total by approximately
$70 million (real $2004). This represents a change in the rate of total depreciation from 4.2 per
cent to 5.9 per cent of the regulatory asset base.
The Commission has to date adopted a ‘hands off’ approach to regulatory depreciation on the
basis that different rates of depreciation will affect the timing, rather than the level, of the return
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of capital. Consistent with this approach, the Commission has made the adjustments submitted
by AGLE and CitiPower. The regulatory depreciation amounts used by the Commission for the
2006-10 regulatory period are as set out in Table 8.3.
Table 8.3:
Regulatory depreciation schedule, 2006-10, by distributor, $million, real
$2004
2006
2007
2008
2009
2010
Total
AGLE
36.0
37.4
38.0
39.1
39.5
189.9
CitiPower
64.3
63.8
63.8
59.4
60.6
311.8
Powercor
101.2
101.9
103.2
105.3
106.3
517.8
SPAusNet
70.8
78.0
83.0
87.4
92.0
411.2
United Energy
88.4
89.7
92.8
78.7
69.6
419.2
Note: Totals may vary slightly due to rounding.
As stated above, the depreciation rates applied by the Commission are the same as those
submitted by the distributors. The Commission has been concerned, however, that its ‘hands off’
approach has limited the scope to consult on proposed changes to depreciation, particularly
where changes to depreciation are proposed late in the price review process.
While in principle depreciation rates affect only the timing (rather than value) of cash flows, the
choice of depreciation rates will affect the stability of prices over time. Therefore, recognising
the desirability of stability in the application and calculation of depreciation, the Commission
foreshadows that it is unlikely to allow changes to depreciation profiles in future reviews where
such changes do not provide adequate time for consultation and/or are not sufficiently supported
by credible reasons.
To ensure consistency and stability, the Commission anticipates that any future review will more
closely evaluate regulatory depreciation proposals and asset lives for consistency with history,
consistency of economic and technical lives of assets, and will also have regard to the
implications for prices over the long term.91 The Commission also anticipates that, as
depreciation rates impact on the timing of cash flows to the distributors but may have substantial
implications for the intergenerational burden on customers, material changes to depreciation
profiles would only be accepted where there is sufficient opportunity for consultation with
customers (and they are not otherwise inappropriate). Table 8.4 illustrates how depreciation, as a
percentage of the regulatory asset base, has changed over regulatory periods.
91
In their recent Electricity Distribution Price Control Review, Ofgem (2004a) expressed a similar view: “In the longer term, it
would be reasonable to expect the price control treatment of long-lived assets to more closely approximate to their useful
technical or economic lives, for example so that the customers that pay for an asset are those that derive benefit from it.
Were it not for the peculiarities of pre-vesting asset lives and the need to maintain broadly stable financial profiles, it seems
unlikely that 20 year lives would be optimal. Ofgem will want to review this issue at the next review in the light of these
considerations” (Ofgem 2004, p.95).
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Table 8.4:
Regulatory depreciation as a percentage of regulatory asset base, historic
and forecast, by distributor
1994-2000
2001-05
2006-10
AGLE
5.2%
6.3%
6.4%
CitiPower
4.2%
4.8%
5.9%
Powercor
5.1%
7.1%
5.9%
SPAusNet
4.2%
5.6%
5.8%
United Energy
4.5%
6.3%
6.8%
Public lighting
In its submissions to the Draft Decision and Position Paper, the Street Light Group of Councils
(SLG) expressed concern with regard to the valuation and subsequent depreciation associated
with public lighting assets that form part of the regulatory asset base of each distributor. This
issue had also been raised by the SLG in response to the Commission’s Issues Paper and in its
submissions relating to the Review of Public Lighting Excluded Service Charges – Final
Determination (ESC 2004c).
The Commission considers that it has effectively addressed the concerns of the SLG through the
review of public lighting excluded service charges. The Commission clearly outlined that the
value of the regulatory asset base for each of the distributors (as at 1 July 1994) is directed by
Clause 2.1 of the Tariff Order. The requirements of the Tariff Order are a matter for the State
Government of Victoria and not the Commission.
The Commission notes that the distributors do not have a specific tariff for public lighting
customers. The depreciation on public lights in the regulatory asset base is therefore recovered
across all customers. The proportion of public lighting assets to total sunk assets (for all
distributors) is approximately 2 per cent. Consequently, the impact on prices will be immaterial.
Also, the Public Lighting Code requires distributors to depreciate public lighting assets over the
economic life of the asset. However it does not prescribe the number of years to which such an
economic life corresponds.92
Customer contributions and disposals
The estimates of customer contributions are as determined in accordance with the Commission’s
building block approach (see Chapter 7), and the estimates of disposals are those submitted by
the distributors in their October 2004 price-service proposals.
92
Public Lighting Code, September 2001.
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9 COST OF CAPITAL FINANCING
The cost of capital financing represents the largest proportion of the total revenue requirement
for each distributor. It comprises both a return of capital and a return on capital.
The return on capital (or weighted average cost of capital) is the financial return that investors
seek when considering and assessing an investment decision. To provide an incentive for
investors to invest, the rate of return should reflect the opportunity cost of their capital — that is,
the return should be commensurate with the returns that an investor could expect to earn from
other investment opportunities in the market, after adjusting for the different levels of risk that
different investments entail. While low prices may be in the interests of customers in the short
term, the Commission considers that the long term interests of customers (particularly with
respect to reliability) require prices to generate sufficient returns to attract the investment
required over the long term.
The cost of capital for a particular investment is determined by the market. It is based on the
aggregate demand and supply of investment funds and the riskiness of the potential cash flows
generated by the investment in question relative to the riskiness of the cash flows generated by
other investments. However, the cost (price) of capital cannot be observed in the same manner in
which prices for other goods and services may be observed.93 Neither the regulated entity nor the
regulator can observe or determine the cost of capital. Instead, the risk adjusted price for
investment capital must be estimated from available capital market data, and can be interpreted
using models drawn from finance theory and practice.
In its previous reviews, the Commission emphasised the need to have primary regard to objective
market evidence when estimating the cost of capital associated with the distributors’ assets, as
well as the consistent application of models drawn from finance theory and practice. These
principles are equally applicable to the current review.
The Commission is mindful that the distributors will not recover the costs associated with the
investments being made now for up to 40 or more years.
This makes it important that the Commission also seeks to create, to the extent possible, a stable
and predictable regime with decisions that can be replicated. However, having regard to the latest
market evidence in isolation is unlikely to create a sufficiently stable and predictable regime. The
imprecision with estimates of the cost of capital could result in the ‘best’ estimate of the cost of
capital varying substantially from one review to the next.
Given the substantial imprecision in estimates of the cost of capital and the need to foster a
stable, predictable and replicable regime, the Commission considers it important to adopt a
cautious approach when interpreting new but uncertain evidence relevant to the cost of capital,
and to adopt a cautious approach when considering changes to key inputs or assumptions relative
to those adopted in previous reviews. The application of these considerations to the estimation of
93
Aggregate economy wide measures of the cost of capital can be determined using data from the National Accounts
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the cost of capital associated with the distributors’ regulated activities is discussed in more detail
in this chapter.
This Chapter sets out the Commission’s Final Decision on the return on capital component of the
cost of capital financing. The Final Decision is set out in Section 9.1 and the reasons for the Final
Decision are set out in Section 9.2.
9.1 Final Decision
The Commission has estimated the after-tax real cost of capital associated with the distributors’
regulated activities for the 2006-10 regulatory period (as at 31 August 2005) at 5.90 per cent.
The estimate has been used to determine the revenue requirements for each distributor. The input
parameters that it has used to derive this estimate are set out in Table 9.1.
In estimating the after-tax weighted average cost of capital (WACC), the Commission has used
the ‘vanilla WACC’, and utilised the Capital Asset Pricing Model (CAPM) to estimate the after
tax return on equity.
Table 9.1:
Weighted average cost of capital and input parameters
Final Decision
2.64%
Risk free rate (real) (Rf)
0
Rural risk adjustment
Debt premium (Rd)
1.425%
Equity (market risk) premium
(Rm – Rf)
6.00%
Equity beta (βe)
1.00
Franking credit value (γ)
0.50
Gearing (debt/assets)
60%
Inflation
2.56%
Real after-tax ‘vanilla’ WACC
5.90%
9.2 Reasons for the Decision
In the 2001 electricity distribution price review, the Commission adopted a real after-tax WACC
to determine an appropriate rate of return on the distributors’ asset values over the regulatory
period. At the time the Commission noted that dealing with the implications of taxation (and
franking credits) in the WACC created a number of complexities and introduced scope for error.
It also concluded that dealing with taxation implications in the WACC lacked transparency.
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As a result, the Commission chose a version of the WACC known as the ‘vanilla WACC’ to
estimate the real after-tax cost of capital.
WACC = Re
E
D
+ Rd
V
V
where Re is the (real) required after-tax return on equity, Rd is the (real) cost of debt, and E, D
and V are the market values of equity, debt and assets respectively.
The real after-tax return on (cost of) equity was estimated using the Capital Asset Pricing Model
(CAPM):
Re = Rf + βe (Rm – Rf)
where Rf is the risk-free rate of return, βe is the estimated equity beta and (Rm — Rf) is the return
over the risk free rate that investors would expect in order to invest in a well-diversified portfolio
of equities (otherwise referred to as the equity (market risk) premium).
In making its Final Decision, the Commission considered the methodology used for estimating
the after-tax WACC and the values of each of the input parameters that are used to estimate the
WACC.
9.2.1 Methodology for estimating the after-tax WACC
In previous price reviews, the Commission has used the CAPM to estimate the cost of capital
associated with the distributors’ regulated activities.94 The CAPM is widely used and understood
by both the finance community and industry, is consistent with the methodology used by
virtually every other economic regulator in Australia and the UK and was not objected to in any
submission to this review. Accordingly, the Commission has used the CAPM.
While in theory the CAPM provides a direct estimate of the cost of capital associated with a
project, in practice it can feasibly be used only to estimate the required returns to the
equity-financed portion of the project. Accordingly, the version of the CAPM that has been used
in this review specifies the estimate of the required real return to the equity providers as follows:
Re = Rf + βe (Rm – Rf)
where Rf is the risk-free rate of return, βe is the estimated equity beta and (Rm — Rf) is the return
over the risk free rate that investors would expect in order to invest in a well-diversified portfolio
of equities (otherwise referred to as the equity (market risk) premium).
94
The term ‘vanilla WACC’ has become a relatively common term used in Australia to refer to the simplified weighted
average cost of capital formula that does not incorporate any treatment of tax. This approach assumes the treatment of tax is
incorporated in the cash flows as a separate item in the revenue requirement.
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The cost of capital associated with an investment can then be estimated as the weighted average
of the cost of equity and cost of debt (hence, weighted average cost of capital, or WACC), with
the cost of debt financing normally estimated from the observed or estimated yields for debt
financing. As a result, the cost of capital can be estimated as (abstracting from issues related to
company tax):
WACC = Re
E
D
+ Rd
V
V
where Re is the (real) required after-tax return on equity, Rd is the (real) cost of debt, and E, D
and V are the market values of equity, debt and assets respectively.
In the 2001-05 price review, the Commission determined an after-tax version of the WACC and
derived a benchmark allowance for taxation. This contrasted with the position advanced by the
distributors at that time that an allowance for taxation should be provided by adopting a pre-tax
WACC — that is, a higher WACC that includes compensation for tax. The benchmark for
taxation calculated by the Commission reflected its view of the tax treatment of an efficient
distributor, subject to the need for consistency with the other features of the Commission’s
decision. The Commission adopted an after-tax WACC because it concluded that dealing with
the implications of taxation (and franking credits) in the WACC creates a number of
complexities, introduces scope for error and lacks transparency.
The Commission considers that the approach implemented in the 2001 Electricity Distribution
Price Review remains current and has adopted the same version of the after-tax WACC, again
compensating for taxation by deriving a benchmark allowance for taxation.
Accordingly, the assumptions required to estimate the after-tax WACC for the distributors’
regulated activities are:
•
real risk-free rate of return (Rf);
•
equity (market risk) premium (Rm — Rf);
•
proxy beta (βe); and
•
benchmark cost of debt (Rd) and financing arrangements
(
E
D
and
V
V
).
In submissions to this price review, AGLE proposed that the statistical technique known as the
‘Monte Carlo’ method be used to assist in estimating of the cost of capital associated with the
distributors’ regulated activities. In later submissions, AGLE’s views have been supported by
United Energy and the Energy Networks Association (ENA).
Under the Monte Carlo method, a (joint) probability distribution is derived or assumed for all of
the input parameters into the WACC. Many random sample observations are then simulated for
each of the inputs and a probability distribution for the WACC derived.
AGLE stated that using the Monte Carlo method would provide a more robust and transparent
method for regulators to address the uncertainty in each WACC parameter.
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In its Position Paper, the Commission noted that, while the Monte Carlo method is used
commonly in some fields to deal with uncertainty, it did not consider that the extensive
information requirements for applying the method in a robust and transparent manner could be
met.
In response to the Position Paper, AGLE (2005b, p. 20) reiterated its view that the use of the
Monte Carlo method would assist regulatory decision making. It stated that, among other things,
the Monte Carlo method would provide further information on the real level of measurement
error in the final value of WACC, provide further transparency and a more robust framework for
deriving a conservative estimate for the WACC. According to AGLE, the Monte Carlo method
would enable a degree of conservatism to be specified as a probability limit.
United Energy (2005c) supported the use of Monte Carlo methods in principle, and the Energy
Networks Association (ENA) (2005a, p. 8) supported the exploration of alternative
methodologies for the estimation of WACC and expressed the view that the Commission’s:
… dismissal of probabilistic approaches to cost of capital estimation is not soundly based.
In response to the Draft Decision, United Energy (2005n) again supported the use of Monte
Carlo simulation as a method to address uncertainty in the calculation of the WACC. United
Energy (2005n) was of the opinion that Monte Carlo simulation provides the most objective and
rigorous approach to dealing with uncertainty in the estimation process, and that it warrants the
Commission’s full and objective consideration.
Similarly, AGLE (2005f) in its response to the Draft Decision stated that
The statistical approach is better than judgement applied to individual point estimates and
can be undertaken without additional information requirements and without significant
additional analysis...it also provides more certainty and transparency and assists in
decision making (AGLE 2005, p. 75).
Specifically in relation to the proposals made by AGLE (2005f, p. 5) for the measurement of the
values of the input parameters, it has “assigned a statistical distribution where uncertainty was
considered material”, and undertaken a Monte Carlo simulation to derive a probability
distribution for the WACC. On this basis AGLE derived an equity beta of value of 1 with a
uniform distribution 0.9 to 1.1, and an equity (market risk) premium (normally distributed) with
a mean of 6 per cent and a standard deviation of 1.8 per cent. AGLE proposed that the 75-80th
percentile from the calculated distribution be adopted as the value for WACC, and provided a
point estimate of 6.70 per cent.
The Commission has not been persuaded to use the Monte Carlo method on the basis of the
comments made by AGLE, United Energy or the ENA regarding the ability of the methodology
to increase transparency and certainty. The Commission acknowledges the concerns expressed
by, amongst others, the Productivity Commission in its review of the National Access Regime
and Gas Access Regime that there is sound reason for setting regulated charges at a level at
which the Commission is confident the returns provided to investors are sufficient to continue to
attract capital into the industry. Indeed, the Commission’s primary objective — referring as it
does to the long term interests of consumers — directs the Commission to this end in any event.
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However, the Commission remains of the view that the methodology that is has used in previous
reviews remains appropriate for this exercise.
The Commission also rejects the contention made by AGLE (2005f) that the Commission is
required to explicitly quantify the uncertainty in the estimation of the WACC and each of its
input parameters.
As the Commission has explained previously, it does not consider it possible to derive
probability distributions — with which it can have the necessary level of confidence — for most
of the WACC inputs. The fact that the Commission has relied on a number of sources of
evidence when forming its views about the appropriate estimate for each WACC parameter
makes it impossible to derive standard errors for the estimates using conventional means, and
makes such estimates speculative.
In addition, the Commission’s own experience in deriving its chosen values for the relevant
inputs as evidenced in the remainder of this Chapter, has highlighted the speculative nature of
going a step further in order to form a considered view on the shape of the probability
distribution and measures of dispersion for each of the inputs.
Thus, the Commission remains of the view that AGLE and United Energy have downplayed the
significance of the information requirements necessary to apply the Monte Carlo method in a
robust manner.
As the Commission has also noted in its earlier discussions, it would not be correct to simply
adopt the Commission’s selected parameter inputs as the central estimates (expected values) for
these inputs, given the Commission’s view that its estimates embody a degree of conservatism. A
similar view has been expressed by the ACCC (2005), which has acknowledged the many issues
associated with the use of Monte Carlo simulation for the estimation of the WACC in the context
of the telecommunications industry, finding that it is “important that the MC analysis is done
using unbiased estimates of the WACC input parameters” (ACCC 2005, p. 62).
Further, the value of Monte Carlo analysis is proven in the fields of computational physics and in
the field of finance in (for instance) finding the arbitrage-free value of a particular derivative.
However, no evidence has been provided that market practitioners consider it appropriate or that
other regulators use the method when estimating the WACC.
Lastly, the Commission remains of the view that transparency is important in the method that is
used to estimate the WACC, and does not consider that the method proposed will improve the
level of transparency. Merely because the Monte Carlo model itself is a mechanical process does
not make the use of the model transparent as discussed above. The Commission considers that
the key inputs to the calculation would be speculative, implying that transparency in the
derivation of such inputs would be correspondingly low. In a similar vein, even if a probability
distribution could be derived robustly for the WACC, the Commission notes that its primary
objective requires it to exercise judgement on important trade offs on the basis of all of the
information available, and does not consider that it is either necessary or appropriate to reduce
this decision to an arbitrary cut off point on a probability distribution as proposed.
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The Commission’s views on this matter are indirectly supported in the Gray and Officer (2005c,
p. 7) paper on estimating the equity (market risk) premium submitted in response to the Draft
Decision by the Energy Networks Association.
There is no natural law that says returns have to be characterised or represented by any
mathematical function. This does not mean that one should not use distributions but simply
they, like many models in finance, should be used with a degree of discretion because the
distributions of stock market returns are rarely so well behaved that parameters can be
estimated from histroric returns and then used with any confidence to forecast future
returns.
In their submissions to the Draft Decision CitiPower, Powercor and United Energy also
identified approaches used in other jurisdictions to estimation the WACC. CitiPower and
Powercor highlighted the probabilistic approaches employed in Western Australia, New South
Wales and New Zealand. United Energy also considered the approach used by the Western
Australian Economic Regulation Authority (ERA) (2005) in its recent decision under the Gas
Code with regard to the Goldfields Gas Pipeline. United Energy indicated that the approach used
— where the ERA adopts a range of feasible values for the underlying cost of capital variables,
having regard to broad commercial practice and selecting a point estimate within the 90th
percentile of the range to ensure that the regulator errs on the side of investors — is favourable
approach to dealing with uncertainty.
Turning first to the decisions of IPART (2005) and the ERA (2005), the Commission notes that
those decisions have been made under the Gas Code, which differs in material respects to the
regime applicable to the current price review. In particular, those regulators interpreted the
requirements of the Gas Code as requiring the regulator to assess whether the WACC estimate as
proposed was outside of a reasonable range, rather than for the regulator to determine an
appropriate value for the WACC. The regulators, therefore, considered themselves legally
obliged to refer to a range for the WACC and its constituent inputs. Moreover, neither regulator
has used the Monte Carlo method to derive a WACC. The ERA (2005) noted that the Gas Code
requires it to form a view about the range that a reasonable person would consider the WACC to
lie within, which need not necessarily conform to the outcomes of a Monte Carlo study.
The conclusion that IPART (2005) reached with regard to the application of the Monte Carlo
method was as follows:
The Tribunal notes that Monte Carlo simulation:
•
is not widely used in financial markets to set rates of return;
•
does not remove the uncertainty arising from individual parameter estimation; and
•
while it assists in generating a range of returns, does not necessarily result in a
rate of return that meets the requirements of the Code.
Nevertheless, the Tribunal’s view is that use of a Monte Carlo simulation framework does
allow for uncertainty through the use of probability distribution for individual parameters,
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Final Decision
and thus meets the requirements of the Code in producing a range of returns that may
reflect prevailing market conditions for funds.
In practice, the aim of Monte Carlo simulation is to produce a wide range of possible
outcomes for the rate of return. The Tribunal’s view is that, in deciding where to determine
the rate of return within this range, it must be guided by the factors in sections 2.24 and
8.1 of the Code. This assessment must be made on a case by case basis. It is therefore
inconsistent in this process of assessment to determine the rate of return at the 80th
percentile or any other point in the probability distribution (IPART 2005, p. 95)
Turning next to the decision of the New Zealand Commerce Commission (NZCC) (2004, p. 7.57.6), the Commission notes that the NZCC concluded that while “the Monte Carlo approach
could potentially provide useful insights into the volatility of key outputs” it considered that “the
appropriate approach was to refine the existing cost benefit model” (NZCC 2005). In its
assessment of the Monte Carlo approach the NZCC was concerned with data quality and
reliability, transparency of the modelling process and the extent to which additional information
would be required to assess its application. One of the biggest criticisms made by the NZCC was
the lack of time available to fully consider the merits and problems associated with a Monte
Carlo approach.
However, it should be noted that explicit price regulation of utilities in New Zealand is a
relatively new phenomenon. When considering the applicability of a Monte Carlo approach to a
regulatory environment, the Commission would consider it more informative to consider the
approaches taken in jurisdictions that have substantial experience in regulating utilities, such as
the US and UK, rather than those for whom explicit price regulation is new. The Commission is
unaware that Monte Carlo analysis like that proposed by AGLE has become a standard and
accepted tool in setting regulatory returns in mature regulatory environments.
The Commission does not accept that a probabilistic approach to establishing a range for each
parameter when estimating the WACC, similar to that implemented in the Gas Code, can provide
greater certainty than the current approach offers. As with the application of a Monte Carlo
approach, estimates of the WACC inputs remain reliant on the application of judgement to a
number of different sources of information and estimation methodologies.
On the basis of the concerns articulated above, the Commission has continued to apply the
approach it has adopted in previous price reviews regarding the estimation of inputs when
determining the WACC, which is to exercise judgement while taking into account all relevant
information.
9.2.2 Estimating the after-tax WACC
In this section, the Commission sets out its reasons and analysis of each of the input parameters
used to determine the WACC. These parameters include:
•
real risk-free rate of return (Rf)
•
equity beta (βe)
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•
equity (market risk) premium (Rm – Rf)
•
debt premium (Rd) and debt raising fees
•
equity raising costs
•
relative risk of the rural distributors
The change in the WACC from that used in the last price review is due principally to the decline
in long term real interest rates which, for ten year CPI-linked Commonwealth government bonds
have declined from 3.50 per cent to 2.64 per cent.95 A further minor adjustment has been made to
the allowance for the cost of debt (a reduction in the debt margin following market movements,
but mostly offset by recognition of debt transaction costs that were not included in the last
review).
The distributors’ October 2004 proposals on the WACC and the various parameters that input
into its determination are set out in Table 9.2, along with the WACC and parameters used in the
Final Determination for the 2001 Electricity Distribution Price Review. During the course of the
price review, the distributors resubmitted some of the parameters. These latest submitted
numbers are discussed below where relevant.
Table 9.2:
Weighted average cost of capital and input parameters, distributor proposals
and 2001-05 price review
a
2001-05
review
AGLE
CitiPower
Powercor
SP AusNet
United
Risk free rate (real) Rf
3.50%
2.79%
2.80%
2.80%
2.80%
2.80%
Rural risk adjustment
—
—
—
0.50
—
—
1.51–1.71%
1.65–1.85%
1.65–1.85%
1.51–1.71%
1.51–1.71%
1.67%
1.72%
1.72%
1.71%
1.60%
6.00-7.80
6.00-8.00%
6.00-8.00%
6.00-8.00%
6.00-8.00%
7.30%
6.94%
6.94%
7.00%
7.30%
Debt premium (Rd)
— Range
— Point estimate
1.50%
Equity (market risk)
premium (Rm-Rf)
— Range
— Point estimate
6.00%
(continued next page)
95
For the purposes of this Final Decision, the period that interest rates were measured was over the 20 trading days to 31 July
2005. For a discussion on why this period has changed refer to the section on the risk-free rate.
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Table 9.2:
Weighted average cost of capital and input parameters, distributor proposals
and 2001-05 price review
2001-05
review
a
AGLE
CitiPower
Powercor
SP AusNet
United
0.90-1.00
1.00-1.10
1.00-1.10
1.00-1.10
1.00
1.00
1.07
1.075
1.04
1.00
0.00-0.50
0.00-0.50
0-0.50
Equity beta
— Range
— Point estimate
1.00
Franking credit value
— Range
0.50
0.30
0.50
0.50
0.30
0.30
Gearing (debt/assets)
60.00%
60.00%
60.00%
60.00%
60.00%
60.00%
Inflation
2.60%
2.56%
2.50%
2.50%
2.56%
2.56%
‘Vanilla’ after-tax
WACC (real)
6.80%
6.70%
6.80%
7.30%b
6.70%c
6.70%
— Point estimate
a
Formerly TXU b Powercor proposed that a rural risk adjustment (represented separately here) be added to the risk
free rate that, when removed, provides a real vanilla WACC of 6.80 per cent. c Excludes a proposed adjustment for
rural risk. A point estimate of a proposed adjustment for rural risk was not provided.
Real risk-free rate of return (Rf)
Where the real cost of capital is used to determine regulated charges, an estimate of the real riskfree rate of return is required for the risk free element of the WACC. In principle, the risk-free
benchmark in the CAPM should reflect the yield on a risk-free instrument. The yield on
government securities is typically used as a proxy.
In its previous reviews, the Commission has used a recent average (20 days) of the yield on
Commonwealth Government inflation-indexed bonds with a term to maturity of 10 years to
obtain a direct estimate of the real risk free rate of return. The indicative closing rates published
by the Reserve Bank of Australia have been used as the data source. The Commission has noted
previously that the use of inflation-indexed bonds appropriately utilises the latest market
evidence and avoids the need for an independent assumption about future inflation. The use of
market evidence is also objective and capable of being replicated across decisions and industries,
and so reduces uncertainty associated with the regulatory process.
Since the Commission first considered this matter in 1998, the use of a recent average of yields
on inflation-indexed bonds with a remaining term of 10 years has become reasonably standard
practice across all of Australian energy regulators and was adopted by all of the distributors to
derive their risk free rate estimates in their price-service proposals.
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Subsequent to the submission of their price-service proposals, AGLE and United Energy have
noted concern with this approach. For example, AGLE (2005b, p. 24) stated that:
… there are likely to be inadequacies in the use of the index-linked Commonwealth bonds
as the basis for estimating the true risk-free rate.
AGLE and United Energy highlighted that, as evidence of this, regulators in the UK have not
relied solely on current market rates or observed debt margins to estimate the risk-free rate, but
instead have adjusted the risk-free rate where market rates are not expected to prevail.
In their submissions to the Draft Decision, CitiPower, Powercor and United Energy all restated
their concern that current yields on 10-year Treasury Indexed Bonds are at an histroric low and
called on the Commission to consider that it would be prudent and reasonable to factor the risk
that the risk-free rate may return to histroric levels in the future. By way of example, Powercor
commented that:
…there is likely to be more room for the real risk free rate to move up rather than down
and therefore the distributors are likely to face a skewed real risk-free rate (Powercor
2005o, p. 4).
In the 2001 Electricity Distribution Price Review, the issue of whether prevailing interest rates
(averaged over a recent period) or some form of longer term average should be used to estimate
the cost of capital was a central issue.96
The Commission notes that real interest rates (measured in the manner described above) have
fallen since the 2001 Electricity Distribution Price Review, and that fall in the real interest rates
accounts for virtually the entire decline in the Commission’s estimate of the cost of capital since
that review. However, notwithstanding the observed decline in the real interest rates, the
Commission does not consider it appropriate to modify its approach to deriving the real risk-free
rate.
The position that the Commission adopted in that review, after considering the advice of a
number of finance experts and practitioners, was that the rates that are currently prevailing in the
market provide the best forecast of interest rates over the forthcoming period. The yields
currently observed reflect the rates at which parties are willing to buy and sell bonds and hence
already reflect the weight of market opinion about future interest rate movements (including the
histroric pattern of interest rates to the extent that history is considered relevant). Current yields
also reflected the rates at which the distributors could lock in their debt financing if so desired
and, in the Commission’s view the use of current interest rates was consistent with both theory
and the weight of market practice.
96
Office of the Regulator-General 1998, pp. 195–201. The Commission considered more specifically whether recent yields on
inflation-indexed bonds would provide the best proxy for the real risk-free rate in its subsequent review (ORG 2000a,
pp.255-260).
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The Commission also noted at the time that using objective market evidence to derive the riskfree rate would increase the predictability of this element to the derivation of costs of capital for
regulatory purposes. This was the approach applied in the Commission’s Draft Decision.
Subsequent to the release of the Commission’s Draft Decision AGLE, CitiPower, Powercor and
United Energy supplied a letter that outlined their concern regarding the measurement period
used by the Commission when determining the value of the risk-free rate.97
In this submission the distributors proposed that the 20 day period used by the Commission to
measure 10-year inflation-linked bonds (the last 20 trading days in August 2005) was a period
where the yields on inflation-indexed bonds were artificially depressed (biased downwards).
The distributors proposed that the downward bias was caused by a substantial one-off increase in
demand for inflation-indexed bonds resulting from the maturity of Treasury Indexed Bond (TIB)
402 on August 20, 2005. This reduced the number of TIB issues in the market from four to three.
The assumed underlying cause for the increase in demand for (and thus exerting downward
pressure on yields) inflation-indexed bonds during the Commission’s measurement period is that
the small number of investors that value such instruments would, on maturity of the bond,
reinvest in similar inflation-linked bonds.
In support of their view, AGLE, CitiPower, Powercor and United Energy provided additional
evidence:
•
A letter from Westpac Institutional Bank dated 29 August 2005 that supports the view that
the downward movement in yields on TIBs over the period from the 12th to the 19th
August (from 2.50 per cent to 2.305 per cent) was “nearly entirely related to investors
reinvesting the proceeds of the maturing 20/08/05 Commonwealth Indexed Bonds”.
•
A research paper from the Commonwealth Bank of Australia (CBA) that identifies the
theoretical causes of a downward bias in TIBs, undertakes a statistical analysis that claims
there has been a structural break in the yields on TIBs from 12 August 2005, and presents
an econometric model that should be used to predict the unbiased risk-free rate on
31 August 2005.
On review of this new information the Commission accepts the view, supported by empirical
evidence, that the measurement period of inflation-indexed bonds cannot be considered to
provide an unbiased estimate when determining the value of the risk-free rate of return for the
2006-10 regulatory period. The Commission accepts that the small market for inflation-linked
bonds and the theoretical and empirical evidence for a downward bias in yields represented by a
structural break could be seen to artificially depress the yields on TIBs.
Additionally, the Commission notes that real yields have declined while nominal yields have
remained relatively static implying a step increase in the forecast of inflation. In a normal
environment, where inflationary expectations rise it would be expected that real yields would
97
Powercor 2005z, Letter to S. McMahon, 30 September.
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remain static (or even rise) while nominal yields would rise. The current observed pattern would
suggest that the decline in real yields is artificial.
In order to address the downward bias the Commission considers that it is appropriate to make an
adjustment to the real risk-free rate. Subsequently, the issue to be addressed is to determine the
most appropriate approach to adjust for the bias.
In their research paper, CBA proposed the use of an econometric model to estimate the unbiased
yield as at 31 August 2005. The Commission does not consider that this is an appropriate means
to remedy for the bias. The implicit assumption underlying the CBA analysis is that past
behaviour (with respect to interest rates) is a suitable means to forecast future outcomes. This
approach is inconsistent with the view the Commission previously has expressed that the latest
market information and data provides the best forecast of future inflation (provided of course that
factors that may create a bias in the observed yields are not present).
Based on this in principle approach, the Commission’s preferred response is to identify a
measurement period that is not influenced by the downward bias, and to sample interest rates
from that period. Data after August cannot be relied upon at this time as it is unclear for how
long the downward bias may persist. On this basis, the Commission considers that it is
appropriate to use the latest market evidence available prior to the biasing event.
The Commission has therefore applied a measurement period for the calculation of the risk-free
rate as the last 20 trading days of July 2005. This amended measurement period excludes any
potential downward bias in the month of August, as identified by Westpac and CBA.
On review of the evidence, the Commission considers it appropriate that the measurement period
for the risk-free rate occur over the last 20 trading days of July 2005. This results in a risk-free
rate of 2.64 per cent.
The differing approach of the UK regulators to deriving the real risk-free rate was known at the
time the Commission first considered this matter in 1998 (for example in the Monopolies and
Mergers Commission (MMC) (1997) decision on Transco, which was referred to and drawn
upon by the Commission in its 1998 review of gas access arrangements). Such an approach was
not followed at the time (nor since by any other Australian regulators) for the reasons set out
above.
In its submission to the Draft Decision United Energy also called for the Commission to publicly
commit to using whatever rates the market determines are appropriate at the next review and to
any upward price implications this might have. While the Commission does not have the ability
to bind any future regulator, it would expect that the most recent market data will be utilised in
the assessment of an appropriate risk-free rate.
United Energy (2005n, p. 9) also claimed that:
“low” real risk free rates imply similarly “low” real growth rates (i.e. Solow’s Golden
Rule holds). Consistency would appear to demand that, if the Commission is going to take
the view that current market prices in respect of real interest rates are “right”, then it
should also apply the implications of that view to all relevant aspects of the Final
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Determination. This issue is likely to be of particular relevance when estimating economic
growth to develop electricity demand forecasts and, to some extent, growth capex
programs. In other words, the economic growth assumptions underpinning electricity
demand forecasts should reflect the economic growth assumptions underpinning the
expected cost of capital. It is not obvious that the Commission’s assumptions on economic
growth for the purposes of estimating electricity demand growth meet this criterion. If this
is the case, the Commission is in error.
The Commission does not accept that it is either necessary or appropriate to link the real risk-free
rate that is used for a regulatory period with the assumption that it may make about economy
wide growth. While the Commission is aware of the expected theoretical relationship between
real risk free rates and economic growth (known as Solow’s Golden Rule), it notes that this
relationship can only be expected to hold over the long term. For short periods — like a five year
regulatory period — other methodologies for forecasting growth would be expected to yield
superior forecasts and the Commission considers it appropriate to avail itself of such forecasts.98
In their submissions prior to the Draft Decision, the distributors also raised a number of issues
associated with the implications of the averaging period for the risk-free rate for the estimation
of debt financing costs, as well as issues associated with the inflation-linking of their revenue
streams for the adequacy of the Commission’s allowance for the cost of debt financing. Both of
these issues are addressed below in the Commission’s discussion of the cost of debt financing.
In the Draft Decision the Commission indicated that, consistent with other regulators, it would
adjust the risk-free rate to convert the semi-annual yields that are reported by the Reserve Bank
of Australia into effective annual rates as required to estimate the cost of capital. It was
recognised that while this adjustment is almost immaterial, it has been made for completeness.
CitiPower and Powercor have highlighted to the Commission that the yields on Treasury Indexed
Bonds reported by the Reserve Bank of Australia are calculated on a quarterly, rather than semiannual, basis. The Commission acknowledges this, and has adjusted for this accordingly.
For its Final Decision the Commission has used the average of the observed yields on
Commonwealth Government inflation-linked bonds over the 20 day period ending on
31 July 2005 as the real risk-free rate, which implied a rate (after adjusting to an effective annual
rate) of 2.64 per cent. Following previous practice, a linear interpolation has been used to derive
a proxy for the yield for an instrument with a remaining term of exactly 10 years.
The Commission has also followed previous practice and derived its forecast of inflation by
using the difference between the yield on nominal bonds calculated in the same manner
(compounded on a semi-annual basis) and the real yield (using the Fisher transformation), which
implied a long term inflation forecast of 2.56 per cent. It is important to note that the inflation
forecast is only used to derive the benchmark taxation liabilities for the distributors.
98
No evidence was adduced that forecasters of short term economic growth use the real risk free rate as their forecast.
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Equity beta (βe)
The equity beta reflects the level of non-diversifiable risk associated with a particular asset,
relative to the (non-diversifiable) risk associated with a well-diversified portfolio of assets.
The normal techniques for estimating equity betas require information on the economic returns
of individual assets (the sum of dividends and changes in the market value of the asset) as well as
the economic return on the well-diversified portfolio of assets, which is only available for
entities listed on a stock exchange. As the distribution activities of regulated businesses are not
separately listed on the Australian stock exchange, their equity betas cannot be estimated directly
and it is necessary to use a proxy to determine the distributors’ after-tax WACC. Even where
equity betas can be estimated for a particular entity, it is common practice to combine the equity
beta estimate with information provided by the equity beta estimates for other firms to reduce the
error associated with this variable.
The Commission has noted in previous decisions that the estimation of the equity beta for
regulated activities poses a number of challenges. There are few firms listed on the Australian
Stock Exchange (ASX) that undertake similar activities to the distributors’ regulated activities,
and so the set of empirical information (at least for Australia) is limited.
Estimating equity betas also requires a number of methodological decisions to be made, for
which there often is little theoretical guidance, which can have a substantial effect on the
resulting estimates. As discussed in detail in the following section, the emergence and then
ending of the ‘technology bubble’ in the world stock markets in recent years has been accepted
elsewhere as potentially creating a bias in equity beta estimates, reducing the usefulness of some
of the information that is available.
Inevitably, equity beta estimation requires judgement and, given the Commission’s concern for
stability and predictability in decision making, particularly judgement as to whether and to what
extent any new information would justify a change from previous decisions.
It is important to distinguish between the classes of risk that are reflected in the cost of capital
and those that are not. Much of the risk associated with returns to a particular asset can be
eliminated by capital market investors through diversification. Diversifiable risk generally arises
from events that are unique to an entity or to a small group of entities. This implies that only the
portion of risk that is associated with economy-wide events will be borne by investors and hence
reflected in the cost of capital. Non-diversifiable risk can be influenced by changes to such
factors as inflation, economic growth, tax rates, interest rates and international financial trading
shocks.
The level of gearing also affects the estimation and interpretation of equity betas. For a given
level of risk for the particular activity or project, a rise in the proportion of debt in the entity’s
financing structure will increase the level of risk borne by the equity providers. The Commission
has adopted a benchmark financing structure for the distributors of 60 per cent debt-to-assets,
and so an equity beta consistent with this level of gearing is required. The process of adjusting
asset and debt betas for gearing levels is known as de-levering and re-levering, and the formula
the Commission previously has used for this purpose is as follows:
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βa = βe
E
D
+ βd
V
V
Where βa is the asset beta (the beta for an un-geared asset), βe is the equity beta, βd is the debt
E
D
beta,
is the proportion of equity funding and
is the proportion of debt funding (gearing).
V
V
In the 2001 Electricity Distribution Price Review, a proxy equity beta of 1.0 was adopted with
reference to a deemed gearing ratio of 60 per cent debt to assets.
A dominant theme in the distributors’ price-service proposals acknowledged that there are
difficulties associated with the estimation of the equity beta. All distributors suggested that the
value of the equity beta should not be less than 1.
In support of their views, each of the distributors referred to additional material. AGLE provided
a report prepared by the Strategic Finance Group (SFG 2004a), to which CitiPower, Powercor
and SP AusNet99 also referred.100 AGLE also supplied a report prepared by KPMG (2004a) that
discussed issues associated with, and means to develop, point estimates (with reference to the
SFG report) for the WACC. SP AusNet and United Energy provided similar, but separately
prepared KPMG reports. CitiPower (2004g) and Powercor (2004g) provided their own, but
similar, analysis of cost of capital issues.
Several common themes were presented in the submissions provided by the distributors with
their original October 2004 submissions and to the Commission’s later Issues and Position
Papers:
•
Recent statistical estimates of the equity beta are “low relative to historical averages”, but
such estimates are “very imprecise” (SFG 2004a, p. 11).
•
There are commonly acknowledged issues associated with the estimation of the equity
beta, including the frequency of observations and length of the sample period, poor
statistical reliability, time variation in estimates, thin trading problems, the influence of
outliers and the potential for the recent technology ‘boom and bust’ to have created a
downward bias in equity beta.
•
Market evidence should be reviewed with caution and weight should be given to recent
regulatory decisions to provide regulatory certainty.
•
Powercor and SP AusNet also concluded that the systematic risk of the predominantly rural
distributors is higher than that of the urban distributors and, as such, the Commission
should adopt a higher equity beta. This matter is addressed separately below.
Based on the reports submitted in association with their price-service proposals, the distributors
proposed a range of 0.9 to 1.1 for the equity beta, which was argued to be consistent with
previous Australian regulatory decisions and market evidence.
99
100
Formerly TXU
United Energy refer to an earlier (2003) but similar SFG report.
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In contrast to the distributors’ views, the Energy Users Coalition of Victoria (EUCV) has
throughout the consultation process proposed that an equity beta in the range of 0.6 to 0.8 was
more appropriate for electricity distribution businesses in light of the empirical information that
both the Commission and other regulators have considered on betas for Australian and overseas
firms (EUCV 2005a, p. 23). This is a view that was supported by the Victorian Consumers’
Groups (VCG) (2005a).
For the purposes of setting regulated charges for the 2006-10 regulatory period, the Commission
in its Draft Decision had regard to:
•
market evidence on equity betas, including current market evidence as well as market
evidence that it considered at previous reviews;
•
the value that it adopted in its previous review of the price controls for the distributors;
•
the values adopted by other regulators in comparable decisions; and
•
overseas information on equity beta estimates (both current evidence and evidence from
previous periods).
On this basis, the Commission adopted an equity beta of 1 for an assumed gearing level of 60 per
cent debt to assets.
In its submission to the Commission’s Draft Decision, while AGLE did not consider the Draft
Decision conservative on this matter, it agreed that the equity beta value of 1 as proposed by the
Commission was consistent with the equity beta it had proposed in its previous submission,
based on a uniform probability distribution of 0.9 to 1.1, with a mean of 1. AGLE considered
that the value was consistent with that proposed by the SFG (2004a) paper provided with its
October price-service proposal. AGLE noted that it accepted the Commission’s view that it was
important for the beta estimate to be based upon market evidence, but highlighted that the
difficulties with interpreting such evidence means that “there will be a need for careful analysis
to derive appropriate conclusions about beta for the distribution businesses” in future reviews
(AGLE 2005, p. 82).
In their response to the Draft Decision, CitiPower and Powercor also maintained that the equity
beta benchmark should be 1 consistent with their price-service proposals of October 2004. In
further support of their view that 1 is the appropriate estimate for the equity beta, CitiPower and
Powercor provided a number of papers that had been provided by ETSA Utilities in its
Application for Review of the ESCOSA’s Electricity Distribution Price Determination (April
2005):101
•
A Gray and Officer (2005a) report on the equity beta of an electricity distribution business:
Report prepared for ETSA Utilities.
•
A NERA (2005a) report reviewing ESCOSA's decision on ETSA Utilities equity beta.
•
A Gray and Officer (2005b) report in response to the submission of the South Australian
Treasurer to ESCOSA's Electricity Price Determination.
101
ETSA Utilities, like CitiPower and Powercor, is a member of the Cheung Kong Group of companies.
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•
A NERA (2005b) report reviewing Associate Professor Lally's Critique of NERA's April
Report.
For the most part, these submissions highlighted themes or matters that the Commission itself
has noted, such as the importance of stability in the regulatory regime and the implications of
this for the relevance of ‘regulatory precedent’ when deriving WACC inputs and the potential
errors associated with the estimation of equity betas, including the potential implications of the
recent ‘boom and bust’ in technology stocks. However, that evidence along with the evidence
adduced by the Treasury provided some additional empirical information, including information
on betas for comparable US entities and estimates of betas for the Australian comparable entities
that adopt more sophisticated estimation techniques (such as eliminating outliers). These other
sources of information are discussed further below.
In its submission to the Draft Decision, United Energy supported the Commission’s use of 1 as
an appropriate estimation for the equity beta in light of “evidence of past decisions and the
position of other regulators and economic advisers” (United Energy 2005n, p. 11). In support of
its views, United Energy provides and cites a paper prepared for the Energy Networks
Association (ENA) by Gray, Hall et. al (2005).
This paper, provided to the Commission in response to the Position Paper, compared the
performance of the ‘mechanical’ equity beta estimates that are prepared by the AGSM Risk
Management Service to a number of alternative estimates for individual equity betas. These
included lengthening the returns window, the use of the ‘Blume’ adjustment, a technique for
eliminating outliers, using industry estimates rather than individual beta estimates and merely
using a beta of 1 for all firms (that is, dispensing with the CAPM). The results of this analysis, as
summarised by the authors, was to:
… suggest that a longer data period should be used, and that the estimate should be
adjusted toward unity using the Blume adjustment. In the absence of any such data, the
best estimate of the equity beta for any company is unity (Gray, Hall et al 2005, p. 41).
The joint Victorian Consumers’ Group (VCG 2005b) submission in response to the Draft
Decision expressed concern that the ESC, in adopting an equity beta of 1, “continues to set the
WACC above a level recently established by Australian regulators for electricity distribution in
other jurisdictions” (VCG 2005b, p. 26). In particular, the VCG (2005b) submission contrasts the
equity beta value applied in the Draft Decision to that used in the Commission’s Water Price
Review Final Decision and the analysis in that document that referred to an equity beta of 0.70
for the energy sector.
The VCG (2005b) submission implicitly raises two separate issues, which are, first, what the
market evidence suggests about the equity beta for regulated activities in the energy sector and,
secondly, to what extent the beta for regulated energy sector activities is likely to differ from the
beta for regulated water sector activities (and, implicitly, whether the Commission’s conclusions
in the Draft Decision are consistent with the conclusions it reached for the water businesses). The
first of these matters is the central topic of this chapter, and will not be expanded upon here.
Turning to the second of the matters, the Commission formed the view when setting regulated
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charges for the water sector that the systematic risk for regulated water sector activities is likely
to be lower than that for the energy sector. These conclusions, in turn, were based upon:
•
the Commission’s a priori belief about the likely differences in betas between the water
and energy sector;
•
estimates of the betas for water businesses in the US and UK and the observed relativities
between the betas for water businesses and energy businesses;
•
the beta values that have been adopted by Australian regulators when setting water
charges; and
•
the water businesses’ proposals, which were within the range of 0.75 and 1.00.
The Commission remains of the view that the systematic risk of the regulated activities in the
water sector is likely to be lower than that in the energy sector, and that the relativity of equity
betas adopted is appropriate.
The EUCV (2005d) also expressed concern that Australian regulators did not appear to
appropriately benchmark the returns of electricity distributors with that of the market, nor appear
to be consistent in determining “what is the correct value for equity beta” (EUCV 2005d, p. 52).
The EUCV calls on the Commission to follow the decisions of ESCOSA, IPART and the QCA
to apply a lower equity beta. Additionally, the EUCV (2005d, p. 46) state that:
The ESCOV is required by its Act to set an equity beta which replicates the local market of
like industries, international benchmarks for like industries and the recent decisions of
other Australian regulators when setting equity beta. By setting an equity beta of 1.0, the
ESCOV is failing to comply with the ESC Act and the National Electricity Rules.
As noted earlier, the Commission has considered at length the issues and difficulties associated
with deriving a proxy equity beta for the distributors’ regulated activities in its previous reviews.
Many of the views expressed in submissions — in particular, that substantial weight should be
placed upon previous regulatory decisions in light of the imprecision associated with equity beta
estimates — reflect the Commission’s own previous conclusions.
The Commission has emphasised, however, that as the cost of capital is a market-determined
parameter, it is essential that an assessment of the available market evidence is made, even if that
evidence is subsequently found wanting and therefore not accorded substantial weight. The
Commission notes that the only means through which to resolve the issue of whether the
Commission’s previous assumption of an equity beta of 1 is excessively conservative as
commented by the customer representatives is with reference to the available market evidence
but interpreted in light of the difficulties already discussed with estimating the equity beta.
In its previous reviews, the Commission has referred to the equity betas produced by the AGSM
Risk Management Service for the firms the Commission considered to be sufficiently
comparable entities.
Figure 9.1 updates the beta estimates provided in the Commission’s most recent decision
regarding the pricing of Victorian water, and also shows how the equity beta estimate derived in
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this manner would have changed over time. All of the equity beta estimates are adjusted to
reflect the target gearing level of 60 per cent debt-to-assets (all calculated using a zero debt beta).
Figure 9.1:
Average equity beta for comparable Australian entities
1.2
Equity beta (Relevered to 60 % D/A)
1
0.8
0.6
0.4
0.2
Jun-05
Mar-05
Dec-04
Jun-04
Sep-04
Mar-04
Dec-03
Sep-03
Jun-03
Mar-03
Dec-02
Jun-02
Sep-02
Mar-02
Dec-01
Sep-01
Jun-01
Mar-01
Dec-00
Sep-00
Jun-00
Mar-00
Dec-99
Sep-99
0
Note: Betas were obtained from the Risk Management Service of the Australian Graduate School of Management. The estimates
include four years of observations, or the firm’s trading history. Firms are only included where there are more than twenty
observations. Thin trading betas were used where the test for thin trading was failed at the 10 per cent level of significance.
Gearing is calculated as the average of the annual gearing levels observed over the period over which the relevant beta was
estimated. The value of equity is the firm’s market capitalisation using share price data obtained from Bloomberg. The value of
debt is taken as the book value of debt, also obtained from Bloomberg. Loan notes are treated as equity (including where the note
is interest bearing). The proxy group between September 1999 and December 1999 included AGLE and Envestra only, between
March 2000 and December 2001, it comprised AGLE, Envestra and United Energy, in March 2002 it included AGLE, Envestra,
United Energy and the Australian Pipeline Trust, between June 2002 and June 2003 it included AGL, Envestra, United Energy,
the Australian Pipeline Trust and AlintaGas, and since September 2003 it has included AGLE, Envestra, the Australian Pipeline
Trust, AlintaGas and GasNet.
There have been at least two concerns explicitly or implicitly raised in submissions (and
acknowledged by the Commission in its Draft Decision) with the conclusions that can be drawn
from the equity beta estimates presented above.
First, a number of submissions raised the concern that equity beta estimates for utility stocks
measured over the period of the technology ‘boom and bust’ are likely to be downward biased.
The rationale for this bias is that, while technology stocks rose during the stock market ‘bubble’
and then slumped during the subsequent correction, safe stocks like utilities moved in the
opposite direction (and, as such, opposite to the market as a whole). To the extent that the
technology bubble is not expected to repeat periodically, the measured covariance between
utility stocks and the market would understate the expected covariance (and hence, expected
equity beta).
Both ESCOSA (2005a) and the QCA (2005) have accepted that the technology ‘boom and bust’
is likely to have led to a downward bias in measured equity betas over that period. The behaviour
of the equity betas for the Australian firms, as set out above, appears consistent with the
anticipated effect of the technology ‘boom and bust’. In addition, ESCOSA (2005a) also
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Essential Services Commission, Victoria
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investigated the behaviour of the betas for US electricity distribution businesses over this period.
Analysis of equity betas of firms in the US has the advantage of being able to make use of a
much larger set of listed entities, as well as information over a longer period (of the Australian
comparable firms used to derive the average equity beta above, only AGLE existed prior to
August 1997). The information presented by ESCOSA (2005) is extended in Figure 9.2.
Figure 9.2:
Average equity beta for US electricity distribution businesses
0.9
0.8
0.7
Average re-levered beta
0.6
0.5
0.4
0.3
0.2
0.1
Jul-05
Jul-04
Jan-05
Jul-03
Jan-04
Jul-02
Jan-03
Jul-01
Jan-02
Jul-00
Jan-01
Jul-99
Jan-00
Jul-98
Jan-99
Jul-97
Jan-98
Jul-96
Jan-97
Jul-95
Jan-96
Jul-94
Jan-95
Jul-93
Jan-94
Jul-92
Jan-93
-0.1
Jan-92
0.0
-0.2
Month ending
Note: The chart reflects the average equity beta (re-levered for gearing of 60 per cent debt-to-assets) across a group of 12 US
electricity distributors, measured using monthly return observations.
Figure 9.2 shows that, while the re-levered equity beta averaged across the sample of firms
fluctuated within a band of about 0.6 to 0.8 over the period prior to the technology ‘boom and
bust’, the equity beta estimates dropped substantially after about mid 1998, which is consistent
with the proposition that the ‘boom and bust’ depressed measured equity betas.
The Commission accepts that the recent technology ‘boom and bust’ is likely to have had a
depressing impact on measured equity betas over the relevant period, and which is likely to lead
to an understatement of the expected (forward-looking) equity beta where observations over the
‘boom and bust’ period are included in the sample.
Second, the papers by Gray and Officer (2004) and the Energy Networks Association (Gray, Hall
et al, 2005) also raise a number of additional empirical issues associated with the estimation of
equity betas, as described above. The implication of both the Gray and Officer (2004) and
Electricity Networks Association (Gray, Hall et al 2005) papers is that more sophisticated
techniques may produce better estimates of equity betas from the available empirical data than
produced by the public beta services (such as the AGSM Risk Management Service), in
particular, to address particular statistical issues associated with the estimation of betas. Gray and
Officer (2004) illustrate the potential differences in the equity beta estimates from the use of the
more sophisticated methods, and the Electricity Networks Association (Gray, Hall et al 2005)
report presents an analysis of the difference in the accuracy of the different equity beta
estimation methods.
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As noted above, Gray and Officer (2005a) then derived equity beta estimates for the set of
Australian comparable entities listed above that attempted to remove some of the potential
problems, including to:
•
eliminate data for the technology stock ‘boom and bust’ period; and
•
eliminate observations considered to be outliers.
The Commission notes, however, that ESCOSA had specific concerns with the Gray and Officer
(2005a) equity beta estimates, which were that:
•
the results were based on consideration of only a limited number of comparable firms;
•
the Blume adjustment was applied to the raw beta estimates, which it considered to be
inappropriate; and
•
on the advice of Professor Lally, only the first column of Gray and Officer’s results should
be considered (the more narrow definition of outliers to data points with residual of greater
than 2 standard deviations) (ESCOSA 2005b).
After making these adjustments, ESCOSA accepted that the more sophisticated methods
employed by Gray and Officer (2005a) provided support for an equity beta (for a gearing level of
60 per cent debt to assets) of approximately 0.82. The Commission shares ESCOSA’s concerns,
most notably on the appropriateness of the Blume adjustment, which the Commission previously
has considered at length (for instance, see ESC 2002) and that a more cautious definition of
outliers should be employed (in light of Professor Lally’s comments).
As noted in the Draft Decision the Commission welcomes the additional research being
undertaken into the estimation of equity betas present in both reports, and encourages further
research on improvements to the estimation of equity betas. To a large extent, the analysis
presented in these reports underscores the caution the Commission has exercised in all of its
previous price reviews when interpreting empirical information on equity betas.
The Commission made several remarks in the Draft Decision that it considers remain relevant.
First, when considering the applicability of the results in the report for the Energy Networks
Association (Gray, Hall et al 2005), it needs to be understood that the Commission’s approach in
previous decisions has not been merely to take an equity beta estimate for a single firm, or even
the average of the equity beta estimates for a group of firms, and to apply that estimate
uncritically. Rather, the Commission has also had regard to estimates of equity betas for relevant
entities in other countries, the equity beta estimates used by regulators in other countries (to the
extent that the CAPM is used), previous decisions by Australian regulators and the qualitative
arguments presented, thus augmenting the information available from Australian empirical
evidence. The Commission would expect to continue to place weight on all of the available
information when deriving the equity beta for regulated entities.
Second, an implication of each report is that regulators should have regard to estimates of equity
betas that have been estimated using more sophisticated techniques than adopted by the public
beta services (such as the AGSM Risk Management Service), with the latter referred to in a
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number of places as ‘mechanical’. Gray and Officer’s further work for ETSA Utilities provides
an application of such a more sophisticated approach.
While the Commission accepts that more sophisticated estimation techniques may produce better
equity beta estimates, it notes that one of the main justifications for using public beta estimates is
because the use of such sources promotes transparency and objectivity in decision making.
Accordingly, an important prerequisite for placing substantial weight upon more sophisticated
techniques is that the Commission and other interested parties are provided with sufficient
opportunity to understand, replicate and examine the robustness of the results presented.
The Commission notes that the results presented by Gray and Officer (2005a) have not been
subject to substantial debate as yet (and were not even produced for review of the Victorian
distributors), and that the use of such sophisticated techniques may not be consistent with the
evidence on standard market practice that the distributors themselves have presented (for
example, see Truong et al 2005).
That said, the Commission considers that the techniques adopted are likely to represent an
advance on previous techniques (notwithstanding that it may not be consistent with standard
market practice), and that it is appropriate to place weight on the equity beta estimates presented
(subject to the adjustments considered appropriate by ESCOSA).
The results of the Gray and Officer (2005a, pp.36, 39) analysis are presented with the ECOSA
(2005b, p.49) adjusted figures (based on the advice of Professor Lally) in Table 9.3.
Table 9.3:
Re-levered Beta estimates after removal of technology bubble and outliers:
Officer and Gray (2005) and ESCOSA adjusted (2005a)
Outlier Removal Criteria
(standard errors)
2.0
2.0
Gray and Officer Blume beta
60%a
ESCOSA recalculation of raw beta
60%
0.80
1.46
0.95
0.77
1.00
0.39
1.35
0.74
0.81
0.83
1.06
0.83
0.95
0.78
0.90
0.84
1.23
1.23
1.04
1.04
3.5 Years: 7/2001 – 12/2004
AGL
Alinta
APT
Envestra
Mean
4 Years: 1/1998 – 6/1990,
7/2001 – 12/2004
AGL
Envestra
Mean
5 Years: 1/1997 – 6/1998,
7/2001 – 12/2004
AGL
Mean
a
AGSM monthly data file, SFG regression analysis, gearing estimates from ESCOSA’s Draft Determination Table
10.2, debt beta of 0.2 for Envestra and zero for other firms, consistent with the procedure used in ESCOSA’s Draft
Determination p.168, equity betas are re-levered to 60 per cent gearing, outliers and the technology bubble are
eliminated. Raw beta estimates are Blume-adjusted before being re-levered.
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As discussed above, the material presented to ESCOSA also provided further evidence of betas
for US firms (see Table 9.4).
Table 9.4:
Gray and Officer (2004) Beta Estimates from Comparable US Firms
Industry Name
Electric Utilities
(Central)
Electric Utilities
(East)
Electric Utilities
(West)
Natural Gas
Distribution
Natural Gas
Mean
Number of
Firms
Mean Equity
Beta
Mean
Leverage
Equity Beta
Relevered
with Bd = 0
25
0.82
52%
0.98
30
0.76
49%
0.96
15
0.82
48%
1.06
31
0.65
46%
0.88
38
0.87
0.78
42%
1.25
1.03
Source: Gray and Officer (2004, p. 18). The table contains beta estimates for comparable U.S. firms computed by
Value Line, http://pages.stern.nyu.edu/~adamodar/pc/datasets/betas.xls. The table also presents equity beta estimates
after relevering to the benchmark assumption of 60 per cent debt financing. Mean leverage values have been
rounded.
In its assessment of the Officer and Gray (2004) data ESCOSA (2005a, p.137) noted that:
Different sources can provide different outcomes since the outcomes are dependent on a
number of factors such as the period covered by the data, the companies that are included
in the sample, the index used as the independent variable, and whether any adjustments
(such as the ‘Blume’ adjustment) have been made.
In particular the use of the Value Line data was called into question as this data “is known to
adopt the ‘Blume’ adjustment”, which is considered inappropriate for the regulatory context. In
addition, ESCOSA (2005a, p. 137) observed that:
Another reason why the ValueLine Betas are inappropriate is that a number of companies
that make up the “Electric Utilities” are very diverse and may influence betas materially.
For example, a number of companies that predominantly generate electricity (rather then
distribute) are included in the list.
Lally (2005) also developed estimates of the asset beta of US firms to expand the set of
comparators for the purposes of the ESCOSA (2005a) decision (see Table 9.5).
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Table 9.5:
Lally (2005) asset beta estimates, with equity beta estimates
Source
Data
Period
Value Line
1999 –
2003
1994 –
1998
2002 –
2003
1990 –
1994
1999 –
2003
1993 –
1997
1999 –
2003
1994 –
1998
1989 –
1993
Value Line
Bloomberg
Alexander
Ibbotson
Ibbotson
S&P
S&P
S&P
Median
Number of
firms in
sample
Electricity
Utilities Asset
Beta
Electricity
Utilities
Equity Beta
Gas
Asset
Beta
Gas
Equity
Beta
Overall
Asset
Beta
Overall
Equity
Beta
83
0.35
0.88
0.17
0.43
0.29
0.73
147
0.26
0.65
0.26
0.65
0.26
0.65
93
0.27
0.68
0.20
0.50
0.25
0.63
35
0.33
0.83
0.22
0.55
0.27
0.68
50
0.12
0.30
0.06
0.15
0.11
0.28
108
0.32
0.80
0.33
0.83
0.32
0.80
80
0.18
0.45
0.19
0.48
0.19
0.48
73
0.19
0.48
0.32
0.80
0.26
0.65
65
0.34
0.85
0.29
0.73
0.32
0.80
0.27
0.68
0.22
0.55
0.26
0.65
Source: Lally (2005, p. 14). The Commission has generated equity betas consistent with 60 per cent gearing.
The Lally (2005) analysis estimated asset beta of 0.30 resulted in an equity beta of 0.75,
consistent with a gearing level of 60 per cent. The Commission has obtained its own estimates of
beta for a group of specific firms, which it considers preferable to the Gray and Officer or Lally
figures.
However, the Commission notes that the Lally (2005) numbers are close to the Commission’s
own estimates of beta for US firms.
As discussed already, in addition to the empirical evidence on equity betas, the Commission
considers it important to have regard to the decisions of other Australian regulators in relevant
matters. Table 9.6 sets out the decisions that the Commission has had regard to.
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Table 9.6:
Regulatory decisions on the equity beta
Regulatory decision
Adjusted equity beta
(60 per cent debt to regulatory assets)a
2001 ACCC Powerlink Transmission Decision
2001 ESC Electricity Distribution Price Review
2002 ACCC ElectraNet Transmission Decision
2002 ACCC SPI PowerNet Transmission Decision
2002 ACCC Victoria Gas Transmission Final Decision
2003 ACCC Moomba to Adelaide Pipeline Gas Transmission
Final Decision
2003 ESC Gas Access Arrangements
2004 ACCC Transend Transmission Decision
2004 ICRC ActewAGL Electricity Distribution Final Decision
2004 IPART Electricity Distribution Final Decision
2005 ESCOSA Electricity Distribution Redetermination
2005 QCA Electricity Distribution Final Decision
2005 IPART Revised Access Arrangement for AGL Gas
Networks Final Decision
a
1.0
1.0
1.0
1.0
0.98
1.16
1.0
1.0
0.9
0.78 – 1.11
0.90
0.90
0.80 – 1.00
Adjusted for consistency with the Commission’s assumptions about gearing.
It is clear from Table 9.6 that there has been substantial convergence in Australian regulatory
decisions on the equity beta of regulated gas and electricity infrastructure at around 1, which the
Commission has adopted in its two most recent energy price reviews.
Previously, the Commission has undertaken extensive analysis into the appropriate equity beta
for a regulated electricity distribution business, and concluded that 1 is appropriate, having
regard to the available market evidence, as well as other important matters, like the importance
of creating a stable, predictable and replicable regulatory regime.
The equity beta estimates have fallen substantially compared to the time of the last review.
However, the Commission considers that the effects of the recent ‘boom and bust’ in technologyrelated stocks (as illustrated by the observed substantial reduction in equity betas for electricity
distributors in the US) provides a plausible reason for placing little weight on the recent
movements. The Commission also notes that the more sophisticated estimation techniques for
equity betas that were provided to the current review also reinforce that the current movements
in observed equity betas is likely to be misleading and that the market evidence may support an
equity beta of 1.
In view of the problems with interpreting recent market evidence and the Commission’s view of
the importance of creating a stable, predictable and replicable regulatory regime, and having
regard to the results of more sophisticated estimation methods, the Commission has again
adopted an equity beta of 1 to estimate the cost of capital associated with the distributors’
regulated activities. That said the Commission remains of the view it has expressed in previous
decisions that it would envisage placing more weight on market evidence on equity betas as the
problems with the quality of data are remedied, the extent of information available improves and
techniques for interpreting that evidence are refined.
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The Commission has adopted an equity beta of 1 for an assumed gearing level of 60 per cent
debt to assets.
Equity (market risk) premium (Rm – Rf)
As measured and applied in practice, the equity (or market risk) premium that is used in the
CAPM is the premium over and above the risk-free rate of return that investors expect to earn on
a well diversified portfolio of assets. In its previous decisions, the Commission has noted that
there are a number of methods available to estimate the (expected) equity premium.
In its previous reviews, the Commission has formed the view that it is appropriate to consider a
number of different sources of evidence when deriving a value for the equity (market risk)
premium. In particular, it has had regard to at least three different techniques for estimating the
equity premium. The first is to use averages of the historically observed premium, the second is
to attempt to estimate the equity (market risk) premium from current share prices, assumptions
about investors’ expected growth in dividends and a model for linking the variables (ex ante
methods). A third method is to survey market practitioners or other experts directly. There are
also variants to the methods.
The Commission has also had regard to the extensive debate amongst practitioners and
academics about whether there may be a priori reasons for the premium to have changed over
time.
In previous decisions, the Commission has discussed in some detail the potential shortcomings of
each of the different equity (market risk) premium estimation methods. It has noted that both the
choice of method and the detailed approach to applying any particular method are subject to
extensive debate amongst finance theorists and practitioners, and poor statistical precision is a
characteristic of all of the methods.
The estimates of the equity (market risk) premium that were provided by the distributors in their
price-service proposals lie within the range from 6 per cent to 8 per cent (see Table 9.2). A main
source of evidence presented by AGLE, SP AusNet and United Energy for the range was a report
from KPMG (and similar evidence in the case of CitiPower and Powercor) that summarised a
number of estimates of the historical Australian equity (market risk) premium. KPMG (2004a)
also commented that other methodologies, such as surveys or the ex-ante approach could not be
relied on with confidence.
In their price-service proposals distributors also commented that the equity (market risk)
premium applied may have been significantly understated for the last 14 years as the
measurements have, in their opinion, not taken the effect of dividend imputation (franking
credits) into account. Consequently, the distributors maintained that their proposed range of
between 6 per cent and 8 per cent for the equity (market risk) premium was conservative.
CitiPower and Powercor stated that if the value of franking credits was not reduced, the equity
(market risk) premium should be increased.
Capital Research (2005) and the South Australian Centre for Economic Studies (SACES) (2005)
provided reports that questioned the distributors’ views about the equity (market risk) premium.
Both of the papers contained sophisticated methods for analysing past returns in order to derive
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the best estimate of the expected future equity premium from these returns. Capital Research
(2005) and the SACES (2005) indicated that measuring the equity (market risk) premium over
the longest period using an arithmetic average would overstate the expected equity premium
because:
•
more weight should be placed upon more recent observations as the market has changed
substantially (both Capital Research and SACES);
•
returns are more appropriately measured as 10–year holding period returns (Capital
Research);
•
geometric means should be used to interpret past data and then adjusted to an equivalent
arithmetic mean in order to avoid bias (both Capital Research and SACES); and
•
unexpected asset price inflation over the averaging period has led to an upward bias in the
estimate of the equity premium (both Capital Research and SACES).
Capital Research (2005) suggested that the use of a 10-year holding period, geometric mean
(then adjusted to an arithmetic mean) and removing the bias caused by unexpected asset price
inflation (as preferred) delivers an estimate of the expected equity (market risk) premium of
approximately 6 per cent. Placing more weight upon the more recent market evidence (as
recommended) results in an estimate of the equity (market risk) premium of 4.5 per cent.
The SACES (2005) report found that placing sole weight on the last 30 years would imply an
equity (market risk) premium of 5 per cent after the removal of biases (or about 5.6 per cent once
the non-cash value of franking credits are included). Its other analysis suggested that the true
range probably extends below this, between 5.1 per cent and 5.6 per cent (after adding on
0.6 percentage points for franking credits).
In the Draft Decision, the Commission noted that (with specific reference to the distributors’
proposals) inferences from historical returns inevitably rely upon the same set of data.
Consequently the differences in the estimated equity (market risk) premium must reflect
differences in the time period of observations, the averaging technique and any adjustments that
have been made to the raw estimate. The upper limit of the distributors’ range would appear to
reflect an adjusted average over the period between 1974 and 1995, or the average between 1882
and 1987 (SFG 2004a, p. 26). It was noted that, as it is now 2005, neither of these time periods
have any obvious justification. Rather than simply quoting a ‘range’ for the advice provided by
history, the Commission considered it more appropriate to evaluate the different issues or
choices available when estimating the equity (market risk) premium, and then to consider the
different estimates of the equity (market risk) premium that result from each of the feasible
choices.
Turning to the Capital Research (2005) and SACES (2005) papers, the Commission noted that
the new material presented suggested that the Commission’s previous view about the equity
(market risk) premium of 6 per cent may be consistent with a more sophisticated interpretation of
the long term historical evidence. In particular, that the material suggested that there are reasons
to believe that the long term average may overstate the expected equity (market risk) premium
(even on the assumption that the expected equity (market risk) premium has remained the same
throughout history).
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The Commission adopted an equity (market risk) premium of 6 per cent in the Draft Decision,
having regard to a range of information (much of which is summarised again below), including
the new material presented by Capital Research (2005) and SACES (2005), information on the
historical premium, other sources of information (including survey information and evidence the
Commission previously has examined on the ex ante premium) and the Commission’s and other
regulators’ previous findings.
In their response to the Draft Decision, the distributors maintained that the equity (market risk)
premium should be at least 6 per cent, consistent with the views expressed in their price-service
proposals.
AGLE and United Energy again commented that an equity (market risk) premium of 6 per cent
to 8 per cent be applied for the 2006-10 period as they maintain the view that this is a value
consistent with reference to the long term historical average. AGLE and United Energy were also
concerned that the equity (market risk) premium estimate should be represented as a range,
established with reference to a formalised estimation methodology based on a Monte Carlo
approach. The Commission has addressed this in the discussion above.
United Energy also questioned the merit of relying upon methodologies other than long term
averages to establish an estimate of the equity (market risk) premium, such as surveys of market
experts, economic models, inter-country comparisons and historical averages. United Energy
was also concerned that the evidence that the Commission had relied upon to establish its value
for the equity (market risk) premium was dated.
The distributors jointly presented or commissioned several pieces of research relevant to
determining the value that is to be adopted for the market risk premium. These pieces of research
were:
•
a report by Strategic Finance Group Consulting (SFG, 2005b) exploring the relationship
between franking credits and the market risk premium;
•
a report Gray and Officer (2005) which was commissioned to review and critique the
material provided by Capital Research (2005);
•
a report by SACES (2005) which was commissioned by the ENA; and
•
a report by KPMG (2005c) summarising the assumptions that independent expert
valuations have adopted regarding the market risk premium and ‘gamma’ in recent years
(that is, in the situations where the discounted cash flow methodology is employed).
In addition, the material provided by the distributors also referred to a recent survey of
Australian firms regarding the assumptions those firms adopted when assessing the commercial
viability of new projects.
Turning to the report by SFG (2005b), the key conclusion of this report is that the Commission’s
assumptions of an equity (market risk) premium of 6 per cent and a ‘gamma’ value of 0.50 are
internally inconsistent. It also commented in the report that the Commission has ignored the
value of franking credits when deriving an equity (market risk) premium in its previous review.
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The Commission’s analysis of this report is set out in more detail in the discussion on franking
credits (see the Franking Credits section), but the main conclusions were as follows.
•
The Commission rejects the comment that it has ignored the value of franking credits in
previous review. Rather the Commission has been careful to add back the non cash value
of franking credits where appropriate. By way of example, in the Commission’s last major
energy review, the formula employed was set out,102 an explicit adjustment was made to the
long term average equity return that was reported,103 an explicit adjustment was made to the
equity premium that Mercer identified as its preferred assumption,104 and an explicit
adjustment was made for the credits when interpreting the survey evidence.105
•
The mathematical formulae adopted by SFG (2005b) are identical to those adopted by the
Commission, which should be expected as all reconcile to formulae published by Officer
(1994) and Lally (2000).
•
However, inputs adopted by SFG (2005b) in its calculations are flawed, being assumed
rather than measured, and generate materially misleading results.
•
In any event, the required adjustment to the equity (market risk) premium will depend upon
how it is derived. For estimates based upon historical returns, an adjustment need only be
made for the period since the introduction of dividend imputation, which implies that the
adjustment to the long term average is small.
The non cash value of franking credits has been added to the estimates of the equity (market risk)
premium in the values reported below.
Turning to the report by Gray and Officer (2005), the key conclusions of the report are as
follows:
•
The average premium to equities measured over the last 30 years, 50 years, 75 years,
100 years and 120 years all exceed 6 per cent (these figures are set out in Table 9.7).
•
Some of the statistical techniques that are proposed in the Capital Research (2005) and
SACES (2005) papers for the measurement of the equity (market risk) premium are
considered inferior to the simple mean estimate. However, they find that the different
techniques adopted (namely, the use of 10 year holding period returns by Capital Research
(2005) and a filtering approach and more frequent data used by SACES (2005)) both
generate estimates of the equity (market risk) premium approximately equal to (or in
excess of) 6 per cent.
•
The main differences between the results presented by Capital Research (2005) and
SACES (2005) arise from adjustments that were made to the raw estimates, namely to
remove what was considered an upward bias in the estimate of the expected premium that
would result from the use of actual returns (rise in the price earnings ratio in the case of
Capital Research (2005), and the effect of the fall in interest rates and dividend imputation
102
103
104
105
ESC 2002, p.398.
ESC 2002, p.328.
ESC 2002, p.334.
ESC 2002, p.340.
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in the case of SACES (2005)). Gray and Officer (2005) questioned all of these adjustments
on the basis that they were not supported by strong theoretical or empirical justification.
The estimates of the equity (market risk) premium that Gray and Officer (2005) produced, the
results of Capital Research (2005) and SACES (2005) as updated by Gray and Officer (2005) but
with the adjustments excluded and the averages the Commission previously reported (but
updated) are set out in Table 9.7.
Table 9.7:
Average observed excess market returns
Length of
period
Years
Mean excess
return
Gamma increment
(historic average)
Gamma adjusted
mean excess return
30
1975 – 2004
7.70%
0.65
8.34%
a
1970 – 2004
4.04%
0.55
4.59%
a
45
1960 – 2004
5.27%
0.43
5.71%
50
1955 – 2004
6.43%
0.39
6.82%
a
55
1950 – 2004
6.77%
0.35
7.12%
75
1930 – 2004
6.58%
0.26
6.84%
100
1905 – 2004
7.15%
0.19
7.34%
a
105
1900 – 2004
7.26
0.18
7.44%
120
1885 – 2004
7.17%
0.16
7.33%
35
a
Commission calculated. These numbers update the mean excess returns for historical periods with different starting
points than were previously published by the Commission (ESC 2002a)
Turning to the adjustments proposed by Capital Research (2005) and SACES (2005), the
Commission does not accept the argument of Gray and Officer (2005) that such adjustments
should be ruled out, but rather accepts that this is an area where experts in the area may disagree.
The Commission has substantial sympathy with the view of Gray and Officer (2005) that the
interpretation of empirical evidence (including any adjustments to raw data or estimates) should
have strong theoretical and empirical justification.
However, the Commission also notes that the proposition at the heart of the Capital Research
(2005) and SACES (2005) material has been common to other independent, credible pieces of
research. The proposition is that the actual historical returns to equity may include substantial
unexpected capital gains, which means that actual historical returns may have exceeded the
expected returns over the period, which in turn implies that actual historical returns may exceed
expected future returns, even if expected returns have not changed.
By way of example, this proposition sits at the centre of the series of estimates of the US equity
(market risk) premium that the Commission previously has considered and labelled as
‘alternative estimates of the historically expected returns’, which includes work by very eminent
experts in the field of finance.106 Therefore, the Commission considers that the adjustments
106
ESC 2002, pp. 331-333. See McGrattan, E., Prescott, E., Taxes, Regulations and Asset Prices, NBER working paper no.
8623, 2001; Fama, E. and K. French, The Equity Premium, The Journal of Finance, Vol LVII, no. 2, 2002, p.638;
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proposed by Capital Research (2005) and SACES (2005) should be taken into account, and note
that these adjustments would reduce the market risk premium measured over a 30 year period by
approximately 150 basis points, but proportionately less over longer periods. The information
that the Commission has taken into account in this regard is set out in Table 9.8.
Table 9.8:
Australian and US estimates of the equity (market risk) premium
Study
Period
Actual excess
returns
Adjusted excess
returns
1875 – 2005
7.0%
5.5%
1960 – 2005
5.6%
4.5%
1872 – 2000
5.6%
4.4% (div. growth)
1951 – 2000
7.4%
3.8% (div. growth)
1951 - 2000
7.4%
4.8% (div. growth)
Australian estimates
Capital Research (2005)
US estimates
Fama and French (2002)
Source: Fama, E. and K. French, 2002, ‘The Equity Premium’, The Journal of Finance, Vol LVII, no. 2, p. 641,
Table 1 and pp 654-655. The estimates are arithmetic averages of historical expected stock yields. The Fama and
French results report the premium against (6 month) bills. The Capital Research estimates adjust the actual excess
return for both the change in expected future volatility compared to the past and to remove the effect of the rise in
the price earnings ratio.
Turning to the other evidence that was provided on the assumptions of market practitioners, the
reports by KPMG (2005c) and Truong et al (2005) indicate that in the application of the CAPM
the majority of practitioners use 6 per cent as the equity ‘market risk’ premium. The majority of
such decisions were made on the basis of precedent or established standards. In interpreting the
survey information the Commission notes that the estimates provided by KPMG (2005c) and
Truong et al (2005) need to be adjusted for the value of franking credits.
The Commission has considered at length the issues associated with estimating the equity
(market risk) premium at its previous reviews, the different estimation methodologies and the
advantages and disadvantages of each. In particular the Commission has reviewed other evidence
on market practitioners such as equity analysts and asset allocation consultants. For instance, in
its 2002 Gas Decision, the Commission took into account work undertaken by Mercer
Investment Consulting, a number of US surveys, and a Jardine Fleming Capital Markets Survey
that covered 61 respondents in Australia (of which 35 were non-academics).
The Commission also took account of survey evidence from the US, where more extensive
surveys of market practitioners have been taken. The Commission considers it appropriate to
continue to take account of this information. The evidence from practitioner surveys the
Commission has taken into account in the current review is set out in Table 9.9.
Jagannathan, R, E. McGrattan and A. Scherbina, ‘The Declining U.S Equity Premium’, Federal Reserve Bank of
Minneapolis Quarterly Review, vol 24, no 4.
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Final Decision
Table 9.9:
Study
Practitioner survey estimates of the equity (market risk) premium
Period
Market
Practitioner
Expected
mean excess
return
(average)
Increment for
imputation
credits
Gamma adjusted
expected mean
excess return
5.94%
0.82%
6.76%
6.00% - 8.00%
0.82%
6.82% - 8.82%
Australian
surveys
Truong et al
2004
KPMG
2000 –
2004
Jardine
Fleming
2001
Total
0.82%
Academics
4.73%
0.82%
5.55%
Brokers
4.92%
0.82%
5.74%
Asset
consultants/trustees
4.50%
0.82%
5.32%
Corporate managers
3.13%
0.82%
3.95%
5.27%
0.82%
6.09%
US surveys
Welch
(2000)a
1997 and
1998
Finance Academics
Welch
(2001)a
2001
Finance Academics
Graham and
Harvey
(2001)b
2000 to
2001
7.1% (mean)
7.0% (median)
5.5% (mean)
5.0% (median)
Chief Financial
Officers
4.2%
n/a
n/a
n/a
7.1% (mean)
7.0% (median)
5.5% (mean)
5.0% (median)
4.2%c
a
The equity premium reported is the 30 year arithmetic average equity premium measured against bonds. b The
equity premium reported is the 10 year arithmetic average equity premium measured against bonds. c The range for
the equity premium of 3.6-4.7 per cent reported in the Draft Decision referred to the range for the average of
responses across six separate surveys conducted between 6 June 2000 and 10 September 2001, and the number
reported in the table above is the weighted average results from these surveys. The median of the expected equity
premium was below the mean for all except one of the surveys.
Source: Jardine Fleming Capital Partners Limited, 2001, Welch, I, 2000, ‘Views of Financial Economists on the
Equity Premium and on Professional Controversies’, Journal of Business, vol 73, no 4, pp. 501-537; Welch, I, 2001,
The Equity Premium Consensus Forecasts Revisited, Cowles Foundation Discussion Paper No. 1325, Yale
University; Graham, J., C. Harvey, 2001, Expectations of Equity Risk Premia, Volatility and Asymmetry from a
Corporate Finance Perspective, working paper, Duke University.
In contrast to the distributors’ submissions, the Energy Users Coalition of Victoria (EUCV)
suggests that the equity (market risk) premium used by all regulators, including the Commission,
is excessive. The EUCV proposes benchmarking of the distributors using financial indicators
(EBIT/assets) observed in the marketplace as one solution for establishing a “correct value for
the ERP” (EUCV 2005d, p. 52).
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Final Decision
The EUCV also provided their March 2005 submission to the South Australian regulator’s
(ESCOSA) review of ETSA Utilities’ price controls. This submission advocates that the equity
(market risk) premium “should rise and fall as the market conditions actually vary, rather than
using a long term average, which currently disadvantages consumers, but will lead to
disadvantaging regulated businesses in the future” (EUCV 2005d attachment, p. 100).
The Commission notes that while its estimate of the equity (market risk) premium does reflect
financial indicators observed in the market place, the contrast with the EUCV proposition is that
the Commission has relied upon capital market data rather than accounting information. While
accounting information may assist in interpreting capital market information, such an exercise
would need to be undertaken carefully and acknowledge the difficulties with interpreting
accounting information. No such study has been submitted to the review.
The second proposition made by the EUCV (2005) was that a time varying equity (market risk)
premium should be used. However, such an approach is not feasible or desirable. The
Commission notes Gray and Officer’s (ENA 2005, p. 10-11) comments in this regard.
We recognise that it is likely that the MRP is not stationary and likely to vary under
different economic conditions. However, the fact that there is no adequate theory
underlying the variability of MRPs makes it dangerous to adjust an MRP estimate simply
because another year or two of data alter the estimated mean… We do not advocate
increasing the MRP now for the same reason we did not advocate reducing the MRP
estimate last year. The problems of the theory and measurement of MRPs suggest a
conservative approach — a regulator should be very careful about making any changes
without compelling evidence.
Finally, the Commission has also taken account of other Australian regulators’ decisions,
including its own past decisions, the most recent of which are set out in Table 9.10.
Table 9.10 indicates that the Commission has adopted an equity premium of 6 per cent (for an
assumed franking credit value of 0.50) in all of its past decisions, which is also the most common
approach of other Australian regulators. While the Commission has noted previously that this
value sits below the average of observed excess returns over the longest period, it has noted that
it is within the range of plausible estimates, noting the imprecision of the estimate provided by
the long term average and is appropriate when the totality of evidence is presented.
The Commission remains of the view that the best estimate of the equity (market risk) premium
will come from having regard to the results of each of the different methodologies (tempered by
an understanding of the strengths and weaknesses of each methodology) rather than placing sole
weight on any single methodology. Such a view has found support in submissions made to the
Commission.
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Final Decision
Table 9.10:
Equity premium estimates applied in Australian regulatory decisions
Regulatory decision
Equity premium
(per cent)
2000 ESC Electricity Distribution Price Review
2000 IPART AGL Gas Distribution Final Decision
2000 OFFGAR Alinta Gas Distribution Final Decision
2001 ACCC Moomba to Adelaide Gas Transmission Final Decision
2001 ACCC Powerlink Electricity Transmission Final Decision
2001 QCA Envestra and Allgas Gas Distribution Final Decision
2002 ACCC ElectraNet Electricity Transmission Final Decision
2002 ACCC GasNet Gas Transmission Final Decision
2002 ACCC SPI PowerNet Electricity Transmission Final Decision
2002 ESC Gas Distribution Final Decision
2003 ACCC Moomba to Sydney Pipeline Gas Transmission Final Decision
2003 ACCC Murraylink Electricity Transmission Final Decision
2003 ACCC Transend Electricity Transmission Final Decision
2003 OTTER Aurora Electricity Distribution Final Decision
2004 ICRC ActewAGL Electricity Distribution Final Decision
2004 IPART Electricity Distribution Final Decision
2005 ESCOSA Electricity Price Review Final Decision
2005 QCA Electricity Distribution Final Decision
2005 IPART Revised Access Arrangement for AGL Gas Networks Final Decision
2005 ERA Final Decision on the Proposed Access Arrangement for the Goldfields
Gas Pipeline
6.00
5.00 — 6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
5.00 — 6.00
6.00
6.00
5.50 — 6.50
5.00 – 6.00
The Commission has adopted an estimate of 6 per cent as the market risk premium in all of its
previous reviews. The additional information provided to this review has been mixed. Evidence
has been presented that the historical average over more recent periods has been somewhat
higher than previously considered, and additional survey evidence has suggested that some
classes of practitioners adopt a value higher than 6 per cent (at least after the non cash value of
franking credits is added back).
However, evidence has also been provided that suggests that unexpected capital gains may have
led to observed returns to shares in Australia overstating the historically expected returns, which
is a phenomenon the Commission has considered previously in relation to the US market. The
Commission has also continued to have regard to the information and views considered at
previous reviews, as reported above.
On balance, the Commission again adopted a market risk premium of 6 per cent for the current
review. While it notes that while this value sits below the estimate provided by simple long term
averages of excess returns, after having considered the totality of the evidence, the Commission
is confident that this value will not understate the expected equity (market risk) premium, and is
consistent it its assumption about the value of franking credits (discussed in the Franking Credit
section below).
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Debt premium (Rd) and debt raising fees
The standard practice among Australian regulators (including the Commission) is to adopt a
benchmark for the cost of debt rather than the businesses’ actual costs. A regulated business’s
actual debt costs cannot be applied in estimating the current cost of debt, as it may be determined
by historical debt costs, and be influenced by actual gearing and credit rating levels, rather than
the benchmark levels. The benchmark cost of debt should reflect the latest market evidence
available on the borrowing costs of an efficiently financed electricity distribution business.
The debt margins proposed by the distributors in their initial submissions are summarised in
Table 9.11. The total proposed debt margin ranges from 151 basis points to 171 basis points
above the 10 year Government Bond rate. All of the margins proposed by the distributors were
based upon yield estimates from the CBA Spectrum service.
Table 9.11:
Distributor
AGLE
CitiPower
Debt margins proposed by the distributors, basis points
Debt
margin
Debt raising
transaction costa
Early debt
re