Electricity Demand and Generation
Scenarios
Submission to the
Ministry of Business, Innovation and Employment
From Contact Energy
This submission by Contact Energy Limited (Contact) responds to the invitation from
the Ministry of Business, Innovation and Employment (the Ministry) for submissions on the
Electricity Demand and Generation Scenarios (EDGS) discussion paper.
We consider the EDGS to be an important document, not least because this document will
form the basis for future grid investment.
For any questions relating to our submission, please contact:
Catherine Thompson | Regulatory Affairs Manager
Contact Energy | DDI: 64-4 462 1130 • Mobile: 0274 399 676
Submission template:
Your details
Organisation Name
Submitter Name (on
behalf of
organisation)
Date of Submission
Does this
submission contain
confidential
information
Contact Energy Limited
Catherine Thompson, Regulatory Affairs Manager
Question
Answer here – cells expand downward
Q1. Do you agree with
the Ministry‟s
assessment of what
the key EDGS
assumptions are?
Contact generally agrees with the Ministry‟s assessment. However
we would encourage the Ministry to consider using differential
exchange rates for any plant built within the next five years, as near
term forecasts for exchange rates are above their long-run average.
Wednesday 8 August 2012
No
We support the Ministry continuing to produce sectoral demand
forecasts (that is, residential, business, industrial, large industrial).
Q2. Are you
comfortable with the
overall demand
forecasting approach
for the EDGS,
including the use of
Transpower‟s
ensemble model for
peak demand
forecasting?
Yes, however we consider it important that the Ministry understands
that Transpower‟s focus and objectives may differ from the Ministry‟s.
Accordingly, their forecasts may reflect a different view to the
Ministry.
In order for models to be replicated by all stakeholders, we
encourage the Ministry to make available detailed methodology
documents, so model replication does not require particular software
(for example, GAMS or MATLAB).
We support Transpower continuing to publish and make easily
available the methodology and models behind their forecasts.
Q3. Do you have any
contrasting views on
demand growth and
assumptions?
Yes. We note that there has been no material growth in either peak
megawatts (MW) or energy gigawatt hours (GWh) since 2007, and
industrial demand could quite possibly fall. Therefore, a realistic
assumption, and one that in our view should be considered in the
scenarios, is that demand will remain flat or decrease. The proposed
scenario is just „lower demand growth‟ (in Table 4) – it is important
that the implications of flat demand are also carefully considered.
Similarly we would be interested in seeing how well the proposed
demand model performed historically – for example, over the past 20
years. This will provide an estimate as to the reliability of the model.
For example, we would be interested to know if the model was a
good forecast of demand over the past five years given the GDP and
population outcomes.
Question
Answer here – cells expand downward
Q4. These scenarios
reflect the Ministry‟s
views on new
generation costs and
availability. Given that
these scenarios will be
used for transmission
investment planning,
do you agree that the
general scenario
themes cover a
sufficient range of
uncertainty?
In Contact‟s view the generation scenarios, the rationale for them and
the format of the output are not well explained and the range of
scenarios is too narrow.
In particular, the scenarios do not reflect some of the issues that are
starting to emerge in the market: for example, a surplus of gas and a
falling gas price.
This may lead to additional thermal generation in the short term,
which, depending on where any thermal generation is located, may
also create the need for new transmission capacity.
Although these scenarios cover a range of possible outcomes, their
top-down nature makes it difficult to assess how likely each scenario
is and therefore what uncertainty they actually cover. The approach
to demand forecasting can be understood as bottom-up forecasts,
accounting for variability in key drivers (for example, the eight
scenarios currently published in the Energy Outlook (+/- GDP, +/exchange rate, +/- oil price, +/- carbon price)) and possible step
changes.
Paragraph 51 gives the impression that the four generation scenarios
are instead top-down views based on possible end points, for which
supporting conditions are then sought as inputs to GEM.
The generation scenarios could instead be built bottom-up based on
different input assumptions such as cost (for example, low wind cost,
high thermal cost). This would be an alternative to the four scenarios
on two output dimensions (low/high thermal, wind versus
geothermal).
One approach would be to create versions of Figure 3 (LRMC of new
generation) under various scenarios of the demand modelling input
parameters (for example, exchange rate impact on wind, and carbon
price impact on thermal). The same variables used in demand
modelling (noted above) could then be varied to generate scenario
outcomes.
As these scenarios are used for transmission planning, it is important
that the thermal scenarios include both baseload thermal and
peaking plant.
Additionally, demand-side response should be modelled as an
alternative to new peaking generation. The GEM schedules in new
peakers to meet peak demand. However, demand response may be
more economic. We are also unsure what the modelling means for
transmission requirements.
In terms of the current approach, we don‟t agree with the
characterisation of wind and geothermal options as being at
alternative ends of the spectrum. It is more likely that there will be a
mix of both depending on the economics of different wind and
geothermal sites. This reflects in part the reduction in wind build costs
Question
Answer here – cells expand downward
over the past year. However, wind cannot be developed in isolation
and some form of balancing generation will also be required.
It is worth highlighting that Table 2 provides an overly optimistic
scenario for potential future generation given that generators have
announced that a number of consented projects are not expected to
proceed, and the high proportion (over 50%) of „generic‟ proposals
included in the table.
Q5. Do you have any
specific feedback on
the proposed EDGS
capital cost
assumptions sourced
from the report: 2011
NZ Generation Data
Update?
Q6. In GS4, the
Ministry will adjust the
relative costs of wind
and geothermal to
favour wind. Do you
agree that there is
enough uncertainty
between the relative
costs of these
technologies to make
this adjustment in one
of the generation
scenarios?
Q7. Do you have any
views on potential
geothermal resources,
“consentability” and/or
how the Ministry could
model these
uncertainties?
Q8. Do you agree with
the Ministry‟s views on
gas market scenarios?
We are willing to engage with the Ministry on our view of capital costs
of projects on a commercial in confidence basis.
The more relevant scenario might be investigating how the mix of
peakers and hydro might interact with baseload or must-run
generation, such as wind and geothermal, to meet base and peak
demand. This is likely to be more important in determining build order
than baseload demand given the existing generation oversupply in
the market.
In our view the geothermal resources described look optimistic based
on current technology.
Modelling geothermal resources requires an estimate of the size of
the field, the ability to access it, the cost of development, and the
consentability.
The real issue is not the availability of gas but the price at which gas
is available. If a high oil price encourages significant exploration and
resulting higher gas supply, this is likely to drive the gas price down
significantly.
Commentators have suggested a gas price of ~$4 to $5 per gigajoule
(GJ) is quite plausible over the medium term.
While Figure 6 shows gas at a price below $7 per GJ, the Ministry
has only discussed gas prices of more than $7 per GJ. The Ministry
should consider what might happen in a situation where the gas price
is considerably lower than this and break down Figure 6 further to
reflect production below $7 (for example at $4 to $5; $5 to $6; and $6
to $7).
Question
Answer here – cells expand downward
Q9. Do you agree with
the Ministry‟s approach
to carbon price
assumptions?
No. The carbon price assumptions appear to be quite out of step with
the market. This may be because the carbon prices relied upon are
predictions from 2010/2011 and the market has moved significantly
since, not least because of the global financial crisis (GFC) and the
lack of any binding Kyoto obligations being in place. Given the
current glut of units, it is hard to see prices rising to the cost of
abatement.
In a situation of sustained oversupply, more expensive discretionary
generation may reduce production. This may be broader than just
Huntly.
Q10. Is there anything
else the EDGS should
consider in relation to
existing thermal
generation or coal
prices?
Q11. The Ministry‟s
assessment of the
likely price and
demand effects is
based on
understanding
developed through the
Energy Outlook
process. Have there
been any other
considerations omitted
from this discussion?
The scenarios appear to be mixing input costs and resulting
electricity price effects. They appear to be saying, for GS3 for
example, that if gas costs are high, not much thermal would be built
or used and wind would set the price, and so the electricity price
would be high. This does not necessarily follow from the gas price
assumption.
At a very simple level, new-build thermal costs are typically higher
than wind or geothermal. Therefore:
a high thermal scenario is likely to lead to higher electricity
prices given its higher LRMC relative to wind and geothermal
in a low thermal scenario the price increases are likely to be
lower.
This is the opposite of what is described in the scenarios.
Q12. Table 4
summarises the
Ministry‟s proposed
EDGS assumptions.
When considering the
assumption set as a
whole, do you have
any specific
comments?
With reference to the response to Question 4, it is not clear how
probable each of the four scenarios are, or even if they cover the
most probable outcome. It seems that a more bottom-up approach
that considers the key input assumptions and looks to vary them (as
described above) would enable the Ministry to develop a central /
most likely generation scenario, with reasonable variations in key
input variables leading to alternate scenarios.
Whereas demand forecasting has central forecasting and p90
predictions on which to base investment decisions, it is not clear how
the currently presented generation scenarios could be used for
similar decision making.
If you wish to make any further comments or suggestions please include them in the
following box:
We wish to make two further comments:
1. In a number of cases there is an overlap between the work being undertaken by the Ministry
of Business, Innovation and Employment (MBIE), the Electricity Authority and the Gas Industry
Company (GIC). To avoid unnecessary duplication and ensure the best outcomes we would
encourage collaboration between these organisations.
2. The Current HVDC pricing methodology discourages investment in new grid-connected
capacity in the South Island. As such we expect to see more electricity transferred from the
North Island to the South Island which will require grid investment and tests that recognise this
ensuing generator investment pattern.