Capacity Investment Scheme – Public Consultation paper

Not Confidential

28th August 2023
Carisbrooke Consulting Group

Attn: David Dawson
Principal Consultant
d.dawson@carisbrookeconsulting.com.au
M: 0417 285 194

Mr Simon Duggan
Deputy Secretary
DCCEEW

Attn: Salim Mazouz, Capacity Investment Scheme

Via portal: https://consult.dcceew.gov.au/capacity-investment-scheme-public- consultation-paper/

Dear Mr Duggan,

Re: Capacity Investment Scheme Public Consultation Paper – CCG Response

The dilemmas faced by the Australian electricity sector have been highlighted again within AEMO’s Final 2022 Integrated System Plan (ISP)1. In simple terms the total generation portfolio will need to rise in power capacity terms from 85 GW in 2023-24 to 142 GW in 2032-33 , and to 287 GW by 2049-502. This is an over build of 1.7 times the existing generation fleet capacity between 2024 and 2033, and 3.3 times by 2050. Included in these figures is storage capacity of 3.4 GW in 2023-24, 23 GW in 2032-33, and 61 GW in 2049-50, all used to ‘firm’ renewable supply as thermal plant withdraws. Network, Generation and Storage investment is now lagging far behind what AEMO believes is required, and we are seeing State Governments provide supporting contracts to coal plants to ensure dispatchable generation remains online3.

The Capacity Investment Scheme (CIS) is a welcome approach to incentivizing additional private and public sector investment in variable renewable energy (VRE) and energy storage systems (ESS) over the next 10 to 20 years, in order to support the transition of the Australian electricity systems to deliver reliable, affordable and lower emissions energy to consumers.

The following paragraphs highlight our main issues of concern raised by the CIS consultation paper, and specific responses are provided in Attachment A.

1
AEMO, 2022 Integrated System Plan, Final, June 2022.
2
This assumes the Step Change scenario developed by the extensive 2022 ISP consultation process unfolds as is currently adopted by industry stakeholders (refer: Chart Data file, 2022 ISP).
3
The Guardian, AGL agrees to keep Victoria’s Loy Yang A power station available until mid-2035, 21 Aug 2023.

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Only Zero Emissions

The CIS consultation papers indicates that “Only zero-emissions technology projects will receive Commonwealth support through the expanded firming tender.” 4

Unless fully contracted to VRE (which at present is extremely unlikely for stand-alone storage projects seeking contracts to support raising of investment funds), ESS charging capacity will need to be drawn from the wholesale electricity market which even at 82% on-grid renewable energy systems will not be able to operate at or claim zero-emissions for scope 1. Some of the wholesale electricity needed for ESS will by definition be sourced from the market which will continue to have a percentage of supply from coal, gas or liquid carbon-based fuel sources for the foreseeable future.

However, ESS must be eligible for the CIS as AEMO’s 2022 ISP clearly shows our future transition to zero-emissions cannot occur without significant volumes of viable
ESS capacity which firms existing and new VRE projects. Without stand-alone grid- scale and community-scale ESS to firm VRE, the NEM / WEM reliability and all government’s affordability targets will not be achieved. Locking stand-alone ESS out of the CIS tenders will reduce competition for large-scale VRE/ESS projects, increase tendered CIS prices from these ‘bundled’ projects (as there will be limited competition), and not support continued strong growth in solar PV capacity from residential and commercial & industrial investment, and solar PV & wind capacity from stand-alone grid-scale VRE investment.

Please ensure stand-alone ESS projects are clearly allowed into the CIS tender process, even where they can be argued to not be a zero scope 1 emissions technology.

De-rating Factors

De-rating factors in the project assessment process envisaged by DCCEEW are yet not defined. “The derating factors for the purposes of the assessment of individual projects in the tender process will consider the impact of location and network constraints.” We suggest the following be considered for inclusion in defining de- rating and indeed re-rating factors to be applied in consideration of projects put forward to the CIS assessment process.

Projects should be assessed by the detriment they impose on the grid through inappropriate location and/or increase on existing grid congestion. The approach to derating projects in the tender process needs to be made public, so that near-term projects which seek to exploit reduced congestion and/or an improved MLF by connecting to the grid between known or emerging connection points for renewable energy zones5 (REZ) and the regional reference nodes (RRNs) are informed on how their project will be derated and understand their investment risk.
4
CIS Consultation Paper, page 8.
5
We believe the land based REZs as defined by Figure 15 in the 2022 ISP should the primary focus. New REZ introduced since that analysis will likely dissipate the lower cost advantages sought from co-located or clustered VRE which utilises the same transmission network links to the RRN.

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The current market / regulatory flaw allows connections closer to the RRN but outside the REZ to gain market advantage against existing or proposed VRE/ESS connections within each REZ, by increasing the probability of congestion for REZ output, and reducing MLF factors for existing REZ VRE connections which reduces the probability of dispatch and also reduces revenues derived when dispatched in the wholesale electricity market. The disadvantages seen by REZ connected
VRE/ESS result from increased network congestion further away from the RRN, and
VRE curtailment / spill within the REZ, which denies low-cost electricity from dispatch in the wholesale electricity market, and in turn increases wholesale electricity prices for consumers. Thus the derating factors need to have the effect of incentivizing new
VRE and/or ESS projects at grid locations where it reduces existing and future congestion, shares existing network capacity with minimal needed upgrade, and avoids blocking access to dispatch from existing and future project investment.

Re-rating factors should be applied for projects seeking to connect within the defined
REZ (where shared grid upgrades are proposed or ongoing), at Terminal Stations, at
Zone Substations, or at or near coal-fired generation facilities which are slated for eventual closure. VRE and/or ESS projects connecting at these locations should reduce the need for additional transmission network investment, whilst re-using existing grid infrastructure, thus helping to lower the end costs to consumers.

Flexibility Tradeoffs

The CIS consultation paper suggests “For example, a 4 hour, 100MW hour battery energy storage system (BESS) has less operating flexibility compared to a 1 hour,
400MW BESS. These trade-offs will be better understood over time.” 6 The implication is that ESS with larger energy storage (MWh) and delivery of energy for longer periods, should be de-rated as these projects are less flexible than smaller energy storage which can deliver energy for shorter periods. This assessment does not standup technology scrutiny.

Support for network reliability depends on the inverter technology as well as the storage capacity. This includes how quickly MW output can ramp, and which of the
FFR and FCAS markets the ESS can compete in. But reliability and restoration of frequency following contingency events also depends on how long the additional
ESS output above rated capacity can be delivered when dispatched. This is a 5 minute to an hour plus delivery of ESS output above rated capacity. Simply put more energy storage availability means an ESS can compete with a larger range of network and energy support services, and more often throughout the day, all of which will be needed by AEMO as coal, gas and liquid fuel generation is retired in the future.

This is supported by a later comment where “This approach is similar to the NSW
Firming and Long Duration Storage (LDS)Long-Term Energy Service Agreement
(LTESA) tenders, which prescribe minimum durations of 2 hours and 8 hours respectively, with longer durations being attributed greater financial value.” 7 We

6
CIS Consultation Paper, page 14.
7
CIS Consultation Paper, page 14.

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Arguably ESS with larger energy storage duration (longer delivery capability), should be rated higher than for smaller energy storage duration, at the same rated power output of the inverter. Larger energy storage will be more able to dispatch to support network reliability.

Ineligibility of Non-dispatchable generation

The CIS consultation paper suggests VRE which is not dispatchable should not be eligible for the CIS tender process. “Variable renewable energy projects that do not generate electricity that is dispatchable and/or comprise a storage component that would enable the electricity to be dispatchable will not be eligible for support under the CIS due to their limited contribution to system reliability.” 8

While this makes sense from a reliability standpoint, DCCEEW should reconsider allowing planned or new VRE into the scheme whose output at rated power (down- graded by its capacity factor9) are 100% contracted to an existing, planned or new
ESS project over the VRE’s life-cycle through a PPA. While co-location of VRE and
ESS would be preferred for maximum system dispatchability and hence reliability impact, within State contracted VRE and ESS also assists system reliability, but to a lesser extent. VRE and ESS connected in different States provide little reliability support, even though they may be financially hedged with each other through a PPA.
This suggests a three-tier rating factor could be applied. The highest re-rating for co- location10, second highest re-rating for within State VRE and ESS connections, and the lowest (or de-rating) for VRE and ESS connections in different States.

VRE which are 100% contracted to ESS where co-located or connected within the same State, should be eligible for the CIS tenders, albeit there may be a lower re- rating or de-rating factor applied in the selection criteria where they are not
‘physically or electrically’ co-located.

Access to Additional NSW Project Funding

Discussion at the CIS public forum on 15th August 2023, suggested that the CIS support for an additional 550MW of firmed capacity in NSW, above the 380MW already supported by the NSW Government, was only eligible to projects which had already provided an application to the initial NSW process. New VRE, ESS and/or
VRE/ESS projects which had not met the submission deadline for the NSW process would not be eligible for the additional 550MW under the CIS scheme.

This may limit the entry of new VRE and/or ESS projects which were unable to meet the initial NSW submission deadlines and project delivery time frames specified by
AEMO Services. A more equitable process would be to have spillover projects not

8
CIS Consultation Paper, page 16.
9
Capacity factor is the % of time a generation technology outputs useful power on average over a period of time.
10
It allows for strongest energy shifting and hence impact to lower congestion on links to the RRN at peak solar and/or VRE output.

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550MW opportunity. This would also allow emerging ESS technologies which can deliver on longer time frames to be included in the NSW funding uplift provided by
Federal CIS funding initiative.

Concluding remarks

Investment in VRE and ESS has fallen short of the 2022 ISP forecast requirements over the last year. Given significant current investment headwinds, how then can the necessary 3.3 times GW investment in VRE and 8 times GW investment in energy storage capacity, progress and be fully deployed by 2050? Without this new investment before baseload thermal generation is withdrawn, network reliability will be degraded and the transition to lower emissions electricity supply will not be achieved, and electricity prices will tend to be higher than they could be if new lower cost VRE capacity was able to be dispatched in the wholesale electricity market.

The CIS is clearly intended to provide strong support and encourage the necessary additional investment in VRE and ESS required to maintain electricity network reliability and affordable electricity supply services to end-users. Careful selection of project ranking criteria within each CIS tender should achieve the desired investment uplift. Transparency on the criteria to be used will be invaluable to new project proposals.

Thank you for the opportunity to provide comments on DCCEEW’s CIS consultation paper.

If there are any queries on this submission please let me know on 0417 285 194 or via d.dawson@carisbrookeconsulting.com.au.

Yours sincerely,

David Dawson
Principal
Carisbrooke Consulting Group

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Attachment A

Consultation Feedback Table

Reference: Question: Response:
1 (Page 7) What other implications The CIS introduces a wholesale energy
the CIS might have on market hedging financial instrument to
the energy market, and assist in underwriting VRE and ESS
how the CIS can be investment. It does not appear to address
designed to mitigate risks the existing economic frictions from MLF
while delivering on key (and DLF), optimization of line congestion,
policy objectives? optimization of new transmission &
interconnection costs within and for REZ
and new VRE and ESS connections, nor
TUoS and DUoS extraction of monopoly
rents, nor optimization of ESS versus
SynCon costs for inertia, system strength
and dispatchable firming services.
Selection criteria using multi-criteria
analysis (MCA) approaches could provide
a better outcome for consumers wrt price
and reliability within the NEM where a
broader view is adopted. An MCA
approach could be used to implement the
de-rating and re-rating criteria process
contemplated by DEECCW for the CIS
tender evaluation.
2 (Page 7) What issues arise from TBA.
implementation of the
CIS, including interaction
with the existing Reserve
Capacity Mechanism?
3 (Page What minimum storage We believe two ‘minimum storage’
14) duration should be thresholds should be defined, being 4
required for tender hours and 8 hours. The longer duration
eligibility, to achieve CIS should attract the greater financial value
policy objectives? from the CIS as it provides a greater
contribution to system reliability, system
strength and system performance in the
long-run as VRE percentages increase.
4 (Page What methodology for ESS cycle degradation must be included
14) modelling and measuring in the forward forecasts, otherwise grid-
duration requirements for wide storage needs will be
various technology underestimated. Cycle degradation varies
durations would be with ESS technology type and is different
appropriate? from round trip efficiency (RTE). Project
investment life-cycle before full
refurbishment also varies with ESS
technology type. Rated power should not

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be used for modelling purposes as it is an
inflated initial performance measure.
Available power after cycle degradation at
(say) 50% of the ESS technology life-cycle
should be used for modelling the duration
of storage available. See the attached
spreadsheet to identify the issue (ESS
Duration CIS Modelling Examples
v1.0.xlsx). This degraded storage duration
should also feed into the financial value
attributed within the CIS.
5 (Page How could the CIS Cycle degradation and project-life cycle
14) eligibility criteria and will improve over time, reducing and
assessment methodology increasing respectively. Standard
change and adapt over measures should be used over time, and
time? where new technologies improve on the
standard measures used, a tendering
advantage will be available, driving down
unit storage and firming costs over time.
6 (Page What methodology for We agree that “storage technology [which]
16) considering a project’s is only capable of charging from one of the
contribution to zero Australian electricity grids are considered
scope 1 emissions would as having a zero contribution to
be appropriate? scope 1 emissions”. This is because
stand-alone ESS which is not co-located
with the VRE will be required to soak up
VRE output which is otherwise spilled,
particularly at peak solar.
7 (Page How could this criteria Updates of proven capacity factor for VRE
16) and assessment and degradation effects for ESS could be
methodology adapt as explored and adopted before each CIS
technology matures over tender process, so rating factors could be
time? adjusted over time.
8 (Page What types of demand Agree that demand response which
16) response would be provides a demand reduction over a
consistent or inconsistent period which is at least 4 hours duration
with the CIS objectives? should be eligible for the CIS tender. Cap
and floor support should be withdrawn
where at least two dispatched demand
responses are not provided within a rolling
12 month period, and reinstated from the
next dispatched demand response.
9 (Page How can the CIS design TBA
16) be future-proofed for an
evolving/changing
technology mix?
10 (Page The Department is We do not agree with this restriction. We
17) seeking feedback on the believe this restriction based on rated
eligibility requirement of power output will limit investment in ESS
projects in the NEM for technology at lower voltages (eg 66kV to

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equal to or greater than 11kV) closer to the loads it seeks to serve.
30MW registered This is related to the import / export (or
capacity? X/R) ratio of the transmission (TXN with
lower R) and distribution (DXN with higher
R) lines, and their import / export power
transfer capability, without voltage
fluctuations outside of the mandated
voltage standard levels. The NER
specifies semi-scheduled generation
between 5MW and 30MW. ESS at these
sizes will be more economic at
connections between (say) 66kV to 11kV,
and will help soak up solar PV generating
at lower voltage levels, which cannot
easily flow up-grid to TXN grid connected
ESS because of the X/R ratio issue.
Connection of ESS at these sizes will be
very beneficial for the DXN and
community connected DER. Investment at
these ESS sizes will be beneficial for both
reliability and for increased support for
solar PV penetration increases at
residential, SME, and Commercial &
Industrial scale. Therefore, we would
advocate the restriction be that the ESS
and/or VRE/ESS projects be registered
and operate as ‘scheduled’ or ‘semi-
scheduled’ as defined by the NER, rather
than a specific rated power output
limitation. Registration with AEMO as
scheduled generation, even though the
NER indicates between 30MW and 5MW
can be semi-scheduled, might be the
preferred criteria.
11 (Page Eligibility: the focus on a Agree land tenure should “demonstrate
18) base level of secure access to land … include a
development status of combination of land ownership, leases,
land tenure, planning and and options to lease” by a signed contract
connection agreement. Agree planning be to
Approvals. “demonstrate an understanding of the
expected planning pathway and planning
approval requirements”. Prefer grid
connection be demonstrated by
completion of the Preliminary Enquiry (or
Pre-feasibility Study) for the project,
and/or submission of a formal Connection
Enquiry to the relevant TNSP.
11 (Page Eligibility: the impact of Agree that participation in other
18) participation in other government schemes as provided in the 5
government schemes on dot points at the top of page 18 of the CIS

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CIS eligibility. Consultation Paper, should not eliminate a
project from eligibility for CIS
consideration.
11 (Page Eligibility: the eligibility of Only existing VRE projects seeking to firm
18) existing projects to bid output by new co-located ESS investment
into the CIS, and or writing of new PPA contracts to support
questions of CIS new ESS deployment, should be eligible
additionality that result for the CIS consideration.
from this approach.
11 (Page Eligibility: the technology The technology needs to be demonstrated
18) risk appetite of the CIS. at a minimum of Technology Readiness
Level (TRL) of 9 or be implementing at a
minimum of Commercial Readiness Index
(CRI) of 2, under ARENA’s project
guidelines.
12 (Page Feedback on: the Stage A criteria should align to the
21) evaluation criteria. greatest extent possible with State
requirements albeit cover the following:
• Technical viability, including firming
services offered and which wholesale
markets will be addressed by the
technology
• Commercial viability (at proposed floor
and ceiling price points)
• Land tenure agreements
• Procurement pathway defined
• GANTT chart of planned FID,
procurement, supply channels,
installation, GPS11 testing, Connection
Agreement, R2 data delivery, and COD
• A risk register
• Demonstrate how the proponent has or
will secure the capability to deliver the
project, including RACI matrix to define
contractual responsibilities
• Social license pathway defined with
initial progress underway
• Local supply chain, local employment,
and local benefits pathways defined,
and draft AIP developed
• Description of how approach meets
State-based policies
Stage B criteria should include the above
and matters raised in the CIS consultation
paper.
12 (Page Feedback on: the On Process: The period between Stage A
21) appropriate structure to decision point by DCCEEW and the point
11
Grid performance standards (GPS) which are AEMO’s testing requirements of a newly installed renewable generation or storage project so that its performance characteristics are fully described for dispatch purposes.

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assess a project’s of submission of Stage B information,
contribution to system needs to a minimum of 6 months, but
reliability. preferably 12 months. Projects which can
provide the information in a shorter period
of time should be accommodated but final
decisions on award should be aligned to
be finalized by DCCEEW at 18 months
post submission of the Stage A decision
point.

On Reliability: Reliability cannot be
modelled dynamically, it is the outcome of
real-time optimization and dispatch of
firmed and unfirmed generation to meet
system demand. However, there are
simplified approaches to modelling
forecast loads and forecast firmed and
unfirmed generation capacity, and
allowing for surplus firmed or dispatchable
generation capacity which should allow
AEMO (or SO) to operate the dispatch
system to meet the reliability standards set
by the NER. We contend that the best way
to ensure AEMO (or SO) has the services
to hand that it needs on a 5 minute basis,
is to have CIS tender participants commit
to those services their VRE, ESS or
VRE/ESS can provide in real time and
which they commit to offer into the existing
energy, FCAS (including FFR), and
emerging markets which could include
under a capacity mechanism, inertia
market or system strength market. The
offer should include the operational
potential of the firmed capacity which can
be delivered at the age and cycle
degradation of the plant, and not at the
rated or nameplate capacity, which will
likely be available only at the early plant
life when it is ‘shiny and new’. This is
particularly relevant wrt ESS technologies.

12 (Page Feedback on: the There are two elements on de-rating
21) potential development which should be included.
and application of de-
rating factors. First the ESS rated power needs to be de-
rated to mid-life output performance to
recognize different technology cycle
degradation as discussed above in point
4.

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Second network congestion will change
over time as transmission lines are built in
accordance with AEMO’s ISP and State
Governments supported investment in
REZ connections. On contribution to
system reliability, the CIS consultation
paper suggests analysis of total
dispatchable and non-dispatchable
capacity will suffice for a reliability
estimate. This is insufficient. Load flow
models are required at least down to zone
substation level in order to identify
changing line congestion over time, and
de-rating & re-rating factors should be
applied for VRE, ESS and VRE/ESS
project locations which increase &
decrease line congestion between REZs
and RRNs, and likewise worsen or
improve MLF values which otherwise
restrict VRE & ESS dispatch.

However, de-rating & re-rating factors
should be set at each CIS tender process
and once the tender outcomes are known,
those factors should not be used for other
economic, pricing or dispatch adjustments.
To do so would introduce further
uncertainty which will dissuade new
investment.
13 (Page Feedback on: the ESS investment must be encouraged in a
22) appropriate structure and manner to 1) shift peak solar and wind
sizing of performance generation to peak load periods, and 2) to
requirements necessary alleviate line congestion at transmission,
to deliver on the policy sub-transmission and distribution voltage
objectives of the CIS levels, and 3) provide FFR and FCAS
without distorting storage services for system reliability and
market participation. performance support. Storage is needed
at all voltage levels in the network. We
believe the CIS will best meet customer
needs when it encourages ESS
investment from 5MW upwards. In very
general terms ESS investment needs to
occur within REZ (likely 100MW+), at
Terminal Stations (likely 30MW to
100MW+), Zone Substations (likely 5MW
to 30MW), and at retiring coal-fired
generation sites (likely 100MW to 800MW
and above). Batteries at lower voltage
levels are best addressed by State

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government initiatives. All ESS registering
for CIS tenders should commit to offering
some or all FFR/FCAS and energy
dispatchable services in relevant existing
and emerging AEMO markets (ie: future
inertia, system strength, voltage control
and other markets implemented in the
NER). CIS support with price floor and
ceiling should be tailored to actual service
provision over a 12-month rolling period,
and withdrawn when requested dispatch
does not occur, but reinstated from future
actual dispatch delivery.
14 (Page Commercial model The floor price may need to change in
26) feedback: the floor price (say) 5-year time increments over the life
support mechanism. of the underwriting agreement, related to
the statistical profile of the wholesale price
data for the preceding 12 months. Pre-
defined & automatic adjustment
mechanisms may be identified before CIS
tendering so that tenderers can adjust
their proposed price points to the defined
adjustment mechanisms. Such adjustment
do however introduce some uncertainty in
future outcomes, so disincentives for
investment need to be carefully weighed
against benefits of adjustments to future
events.
15 (Page Commercial model Different floors should apply to VRE and
26) feedback: the use of a ESS, else the existing contract markets
single net revenue floor will be distorted. This is particularly
for both VRE and relevant to solar PV and peak solar
scheduled generators periods where ESS will seek charging
(including storage). contracts at a low or negative price.
16 (Page Commercial model Maximum tenor should align with the
26) feedback: the term of the technology’s contracted financing tenor.
contract, including
financing requirements
around revenue tenor.
17 (Page Commercial model While proposed approach is reasonable,
26) feedback: the ESS will not likely be able to fully charge
performance with 2-hours’ notice of a LOR 3 event.
requirements, including Capacity available for a LOR 3 event
the LOR3 performance should be set at 90% of the charging
requirements capacity available within the notified time
of the event, provided there are no
congestion limits which prohibit ESS
charging.
18 (Page Commercial model Negotiation of the structure of penalty
26) feedback: the milestone payments should be allowed to ensure

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requirements, penalty projects can share forward net revenues
provisions and between operations and penalty
termination provisions. payments, to avoid forcing insolvency
through a penalty event.
19 (Page Commercial model Agreed.
26) feedback: A contract
structure that divides
development/construction
and operating periods
into two contracts, similar
to the NSW Project
Development Agreement
and LTESA division.
20 (Page Commercial model The CIS should 1) apply only to new
26) feedback: the commercial PHES systems with FID after 31
model’s applicability to December 2024 but before 1 January
pumped hydro energy 2026, and 2) be limited to provision of
systems 10% of each State’s reliability
requirement, or the 2022 ISP PHES %
capacity identified for each State,
whichever is the lowest, and 3) be
allocated between PHES projects in each
State on the basis of their rated output
power (MW).

End of Table Feedback.

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