2022 National Greenhouse and Energy Reporting (NGER) Scheme: proposed updates

Friday, 29 April 2022

Consultation Hub
Department of Industry, Science, Energy and Resources
Australian Government

Dear Madam / Sir

Re: Submission to National Greenhouse and Energy Reporting Scheme – 2022 Proposed
Amendments

I thank you for the opportunity to make a submission as part of the consultation process on the proposed
changes to the way emissions are reported under the NGER scheme. Enabling accurate, meaningful and up-to-
date emissions reporting is critical for governments at all levels as well as for businesses and other
organizations seeking to monitor, report and implement changes that will effectively and efficiently reduce
their own emissions, and the NGER scheme is central to this. I trust that you will give this submission due
consideration when amending the scheme methods.

I restrict my submission to just one topic of the discussion paper and the NGER methodology itself: the
methodology for calculation of scope 2 emission factors for states and territories. This topic is very well aligned
with my area of professional expertise and interest. You will note in the attached submission that I target four
areas that I think require review and adjustment within the scope 2 calculation methodologies, even though
only two of these are highlighted in your discussion paper. I realise that, under normal circumstances, only
those elements of a submission that target the specific items from the discussion paper would usually be
considered. However, the timing is right to consider these additional changes now and I have been considering
approaching the Department about this for some months anyway, and so I would like to encourage you to
consider all three suggestions, most likely as a separate review subsequent to the current proposed
amendments being finalised. As the energy system continues to evolve, it will become increasingly important
that scope 2 emissions are calculated appropriately and used meaningfully by states and territories and
organisations within them; this will benefit significantly from further refinements to the way scope 2 emissions
are calculated and reported under the NGER legislation.

Please find attached my submission, covering the following elements of the NGER Emission Factors calculations

1. Removal of three-year moving average calculation – topic already highlighted in discussion paper
2. Application of more timely data – topic already highlighted in the discussion paper
3. Handling of energy flows between states and territories – topic not covered in the discussion paper
4. Introduction of marginal emissions factors for states and territories – topic not covered in the
discussion paper

Please feel most welcome to contact me directly should you wish to discuss any of this further. I would be only
too happy to provide further information, prepare and present on the topics contained within the submission,
and/or to consult more closely on potential changes that could be made to the methodology and legislation.

Kind regards,

Evan Franklin
Associate Professor of Energy and Power Systems
School of Engineering

School of Engineering Private Bag 65 T +61 412 106 185
College of Science and Engineering Hobart Tas E evan.franklin@utas.edu.au
7001 ABN 30 764 374 782 / CRICOS 00586B
Australia utas.edu.au

Amendments to the National Greenhouse and Energy Reporting scheme.
Consultation submission, Evan Franklin, University of Tasmania School of Engineering, 29
April 2022

Emission Factors (EFs) are valuable metrics used by states and territories to assess and quantify scope 2 GHG
emissions associated with sectors of the economy, local government areas, the activities of businesses and
organisations or all sizes, or other any other activities within that state or territory. Importantly, they are
regularly used for reporting, for decision-making related to new or changed activities, and subsequently for
assessing the impact of such decisions. The intensity of emissions for a given activity can actually vary
depending upon time of day and time of year, and hence emission factors could in fact be time-variable on a
time scale of hours or days. However, this would be unnecessarily cumbersome and unwieldy, and in most
cases would provide little benefit over using average factors over a longer period. The practice of calculating
EFs on the basis of average values on a 12-month basis therefore generally makes sense now and into the
future1.

Given that average EFs are currently used - with one single metric per state or territory per 12-month period
- it is particularly important to ensure that calculated EF values for each state and territory continue to be
calculated accurately and reliably in a rapidly evolving electrical energy system. EFs need to continue to be
useful and meaningful metrics for states and territories, for both reporting and decision-making. But, with
increasing transmission interconnectivity between states and territories, increasing uptake of renewable
generation and, in particular, increasing uptake of storage technologies, the calculation methodology for
determining state and territory EFs will no longer be fit-for-purpose and will require review and update. The
issue relates to the way emissions associated with imports and exports across state boundaries are currently
handled in the calculations, when there is significant storage capacity on either or both sides of the state
boundary and when there is a considerable difference between the emissions intensity of generation in each
state. This issue may not necessarily be immediately evident today in all jurisdictions, although there is
sufficient evidence of it being problematic already for some states. It will almost certainly become
increasingly so over the coming decade. There is considerable benefit in carefully considering and addressing
these issues today.

The current consultation process discussion paper which this submission is responding to, requests
submissions related to a narrow scope when it comes to scope 2 emissions. This submission aims to extend
the discussion beyond that original scope, although it is certainly anticipated that this issue could not be
resolved without a separate, thorough review process.

In this submission, Tasmania as a state is regularly used as an example. This is because the energy system in
Tasmania is unique in Australia, in that it contains very high levels of renewable energy generation and, even
more importantly for the context of this discussion, it already contains very large amounts of energy storage.
In many ways, the Tasmanian energy system represents the future state of energy systems in all other states
and territories, and therefore a useful glimpse into the future. Tasmania is also exposed far more greatly to

1
It is worth noting, however, that even this approximate approach would become flawed under scenarios where the
penetration of renewable energy generation is such that curtailment occurs with consistency and regularity. An energy-
consuming activity deliberately aligned with periods of regular curtailment of solar generation, for example, will result
in far less emissions than the same activity if it were not aligned, yet under average EF arrangements both would
always be attributed with having produced the same emissions as each other.
the limitations of the current EF calculation methodology, and so it provides us with excellent examples of
how different EF calculation methods can produce values which may be either more or less meaningful and
useful.

This submission is arranged to covers the following four elements of NGER Emission Factors calculations:
1. Removal of three-year moving average calculation – topic already highlighted in discussion paper
2. Application of more timely data – topic already highlighted in the discussion paper
3. Handling of energy flows between states and territories – topic not covered in the discussion paper
4. Introduction of marginal emissions factors for states and territories – topic not covered in the
discussion paper

1. Removal of three-year moving average calculation

The removal of the three-year moving average is a generally sensible and positive change, and I support it.
Average 12-month EFs already naturally lag, given that they are calculated and set each year based on data
from the previous year, but the three-year moving average (also rounded) results in an even longer lag and
makes it quite slow and difficult to observe fully the changes to emissions that may have arisen from a given
decision by a state or local government, business or other organisation. A change in demand or generation
of around 50 GWh/year (about 5 - 10 MW) for three years consecutively would be required for any change
to Tasmania’s determined EF value (about 4 times as much needed to change Victoria’s EF).

It should be noted, however, that the three-year averaging approach does currently remove some degree of
market variability, which might be year to year variation (weather-driven, geographically-driven) rather than
structural system changes. An unseasonally hot summer in Victoria for example may generally result in
higher cross-border energy flows into that state than in a normal year, and this can impact the EF for Victoria
(likely not much) and neighbouring states (Tasmania – potentially a lot) even if the net energy flow between
states is the same as for any other year.

It should also be noted that with current EF calculation methodology, removing the three-year averaging
approach when a state imports and/or exports significant quantities of energy compared to total demand,
will likely produce considerably more year-to-year volatility in calculated EF values. This volatility can even
easily mask any other variations which might be expected owing to changes in generation in the state or
energy consumption behaviour of a sector or organisation. Tasmania, which currently has capacity for
imports or exports of up to about one-third of total demand, will see this more than any other state. In the
figure below, the officially reported EF values (blue) for Tasmania for the last 15 years are plotted alongside
EF values calculated similarly from NEM values (albeit with some simplifying assumptions about emission
intensity of generation in each state – being static in these calculations) (orange). With the exception of the
most recent few years there is good agreement, which means that the same calculated values but without
three-year averaging (yellow) provides a good view of the increased volatility that can occur.
Tasmanian electricity emissions factor kg CO2/kWh
0.35 Published EF Figures (DISER)
0.30 Calc'd EF from NEM data with NGER method - 3-year avg
Calc'd EF from NEM data with NGER method - 1-year data
0.25

0.20

0.15

0.10

0.05

0.00

2. Application of more timely data

Using up to date NEM data is a positive change which I support without reservation.

3. Handling of energy flows between states and territories

This is the issue which arguably required the most attention. Total reported EF values by state, under current
methodologies, do not generally account well for electricity transfers between states when there is
significant storage in one or both states. The NGER legislation does provide a method for calculating and
reporting EF for each state and territory, accounting in part for electricity imports and exports between
states. Emissions from exports are subtracted and emissions associated with imports are added when
calculating EF for a given state. This methodology works quite well in the case where exports or imports
result in less or more generation as a whole (across the entire year) in the state, which is usually the case if
there is no means by which a state can store significant amounts of energy.

A simple example: South Australia (lower emissions intensity) has a large battery system. When market
conditions dictate significantly lower prices in Victoria than in SA, it can make sense for the battery operator
to import into SA and store energy in the battery. When prices later in the day dictate it, it may make sense
to export that energy again from the battery and into Victoria. Emissions associated with that energy are
generated in Victoria (at higher emissions intensity) and that energy is used in Victoria. Yet, EF calculations
allocate the Victorian emissions (at average intensity) first to South Australia and then allocate emissions to
Victoria at the SA average intensity. In other words, the time-shifting and geographical nature

Tasmania provides numerous similar examples, which are evident from published data. For Tasmania, a
fraction of Victorian emissions are added into the calculation of EF, giving rise to an EF that can appear
higher than intuitively expected. For example, Tasmania’s EF for the 2020-21 year was set at 0.172, despite

2
NGER data, http://www.cleanenergyregulator.gov.au/NGER/Legislation/Measurement-Determination
Tasmania generating close to 100% of electricity demand from Tasmanian renewable sources3. It is
conceivable, or likely even, that Tasmania’s reported Emissions Factor will increase if those infrastructure
developments that are designed primarily to increase renewable energy generation, increase connectivity
and unlock Tasmania’s hydro flexibility (Marinus phase 1, Tarraleah redevelopment, BoTN) are completed.

Alternative EF calculation methods are possible, which take into account the time-shifting nature of storage
and which better consider the net flow of energy and origins of emissions associated with demand. Rather
than include further analysis of this in the body of this submission, I have included analysis of methods and
emissions associated with EFs in Appendix A. This appendix was prepared with the specific intent of
reviewing the impact of EF calculation methodologies in the Tasmanian context. It highlights the problem
most clearly. I would like to encourage a close read of this appendix, if there is desire to consider this
problem more fully.

4. Introduction of marginal emission factors for states and territories
This would be a large addition to NGER approach for reporting of emissions in states and territories via EFs.
But potentially it could be the most powerful and useful new tool when it comes to enabling better decision-
making relating

The Australian electricity system is planned to become both increasingly connected and increasingly supplied
from renewable sources of energy. This transition is planned to occur over a multi-decade period: AEMO
expects by 2042 that [under high DER / EV uptake scenario] renewables is 75% of generation (up from 28%
today), with the remainder mostly from coal (including with ~40% of Vic generation still from brown coal)4.
Dispatchable storage will facilitate high amounts of renewable generation, meaning that high capacity
factors for solar and wind are maintained, and thus ensuring that they will still rarely be the marginal
generator (apart from perhaps in South Australia).

The marginal generator(s) is the one which will increase or decrease its output if system demand changes.
From an energy and emissions point of view it is the generator or generators that will have produced more
or less energy over a period of time as a result of that system change. Hydro generators are essentially never
the marginal generator from an energy or emissions point of view, since they are energy constrained and
water resource managed over long durations, meaning that any additional output required in one time
interval will be matched by an equivalent lower generation amount over all future time intervals. Until wind
and solar are built to such an extent that they regularly generate more energy than the system can handle
(owing to either demand or transmission constraints), they will rarely act as marginal generators.

Having a good knowledge about marginal generators is important, since it leads to an understanding of the
marginal emitter at different times of the day and year, and therefore enables calculation of a marginal
emissions intensity (or marginal EF) for each region in a system. Making decisions based on average
emissions can lead to poor decisions because a change by definition has its impact at the margin of
generation; making decisions based on marginal emissions gives a truer indication of the impact of a
decision.

Tasmania is again exposed to this more than other states. Market dynamics means that determining the
exact mix annually of marginal energy generation for Tasmania or any other state is quite complicated.

3
For reference, an EF of 0.17 equates to an enclosed electricity system which generates 35 – 40% of electricity from gas
(CCGT) and the remainder from renewable sources.
4
ISP 2020, AEMO, https://aemo.com.au/en/energy-systems/major-publications/integrated-system-plan-isp/2020-
integrated-system-plan-isp
Tasmania’s hydro storage based system makes it even more so, since the effective marginal generator in
Tasmania is often one that is dispatched at a much later time interval. Until solar and wind are regularly
constrained and curtailed in Tasmania or Victoria, marginal generation for Tasmania will come from either
Victorian brown coal or Victorian or Tasmanian gas. The effective marginal EF for Tasmania (average across a
year) is likely in the range 0.6 – 0.8 at present (but considerable work would be needed to calculated this
accurately). This will decrease over the coming decades as the Australian system (particularly in Victoria)
transitions to low emissions generation. A company wanting to change operations to increase electrical
demand in Tasmania and wishing to build new renewable generation to be carbon neutral will make a poor
decision if basing new generation on the currently published EF values.
Appendix A:
Comparison of Tasmanian electricity emissions values from different reporting and
determination methods – detailed analysis on annualised energy flow basis
With Tasmania being electrically connected to the mainland stated (that is, not being a closed system) there
can be no single, definitive emissions value determined for the state. The value used depends upon whether
emissions created in Tasmania only are counted, whether emissions created elsewhere for electricity used
within Tasmania are included or excluded, and whether emissions avoided elsewhere by electricity
generated in Tasmania are included or excluded. This is consistent with the fact that the two formal
greenhouse gas reporting methods in use in Australia yield different emissions attributable to the Tasmanian
electricity sector.

In this appendix, estimates of the emissions associated with Tasmania’s electricity system are examined by
considering the key inclusions or exclusions described above and compared to emissions determined from
the different retrospective greenhouse gas reporting approaches. This comparison is valuable because it
provides insights into the meaningfulness of reported emissions in assessing the impact of changes in the
system, and because it provides some confidence in estimates of Tasmanian emissions under future
scenarios. It should be noted that emissions associated with the electricity system in Tasmania are generally
a minor fraction of total energy system emissions.

Five different values of emissions for Tasmania’s electricity system are presented in this analysis. Data
sources and determination methods are detailed in the table below.

Tasmanian emissions Data source Determination method / Notes / comparisons
value (Mt / year) inclusions and exclusions
Reported Emissions in State and Territory Greenhouse Inventory value reported for
national accounts Gas Inventories, National Tasmania for ‘Energy
Greenhouse Accounts5 Industries’ consists of
electricity generation only
Calculated Tasmanian AEMO - electricity produced by ‘Generation from Tasmanian Should yield similar
emissions, all Tasmanian generators6; generators’ x ‘emission value as Reported
electricity generation Clean Energy Regulator – intensity factors per Emissions; small and
within Tasmania generator emission intensity generator type’ remote generators
factors7 not included here
Calculated Tasmanian As above, but also including ‘Generation from Tasmanian Emissions higher in
emissions, all electricity imports and exports generators NOT exported’ x years with high
electricity used in to Victoria ‘emission intensity factors per imports from Victoria
Tasmania (including generator type’ + ‘Generation (even if exports
imports) imported to Tasmania’ x match imports)
‘Victorian generation
emission intensity factor’
Calculated Tasmanian As above ‘Generation from Tasmanian All Tas demand first
emissions, energy generators NOT exported’ x attributed to Tas
balance required in ‘emission intensity factors per renewable
Tasmania (net of generator type’ + ‘Balance of generation; imports
imports & exports) imports less exports’ x netted against
exports counts

5
National Greenhouse Accounts 2019, https://www.industry.gov.au/data-and-publications/national-greenhouse-
accounts-2019
6
https://opennem.org.au/energy/tas1/?range=all&interval=1y
7 http://www.cleanenergyregulator.gov.au/NGER/National%20greenhouse%20and%20energy%20reporting%20data/ele
ctricity-sector-emissions-and-generation-data
‘Victorian generation avoided Victorian
emission intensity factor’ emissions; 100% RE
Tas = zero Tas
emissions
Attributable Clean Energy Regulator – Scope ‘Annual Tasmanian electricity Difference between
Tasmanian emissions, 2 state Emission Factors8 demand + losses’ x ‘Reported this and Reported
using Reported Tasmanian Emission Factors’ Emissions in national
Emission Factors accounts highlights
problem with
national accounting
methods for energy
exchange between
states
Attributable AEMO - electricity generation, ‘Annual Tasmanian electricity Should yield similar
Tasmanian emissions, imports and exports9; demand + losses’ x ‘Calculated value as Attributable
using calculated Clean Energy Regulator – Tasmanian Emission Factors’; Tasmanian emissions
Emission Factors generator emission intensity Emission Factor calculated using Reported
factors10 based on National Emission Factors
Greenhouse and Energy
Reporting methodology11 Reported values are
Financial Year; this
appendix uses
Calendar Year

Comparison of Reported Emissions and Emission Factors with Calculated Emissions and Emission
Factors
Nationally reported Tasmanian electricity sector emissions values are plotted in Figure 1, and compared with
our calculated emission quantities, which are based on generator emission intensities factors and annual
generation amounts. We also plot in Figure 2 emissions based on application of Emission Factors to the
entire electricity system, both those reported nationally each year and our calculated values. In both plots
we can see generally very good agreement between reported values and our own calculated values, giving
confidence that these and subsequent calculated values provide a reasonable basis for evaluating emissions.

Differences between reported and calculated values can mostly be attributed to the use in calculations of a
single value for emissions intensity factors for each generator / fuel type in Tasmania (hydro, wind, gas –
OCGT, gas – CCGT), rather than using values which change from year to year, with time of year and with
generator output. Auxiliary power station emissions are also ignored in calculations. A more detailed
analysis, calculations based on time series data rather than annualised values, should improve accuracy if
required. Note that 2020 data has not yet been reported, but our calculations indicate that Tasmanian
electricity emissions will be significantly lower than 2019 figures.

Comparison too can be directly made between the emissions quantities reported ( or calculated) for
generation sources located within Tasmania (Figure 1), and emissions for the Tasmanian electricity system
determined by application of Emission Factors (Figure 2). It is immediately obvious that the two reporting

8
NGER data, http://www.cleanenergyregulator.gov.au/NGER/Legislation/Measurement-Determination
9
https://opennem.org.au/energy/tas1/?range=all&interval=1y
10 http://www.cleanenergyregulator.gov.au/NGER/National%20greenhouse%20and%20energy%20reporting%20data/ele
ctricity-sector-emissions-and-generation-data
11
https://www.industry.gov.au/sites/default/files/2020-10/national-greenhouse-accounts-factors-2020.pdf
methods yield very different determinations of Tasmanian electricity emissions, highlighting the
shortcomings of either one or the other (or both) when used for evaluation of state-based emissions.

Tasmanian electricity system emissions (Mt CO2 per year)
1.2
Reported Emissions in national accounts
1.0

0.8

0.6

0.4

0.2

0.0
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Figure 1. Comparison of annual Tasmanian electricity emissions, reported in national accounts and calculated based on generation in
Tasmania and generator emission intensities.

4.0 Tasmanian electricity system emissions (Mt CO2 per year)
Attributable Tasmanian emissions, using Reported Emission Factors
Attributable Tasmanian emissions, using calculated Emission Factors
3.0

2.0

1.0

0.0
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Figure 2. Comparison of emissions attributable to Tasmanian electricity system, based on reported and calculated Emission Factors.

Inclusion of emissions owing to electricity generated elsewhere and of avoided emissions elsewhere
The nationally reported emissions figure for Tasmania (previous plots) is not a particularly useful metrics in
the case where a significant amount of import or export takes place to or from Tasmania – which is currently
often the case and which is planned to be increasingly so. A more meaningful metric is one which also
includes the emissions associated with imports.

The annual emissions plot of Figure 3 now includes calculated emissions values based on the inclusion of
emissions associated with electricity imports (second, or aqua coloured, column), calculated emissions based
on inclusion of both emissions and avoided emissions as a result of the net balance of imports and exports
(third columns, grey-blue), plus also electricity emissions attributed to Tasmania based on Emission Factors
(fourth columns, green). For the sake of maintaining clarity on charts, nationally reported emissions figures
are not plotted on this or subsequent charts, since our calculated values are sufficiently similar for the
purposes required. Note that the inclusion of emissions produced elsewhere owing to Tasmania’s electricity
needs being met by imports but not considering the benefits of avoided emissions from exports (second,
aqua column) should not be considered a fair, equitable or useful measure of Tasmania’s electricity
emissions. But we include it here because it corresponds exactly to the values determined using the formal,
published national Emissions Factor methodology; the only difference between the two columns (aqua and
green) is that EF values are 3 year averages based on prior financial years, whereas our calculated emissions
from generation + imports is calculated from data for each calendar year.

Tasmanian electricity system emissions (Mt CO2 per year)
4.0 Calculated Tasmanian emissions, all electricity generated within Tasmania
Calculated Tasmanian emissions, all electricity used in Tasmania (incl. imports)
Calculated Tasmanian emissions, balance required in Tasmania (net of imports & exports)
3.0 Attributable Tasmanian emissions, using calculated Emission Factors

2.0

1.0

0.0
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

-1.0

-2.0

-3.0

Figure 3. Comparison of historical emissions attributable to Tasmania’s electricity system, based on the four different determination
methods. Only one approach is capable of reflecting a system that has negative sector emissions (that is, where the Tasmanian
system causes net avoided emissions elsewhere); this is not possible with the current formal accounting approaches used in Australia.

The comparison of emissions determined via these different approaches (two of them based on formal
national reporting methods) highlights some very important key differences. Emissions reported according
to national inventories (first, dark blue column) are considerably lower than other measures of emissions for
most years, because other measures take into required electricity account imports, which are closely
associated with combustion of brown coal in Victoria. In 2006 – 2009 and again in 2015, for example,
Tasmania’s formally reported electricity emissions are quite low (almost 0 in 2015 when there was almost no
gas-fired generation in Tasmania); but, large quantities of electricity were imported from Victoria in those
years, meaning actual emissions owing to Tasmania’s electricity system are in fact quite high.

Tasmanian electricity emissions determined by including emissions both produced and avoided owing to net
energy balances (third column, grey-blue), is the only method which accurately describes Tasmania’s
electricity system emissions on a whole of system basis. No other method, including both of the formal
national accounting approaches currently in use, can accurately reflect the emissions owing to the
Tasmanian system and no other method can capture the genuine global emissions impact of system changes
such as electrification of transport, widespread uptake of rooftop solar or development of hydrogen
electrolysis industries. A 200% TRET, for example, which is generally considered as a means for the
Tasmanian electricity system to contribute to global emissions reductions by becoming a net negative
emissions system, can only possibly be described as such by the method which we newly propose here. In
contrast, both current reporting methods will see Tasmania’s formally reported electricity emissions remain
about the same or even increase, depending upon market dynamics and the temporal operation of a
Tasmania-Victoria interconnect.
Estimating emissions (real and reportable) under future scenarios or counterfactuals
We have established that emissions reporting using either national state and territory inventories or using
national greenhouse reporting Emission Factors will lead to an inaccurate or incomplete determination of
Tasmanian electricity emissions and hence a misleading assessment of the emissions impact of any changes
to the Tasmanian energy system. In contrast, a measure of emissions attributable to the Tasmanian
electricity system which includes net balancing of interstate energy flows and the associated produced or
avoided emissions, provides a suitable measure for the Tasmanian system and therefore also a means to
evaluate the whole-of-system emissions impact of system changes. We demonstrate this by examining again
the emissions determined via these different calculation methods for five future or counter-factual scenarios
based on anticipated or alternative system generation and demand patterns. The conditions for these five
scenarios are presented in the table, with the resulting determined emissions plotted in Figure 4, alongside
recent year emissions. We omit the emissions value calculated considering imports only, both because it has
already been shown to be an incomplete measure but also because it yields the same value as that
determined using Emission Factors.

Scenario Brief Description Scenario Details
Name
2020-EV Current system plus full Same Tasmanian generation (2020 figures)
electrification of transport Total demand increased by ~30% via full electrification of transport12
Interconnect energy flow as per 2020, with adjustment to meet demand
balance
2036a Based on Project Marinus Tasmanian generation, demand and interconnect energy flows all as per
modelling, 2036 – Without FTI Consulting modelling outputs for ‘Without Marinus’ case in 203613;
Marinus Average Victorian marginal emissions intensity reduced by 50% in 203614
2036b Based on Project Marinus Tasmanian generation, demand and interconnect energy flows all as per
modelling, 2036 – With FTI Consulting modelling outputs for ‘With Marinus’ case in 2036;
Marinus Average Victorian marginal emissions intensity reduced by 50% in 2036
2040a System with 200% TRET and 200% TRET generation target met; Tasmanian demand unchanged; 1500
no transport electrification MW Marinus and BoTN pumped storage operating, with average 3 hours
full interconnect import per day;
Average Victorian marginal emissions intensity reduced by 50% in 2040
2040b System with 200% TRET and 200% TRET generation target met; 30% Tasmanian demand increase (full
full transport electrification electrification of transport); 1500 MW Marinus and BoTN pumped
storage operating, with average 3 hours full interconnect import per day;
Average Victorian marginal emissions intensity reduced by 50% in 2040

12
~30% demand increase is also approximately equivalent to a 500 MW H2 electrolyser operating at 70% capacity
factor, and is approximately equal to the maximum additional load that a fully exporting Basslink could support.
13
Data in Figure 6 of Marinus 2021 Wholesale Pricing Report: https://www.marinuslink.com.au/wp-
content/uploads/2021/06/Wholesale-Pricing-Report-How-do-customers-benefit-from-Project-Marinus.pdf
14
This is possibly an optimistic figure, given the expected generation mix for Victoria given in AEMO’s ISP 2020 figures
for 2040 generation and capacity. The actual average marginal emissions intensity, applicable for Tasmanian import
emissions, could be considerably higher than the 50% value used in these scenarios.
Tasmanian electricity system emissions (Mt CO2 per year)
4.0

3.0

2.0

1.0

0.0
2015 2016 2017 2018 2019 2020 2020-EV 2036a 2036b 2040a 2040b
-1.0

-2.0

-3.0 Calculated Tasmanian emissions, all electricity generated within Tasmania
Calculated Tasmanian emissions, balance required in Tasmania (net of imports & exports)
-4.0
Attributable Tasmanian emissions, using calculated Emission Factors
-5.0

-6.0

Figure 4. Emissions attributable to Tasmanian electricity system, both over recent years and then for five different defined scenarios,
using the four different emissions determination approaches.

We immediately note three key observations:

1. Actual, whole-of-system emissions (grey-blue column) owing to the electricity sector would increase
markedly with the electrification of transport or for an equivalent demand increase due to H2
electrolysis (2020-EV compared with 2020), if no additional renewable generation was built that would
not otherwise have been. This is despite electricity system emissions as reported in the official state and
territory inventories suggesting no change to emissions (dark blue). Meanwhile, determination of
emissions attributable to electricity in Tasmania by applying Emission Factors to the whole sector
(green) will yield the same value as our whole-of-system emissions calculation. This is because imports
increase considerably under this scenario, and hence Tasmania’s Emission Factor increases to 0.3. For
reference, a closed system with an Emission Factor of 0.3 is equivalent to two-thirds of all electricity
being produced by CCGT power stations. It is important to note that, although electrification of
transport sees an increase in emissions owing to Tasmania’s electricity system, the reduction in
emissions owing to reduced petrol and diesel combustion will offset this increase plus add some small
net reductions (in the order of 20% reduction overall in transport emissions).
2. For the two key scenarios representing the outcomes of TasNetworks’ Marinus project market
modelling (2036a – Without Marinus, and 2036b – With Marinus), we see that official greenhouse gas
reporting methods, whether using national inventories or using state-based Emission Factors, both
show a reduction in reported emissions compared to today but still show positive emissions associated
with Tasmania’s electricity system. Furthermore, the implementation of Marinus (and associated
additional wind generation in Tasmania) provides next to no benefit at all in terms of Tasmania’s
reportable emissions, using either of these methods; benefits instead are accrued in Victoria’s emissions
reporting. In contrast, the determination of emissions owing to Tasmania’s electricity system when
impacts of net energy imports and exports are considered, shows negative emissions in both cases.
With this emissions calculation method, the emissions benefits of building Marinus and additional wind
generation in Tasmania are also reflected in Tasmania’s net system emissions. These two scenarios
serve to highlight the benefits of using a whole-of-system approach to assessing Tasmania’s emissions.
3. Under the two scenarios analysed where a 200% TRET is achieved by 2040 (so that additional wind and
solar generation, Marinus stage 1 and 2, and Battery-of-the-Nation are all in place), we can observe
firstly that conventional emissions accounting and reporting methods either show no impact at all from
Tasmania’s efforts in developing the energy system to reduce global emissions or in fact can show a
negative impact. Using Emission Factors proves inadequate as a measure for electricity sector or any
sub-sector or uses of electricity in Tasmania, since it is determined not by the net renewable energy
generated in Tasmania or by avoided emissions resulting from that, but rather is determined by the
volumes of exchanged energy to/from Victoria. Battery of the Nation and other system flexibility
developments, that are designed largely to facilitate exchange of energy to/from mainland states in
order to enable higher renewable generation everywhere, will essentially lead to higher Emission
Factors in Tasmania the more successful they are in fulfilling their objective. Finally, the impact of
electrification of the transport fleet (or equivalent H2 production) in Tasmania can be seen to still have a
considerable impact on whole-of-system emissions even in 2040 (although less than today), because
reduced export of renewable energy from Tasmania results in more emissions occurring in Victoria; in
2040 Victorian electricity system is still expected to be supplied 40% by brown coal fired generators.
Both currently used formal reporting methods, meanwhile, misleadingly suggest positive and
unchanged emissions regardless of this system demand change in Tasmania; the extra emissions, which
do of course result, would instead appear in Victoria’s reported electricity system emissions figures.

The value of a whole-of-system approach to emissions reporting and to assessing the impact on emissions of
key system changes is very clear. Although large system changes (eg. full electrification of transport, large
scale hydrogen production) are used here to illustrate the shortfalls or benefits of different emissions
calculation approaches, the emissions impact of a smaller system demand change is identical in nature and
will be simply scaled accordingly. In other words, even building a 10 MW electrolyser or replacing 10,000
cars with electric vehicles tomorrow, or indeed anytime in the next couple of decades, will result in an
increase in whole-of-system emissions owing to the Tasmania electricity system, unless additional renewable
generation is built (in Tasmania or indeed elsewhere in the system) that would not otherwise be the case.
Current emissions reporting methods will simply not accurately capture this impact, in the same way that
they won’t adequately capture the emissions benefits for Tasmania of building new wind and solar energy.