Meeting with Vinnies, SACOSS, PIAC and the EDPR Customer Forum
←
→
Page content transcription
If your browser does not render page correctly, please read the page content below
Meeting with Vinnies, SACOSS, PIAC and the EDPR Customer Forum 18 October 2018
Agenda
Item Topic
1 Safety topic
2 Objectives for today
3 Customer Forum status update
4 What we’ve heard from our customers
5 Improving customer experience
6 Life support customer initiatives
7 Revenue, demand, expenditures and RAB
8 DER integration
9 Network innovation
10 2022-27 TRR: Customer engagement approach
2
Safety topic – Stop for Safety 2018
Company wide program to encourage Critical risks
engagement and participation in safety
Key risks that can cause significant injuries or
leadership at all levels
fatalities
› Target for minimum participation levels
across the business of 90% 1. Electrocution
2. Hit by object, plant or equipment
3. Motor vehicle
4. Fall from height
Managers must set aside 1 hour during 5. Customer aggression & working alone
October to hold a Stop for Safety event 6. Excavation, trenching, confined spaces & gas
with their team ignition
7. Fatigue
8. Catastrophic network asset failure
The focus this year is on: 9. Personal wellbeing – mental health
› Critical risks; or
Behaviour impacts on safety
› Behaviour impacts on safety
5 states of mind which are often identified as
contributing factors in incidents
Our team is focussing on Managing
Pressure and Fatigue D = Distraction
R = Rushing
F = Fatigue
F = Frustration
C = Complacency
3
Objectives for today
Provide an update on the outcomes so far of the Customer Forum
negotiation process
Listen to stakeholder views on key elements of our proposal (both in
and out of the scope of negotiations), prior to publishing the draft in
December 2018
Opportunity for Customer Forum to privately test its negotiating
positions and conclusions with stakeholders.
4
Customer Forum status update
The scope of negotiations
In-scope (AER In-scope (AusNet Out of scope / context
endorsed) Services)
• All other capital
• Operating expenditure • Replacement expenditure
• Augmentation expenditure - major • Rate of return
expenditure - major projects (i.e. station • Tax allowance
projects (i.e. station rebuilds) • Opening RAB
rebuilds) • DER integration • Pricing and tariffs.
• Customer experience • Innovation expenditure
and hardship • Metering
arrangements • Price path
• Overall ‘reasonableness’
of proposal
6
Areas of preliminary agreement
Most elements of opex forecasting approach (i.e. base, trend,
regulation-driven step changes)
Various customer initiatives for implementation by 2020
An improved customer service incentive scheme from 2021
Funding for network innovation projects
Metering revenues (subject to a commitment to implement customer
initiatives, and comparison with other Vic. DNSP forecasts)
Preliminary agreements reached will be reflected in the Draft Proposal
published in December, to be tested with wider stakeholders prior to
7
lodgement of the formal proposal in July 2019Outstanding matters
Augex/repex major projects
› The Forum is seeking further information (e.g. on non network
alternatives, demand forecasting methodology, how we prioritise projects
etc.) before negotiating on these topics in November
DER integration
› AusNet Services is currently working through impacts of Vic. Govt. Solar
Subsidy policy
› We have tested high level DER connection charging options with the
Forum, and will consult on these in our draft proposal in December
Price path
› To be negotiated in November, once draft proposal revenues are finalised.
A second period of negotiations is scheduled for early-mid 2019, to test
propositions in more detail and address stakeholder feedback on the draft
8
proposalQuestions for attendees
Do stakeholders have views on:
› The areas of negotiation between AusNet Services and the Forum; and/or
› The preliminary agreements reached.
9What we have heard from our customers
Research highlights
Of small businesses
Outages 15% have installed back-up
7.8/10 power generation
Consistent Overall satisfaction
with views We still need to do better
with supply with our proactive
5 years ago,
majority of Anecdotally, heightened concern about communications around
reliability, particularly amongst business
customers customers, small and large. outages.
are satisfied Customers want to know the reasons for
with outages.
Residential customers
reliability 63% considered annual
blackouts were
The main reasons customers contact
AusNet Services is to get outage
information or tell us about an outage.
acceptable.
Businesses are less Providing a reliable,
tolerant of outages. continuous electricity supply
was rated as the most valued
service.
Small business
96% customers considered
a reliable energy
“Lifeblood of
supply as very the house.” 11
importantResearch highlights
Affordability Many customers felt the
~1/3 Customers thought their
bills were poor or very poor reason for bills increasing
in terms of affordability. was (at least partly) due to
Current
profiteering by electricity
electricity costs retailers and distributors
and future price
rises are a
~2/3 Residential customers
believe that their electricity
concern for all provided poor value for
customers money. For vulnerable
Small businesses believe customers, we need to
~1/3 that their electricity provided
poor value for money.
understand energy
stress in the context of
other pressures in their
lives. A more holistic
~2/3 of customers felt electricity
bills have increased in the approach to this
past 2 years. segment is required.
For many business customers (small and large)
electricity prices are surpassing labour costs.
Voluntary demand management programs generally seen as a positive way
to reduce expensive network upgrades. Community education seen as
critical to driving participation.Research highlights
of solar customers Customers said
Control
An emerging
~80% would be very ~9% they would
unhappy if their probably or
theme
energy exports were definitely go off-
amongst
customers restricted (time of day grid in the next
is concern or amount of energy) ten years.
about an
increasing The ability to exercise choice is Amongst C&I customers,
significant investment in
lack of closely tied to perceptions of capability to drive energy
control control. independence.
Complexity and lack of optimism Network management
about outcomes deter customers strategies like demand
from becoming engaged. response and active
solar export limiting are
of customers try to viewed by many
>70% reduce energy use, but customers as a further
many are unaware that loss of individual
smart meters can help. control.
13Research highlights
of non-solar customers Solar is viewed as
Interest in
new
58% are interested in
beneficial, as is the idea of
modernising the network to
installing solar accommodate it.
technology
of small business
Solar remains 21% customers have installed
49% of customers think the
government should pay for
the dominant solar for their business solar-related network upgrades.
area of interest
of customers are
and investment
~1/2 interested in purchasing
Anecdotally, despite
understanding solar
Increasing a battery. cross-subsidies,
awareness of, customers (incl.
and intent to vulnerables) are prepared
Interest in electric vehicles was
purchase to pay for solar network
batteries and relatively limited.
upgrades.
EVs
Interest in renewables is lower
Enablement of solar is
among businesses than residential
analogous to a public good,
customers, due to the high
so funding to accommodate
consumption and consequent long
solar should be shared.
pay back periods.Research highlights
Bills, tariffs, retail offers and the Customers want to
Information
industry itself are too know which
needs complicated for customers to appliances/
navigate.
Apart from equipment
outage
Customers don’t trust the consumes the most
information,
energy information they receive, power –
customers are
looking for ways as they see it as biased. information to help
to reduce bills understand how
and be more of customers behaviour impacts
energy efficient >70% would like to be bills.
notified if their
energy Preference for multi-
consumption channel approaches to
was outside its communications,
depending on nature of
normal range
communications and
individual preferences.
15Questions for attendees
Do stakeholders consider the research findings are reflective of
customer preferences and concerns?
16Improving customer experience Improvements being made in the 2016-20 period
Several initiatives are underway to improve
customer experience by 2020
Collaborating with the community
1 Turning the organisation to face the customer
5
Making our organisation easier to deal with
2 Aligning our incentives with customer outcomes
6
Building our understanding of our customers’ Taking care of our most vulnerable customers
3 needs 7
Fixing customer pain points and improving the Making our claims process easier for all
4 customer experience 8 customers
18Questions for attendees
Do stakeholder have views on the eight initiatives?
Are there other initiatives that we should be considering?
19Improving customer experience An improved customer service incentive scheme from 2021
Customer Satisfaction Incentive Scheme
AusNet Services is proposing that a new Customer Satisfaction Incentive
Scheme (CSIS) be introduced from 2021. This will encourage
improvements in customer satisfaction regarding:
› Connections
› Planned outages
› Unplanned outages
› Complaint handling.
AusNet Services has commissioned a quarterly survey of our residential
and business customers satisfaction, where customers report their
satisfaction on a scale between 0 and 10. We propose to use the average
overall satisfaction score as the scheme parameters and measure this
against target performance.
Targets will be set on existing performance, so AusNet Services is rewarded
for improving above existing levels and penalised if performance declines.
21Customer Satisfaction Incentive Scheme
We propose a total of 0.5% revenue at risk (approximately $3.5million per
annum) for this scheme. This would replace the existing telephone
answering parameter in the STPIS (which we propose to remove).
Scheme Parameter Revenue at Risk
Satisfaction with Planned Interruptions $1.0M
Satisfaction with Unplanned Interruptions $1.0M
Satisfaction with Connections $1.0M
Satisfaction with Complaints $0.5M
Total $3.5M
22Questions for attendees
Do stakeholder have views on the design of the proposed customer
service incentive scheme, e.g.:
› Replacing the STPIS telephone answering measure
› The proposed performance measures
› The proposed revenue at risk
23Life support customer initiatives
We are implementing changes to protect
our most vulnerable customers
Improve restoration times for life support customers experiencing an
outage. Utilise information received from smart meters to identify life
support customers off supply and improve timeliness of reconnection of
these customers.
› Effective from 31 October 2018
Consistent and “plain language” compensation and claims fact sheet
that is easily accessible by customers.
› Effective from 31 October 2018
Enhance communications to vulnerable / life support customers.
Enhance and expand communications to vulnerable and life support
customers in advance of network events, to include SMS, social media and
community messaging channels.
› Effective from December 2018
25Questions for attendees
What are stakeholder’s views on these initiatives?
Are there other initiatives we should be considering to support and
protect life support customers?
26Revenues, demand, expenditures and RAB Revenue and average bill forecasts
Revenue per customer (the average bill)
Revenue per customer is forecast to decline by 5% ($46) in 2021, and
by a further 2% ($19) by 2025
28Total revenue
Total revenue is forecast to be 3.2% higher than 2016-20 revenues, or
2% less if incentive payments are excluded
29Questions for attendees
Do the revenue forecasts appear reasonable?
30Revenues, demand, expenditures and RAB Operating expenditure forecasts
Base year
We have made significant opex savings in the current period, lowering
prices from 2021
• Base year - 2018
• Negative adjustment for leases
($6M) - change in the approach to
leases – these will be capitalised
from 1 April 2020 onwards and so
are removed from the base year
• Bottom-up forecasts of:
• GSL Payments ($49M) –
Forecast based on historical
GSL payments.
• Metering re-allocation from
ACS to SCS ($32M) – to
accurately reflect the usage
of these assets by the
distribution business.
• Debt raising costs ($12M) –
Forecast using AER’s
benchmark approach
32Step changes
Step change expenditure is principally driven by regulatory change and
opex/capex trade-offs
• REFCLs ($9 million) – A
compliance-driven safety
program, this requires in
additional annual testing
requirements of the REFCL
equipment.
• IT cloud transition ($9 million)
– A move from on premises
solutions (capex) to cloud based
(opex) solutions. This is
increasingly the service delivery
option for all IT systems
• Security ($1 million) – Uplift in
IT security capabilities, driven by
emerging regulatory changes.
• Innovation ($3 million) – see
slide 46
33Trend parameters
Our trend parameter forecasting approach is
largely in line with recent AER decisions
• Labour growth – Using average of
DAE and BIS reports as accepted
by the AER in Evoenergy draft
decision.
• Growth parameters – Using the
AER approach as applied in AusNet
Services 2016-2020 decision.
Modest growth in customer
numbers, circuit length forecast and
currently no growth in ratcheted
maximum demand.
• Productivity – zero productivity
applied in line with latest AER
decisions (noting AER review
recently commenced)
• Total of $59 million over the 2021-
25 regulatory period.
34Questions for attendees
Does the opex forecast appear reasonable?
35Revenues, demand, expenditures and RAB Demand forecasts
We only expect small pockets of maximum
demand growth over 2021-2027
Change in
demand (MW)
Doreen
Clyde North
Driven by new estates in Melbourne’s growth corridors – particularly Clyde North and
Doreen. The bulk of our 2021-25 augmentation program is upgrades in these two areas. 37However, demand profile is becoming
‘peakier’
Total customers are increasing, while energy consumption is declining
820,000 7,700
800,000
7,600
780,000
7,500
760,000
Total Customers
7,400
Energy (GWh)
740,000
720,000 7,300
700,000
7,200
680,000
7,100
660,000
7,000
640,000
620,000 6,900
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Customers (LHS) Energy (RHS)
38Revenues, demand, expenditures and RAB Capital expenditure forecasts
Total capex forecast
Total gross capex is forecast to be 9% lower over 2021-25, compared to
2016-20 actual/estimated capex
40Augmentation capex forecast
Augex is forecast to be 8% lower over 2021-25, compared to 2016-20
actual/estimated augex
41Major projects – probabilistic planning and
economic analysis approach
Collateral damage
Establish Baseline
Risk = Safety risk + Supply risk + & Environmental
risk
Formulate options to OPTION OPTION OPTION OPTION
address risk 1 2 3 4
Options Analysis Conduct sensitivity analysis and test assumptions:
compare to Baseline Discount rate, VCR, Asset failure rate, demand growth
Select Conduct sensitivity analysis to determine
Preferred Option economical timing of Preferred Option
42Augex major project – Clyde North case
study
Economic analysis shows that the installation of a new
transformer is justified by 2023
Supply risk vs. Annualised cost of augmentation ($M) • This project will be subject
1.6
to RIT-D process (project
cost of > $5M)
Supply Risk/Annual Augmentation Cost ($M)
1.4
Can non- • Non-network options
1.2 network options
Can non-network options be used to defer report will explore
be used to address risk
1.0 before augmentation is
augmention? opportunities to defer
Network network augmentation
justified?
0.8 augmentation is
justified through detailed economic
0.6 analysis.
0.4
0.2
0.0
2019 2020 2021 2022 2023 2024 2025
Year
Supply Risk ($M) Annualised Augmentation Cost ($M)
43Augex major project – Clyde North case
study cont.
The preferred network option delivers the best reliability outcome
The deferral and do nothing options reduce short term costs, but
have significant reliability impacts
Price reliability trade-off – Clyde North - Short term
Clyde North
800
1: Do nothing
Total expected outage duration 2021-25 (mins)
700
600
7: DM +Agg +
Deferral to
500 4: 2 yr deferral 2026
400
3: 1 yr deferral
300
5: Embedded 6: Battery
200 generation
2: Preferred
option
100
0
$- $1 $2 $3 $4 $5
Revenue per customer 2021-25
44Questions for attendees
What are stakeholders’ views on the price/reliability trade-off
framework used to compare and negotiate augex major project
options?
Does the augmentation capex forecast overall appear reasonable?
45Connections capex forecast
Net connections capex is forecast to be 14% lower in 2021-25, compared
to 2016-20 actual/estimated capex
Gross and net connections capex 2011-25 ($m, Real $2020)
$140
$120
$100
$80
$M
$60
$40
$20
$0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Net connections capex Contributions Gross Allowance
46We have recently implemented a more cost
reflective customer contributions policy
This has led to a fairer recovery of the connection costs of
residential land developments from 2018
2014-16 avg. 2018-20 avg. (forecast)
12% 77%
23%
88%
Average costs recovered from residential land developers Average costs recovered from residential land developers
Average costs recovered from other customers Average costs recovered from other customers
47Questions for attendees
Does the net connections capex forecast appear reasonable?
48Replacement capex overview
• Repex is forecast to be 28% higher in 2021-25, driven by higher
expenditure on conductors, cables and poles
• Forecast remains lower than that produced by the AER’s Repex model
The majority of repex is not within the scope of negotiations, and will be tested
49
with stakeholders in 2019 through deep divesReplacement major projects: overview
The repex forecast includes nine major station asset replacement
projects, which are being negotiated with the Customer Forum
These projects account for around 20% of repex and 20% of our total
customers
Direct capital cost
Project Timing
$2020 M
Thomastown 2021 $14.6
Benalla 2022 $8.2
Bayswater 2022 $11.1
Maffra 2022 $16.5
Traralgon Stage 2 2023 $8.7
Watsonia 2023 $19.1
Bairnsdale 2023 $5.9
Warragul 2023 $11.3
Newmerella 2024 $5.4
50Replacement major projects:
price / reliability trade-offs (short term)
Option 4 (deferring the three lowest risk projects) would give rise to
modest price and reliability impacts in the short term, relative to the
preferred portfolio
Price-Reliability Trade-Off of Repex Portfolio Options (cost versus outage duration) – Short Term 2021-25
140
6: Defer all projects out of period
Total expected outage duration 2021-25 (mins)
130
120
110
5: 1 yr deferal of
all projects
100
4: Three lowest risk
projects defered 3: Three project
90
out of period deferals + Non
network option
80
2: Proposed timing
70
1: Start all projects
60 in 2021
50
$0 $1 $2 $3 $4 $5 $6
Average annual cost per customer 2021-25
51Replacement major projects:
price / reliability trade-offs (long term)
In the long term, the cost of Option 4 is higher than the preferred
option, and would result in worse reliability
Price-Reliability Trade-Off of Repex Portfolio Options (cost versus outage duration) – Long Term
140
6: Defer all projects out of period
130
Total expected outage duration 2021-25 (mins)
120
110
5: 1 yr deferal of all
projects
100
90
4: Three lowest risk projects
deferred out of period
80 3: Three project
2: Proposed timing deferals + Non
network option
70
60
1: Start all projects in 2021
50
$100 $120 $140 $160 $180 $200 $220 $240
PV cost over 50 yr asset life per customer
52Questions for attendees
What are stakeholders’ views on the price/reliability trade-off
framework used to compare and negotiate the repex portfolio options?
Does the replacement capex forecast overall appear reasonable?
53Safety capex forecast
Safety capex is forecast to be 58% lower over 2021-25, compared to 2016-
20 actual/estimated safety capex
54Questions for attendees
Does the safety capex forecast appear reasonable?
55IT capex forecast
The IT capex forecast is broadly in line with 2016-20 actual/estimated
capex
56Questions for attendees
Does the IT capex forecast appear reasonable?
57Revenues, demand, expenditures and RAB Forecast RAB
Forecast real RAB growth per customer
Relatively flat RAB per customer is forecast from 2020
RAB per customer - $0's, real $2020
$6,500
$6,000
$5,500
$5,000
$ $4,500
$4,000
$3,500
$3,000
$2,500
$2,000
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
2015-17 - Actual excl Mandated Safety 2015-17 Actual - Mandated Safety
2018-20 - Expected excl Mandated Safety 2018-20 - Expected Mandated Safety
2021-25 - Forecast excl Mandated Safety 2021-25 - Forecast Mandated Safety
59Forecast real RAB growth
RAB growth has been materially impacted by mandated
bushfire safety programs
This is forecast to continue in the 2021-25 period
Closing RAB - $m, real $2020
$5,000
$4,500
$4,000
$M $3,500
$3,000
$2,500
$2,000
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
2015-17 Actual RAB excl Mandated Safety 2015-17 Actual RAB - Mandated Safety
2018-20 Expected RAB excl Mandated Safety 2018-20 Expected RAB - Mandated Safety
2021-25 Forecast RAB excl Mandated Safety 2021-25 Forecast RAB - Mandated Safety
60DER integration How our proposal is impacted
Solar uptake on our network Strong growth in solar uptake is expected between 2021 and 2015 62
Impact on Proposal
Core elements of the DER integration program are:
1. We propose to use a smart platform to enable maximum export within
existing network capacity. Reduces the number of solar customers with
static export constraints.
2. We are assessing where it will be economically efficient to augment to
enable export.
Program Description Forecast expenditure
($m 2020)
Distributed Energy Work to expand and productionise the DENOP platform, which is under trial
Network Optimisation in the current period
Platform (DENOP)
10
Augmentation to Augmentation of the shared network to allow additional DER export
increase hosting capacity where economically efficient. 21
capacity
63Who should pay for efficient augmentation
to support additional DER?
We are exploring various options with the Forum, and will consult on
these in our draft proposal in December:
1. Status Quo – All customers fund the efficient augmentation costs through network
charges. This is consistent with the current regulatory framework.
2. Additional connection charge for new connecting DER customers – only DER
customers contribute to efficient augmentation costs, via connection fees. This
could be applied to:
1. Some new connecting DER customers (i.e. those able to export)
2. All new connecting DER customers
This option would require regulatory change to proceed.
64Questions for attendees
Does the approach to accommodating DER appear reasonable?
What are your initial views on the DER connection charge options
presented?
65Network innovation
Our network innovation proposal
Network R&D funding per capita 2014, USD (2015
Our electricity system has changed prices and PPP)
rapidly and continues to transform
Innovation is necessary to
› meet changing customer needs and
expectations
› support customer control over how they use
electricity and our network while maintaining
reliable supply
› keep costs sustainable in the face of this change
› leverage technology to provide better services to
our customers
Innovation expenditure by Australian
networks is traditionally very low in
international terms
Source: IEA and United Nations database as reported by
Energy Networks Australia, Network Innovation Discussion
Paper, July 2017 67Our network innovation proposal
Constraints on incentives for innovation imposed by our regulatory
framework
› Difficulty of meeting expenditure tests - benefits uncertain and hard to quantify
› 5-year regulatory cycle not suited to projects with multi-period costs and benefits -
particularly where costs are incurred well before benefits might arise
› Riskier investments not rewarded - we do not profit in the same way as businesses
in competitive markets and hence have less incentive
Preliminary agreement reached with Forum on innovation expenditure
allowance (separate to demand management innovation)
› $7.5m over 5 years ($2018), reduced from $10.8m and excluding expenditure on
EV preparation
› This innovation spend accounts for 0.3% of opex and 0.5% of capex
› The proposed focus of the innovation expenditure will be trialling technologies to
• move from a statically managed centralised network to a dynamically managed
decentralised network
• deploy stand alone power systems in remote network areas
68Questions for attendees
Are there particular areas where stakeholders would like to see
innovation expenditure focussed?
692022-27 Transmission Revenue Reset: Customer engagement approach
2022-27 TRR: customer engagement approach
We are commencing planning for our 2022-27 TRR, including our
approach to customer research and engagement
We are therefore seeking feedback on:
› What customer engagement model is most effective? What has worked
well in other jurisdictions? e.g. a customer advisory panel
› When should engagement start?
› How much engagement should be done with end users vs.
advocates/customer reps?
› What research methods are most meaningful and effective?
› Is publishing a draft proposal helpful?
› Anything else?
71Thank you for your time today
You can also read
