Draft Grid Planning Assumptions (GPAs) released in May 2007 - generation scenarios

Please note the information on this page is now out of date but is retained as a matter of public record. 

• Generation scenario outlines
• Modelled generation projects
• Generation scenarios - methodology
• Generation scenarios
  

The Commission has now completed its review of submissions and of further development work, and each of the four generation scenarios it has adopted is set out below. The scenario names and descriptions have been changed since the consultation.

• Primary Renewables (formerly known as Renewables): Government policies strongly discourage the development of fossil-fuel-based generation. Combined with a constrained gas supply, this leads to the development of renewable options. Geothermal, hydro and wind generation all feature strongly, with the majority of the new hydro projects being located in the South Island, but all the geothermal and most of the wind in the North Island. In the later part of the scenario, both renewable and thermal projects are added to provide peaking capacity in the North Island (including pumped and peaking hydro schemes, and gas- or oil-fired thermal units). Demand-side measures also contribute to peak management.

• South Island Surplus Renewables (formerly known as South Island Surplus): This is a variant of the Primary Renewables scenario, and is similar in many respects (with a strong emphasis on geothermal, wind, and hydro generation). The key difference is that in the SI Surplus variant, the Tiwai Point aluminium smelter ceases operations with a gradual phase-out from 2014 to 2019. The results include increased northward power flows, and delays in generation build relative to the Primary Renewables scenario . The scenario also includes the development of marine generation projects in the 2030s.

• Mixed Technologies (formerly known as Coal and LNG): Government policies provide more moderate support to renewable generation. A mixture of generation technologies is the result, with a substantial amount of new coal-fired generation (black coal in the North Island and lignite in the South), as well as moderate amounts of geothermal, wind, and hydro. Towards the end of the scenario, expensive but plentiful imported LNG is available, allowing the development of more gas generation. Demand-side measures also contribute to peak management.

• High Gas Discovery: Timely and extensive exploration for gas leads to a relatively unrestricted supply of natural gas at prices similar to today's. Major new gas-fired power stations are constructed, with five new CCGTs installed by 2026 (including Huntly e3p and Otahuhu C). Government policies supporting renewable generation also encourage the development of geothermal resources, and, to a lesser extent, wind and hydro power. Demand-side measures contribute to peak management. This scenario would imply the lowest power prices for consumers.

The Commission Board has also discussed the probability weighting of the scenarios. The Board agreed that the two renewables-based scenarios (Primary Renewables and South Island Surplus Renewables) should receive a 70 per cent weighting collectively, with the remaining 30 per cent weighting for thermal (Mixed Technologies and High gas discovery) scenarios (15 per cent for each scenario).  The two renewables-based scenarios would be weighted 50 per cent Primary Renewables and 20 per cent South Island Surplus Renewables. 

The Board’s rationale for this was due to the apparently reduced prospect of the Tiwai Point aluminium smelter closing, plus the likely effect of the Government’s declared intention to encourage the development of renewable generation.  In a scenario sense, the combination of a renewables-based and lower South Island demand future is given a higher weight than a thermals future.

Current, committed, and possible future projects that the Commission will be including in the generation expansion modelling are described below. 

• Current projects  xls [22KB]   (updated May 2007, since superseded)

Note that some embedded generators are not included. This is legitimate as the Commission demand forecast is net of embedded generation. Some embedded plants are included, typically the more major ones. Therefore, the demand figures that will be used in the model have been adjusted upwards to compensate.

The committed projects which will be included in our generation expansion modelling are:

• Southdown E105  (45 MW of gas thermal, heat rate of 8.95)
• Huntly e3p  (385 MW of gas thermal, heat rate of 7.08 – PBA reportpdf [643 KB])
• Tararua III  (93 MW of wind)
• White Hill  (58 MW of wind)
• Deep Stream  (5 MW of hydro)
• Ngawha 2 (17 MW)
• Kawerau (80 MW of geothermal)

Commissioning dates in 2007 will be assumed for these projects, except for Southdown E105, which will be modelled as a current project, and Kawerau, which is assumed to commission in 2008.

The Commission has collated a list of possible future projects for the scenario modelling, based on public information, commissioned external documents, and information from submissions. These include specific projects currently under consideration, 'generic' projects associated with a region rather than a specific site, and some potential sites for hydroelectric plants which are not known to be under consideration currently.

• List of projects .xls [109KB]  - updated 11 May 2007, since superseded

A key input to these list of projects was the following report by PBA, providing information on existing and potential thermal, geothermal, wind, and hydro schemes.

• PBA electricity generation database pdf [1950 KB]

Feedback from submitters was also taken into account when preparing the list of projects.

Recent changes to the list of projects include the following:

• Operations and Maintenance costs have been reviewed, leading to reductions for geothermal, thermal, and hydro projects.  O&M costs for wind projects were also reviewed, but have not been changed;
• many small and/or non-cost-efficient hydro projects have been removed from the list of modelled projects;
• some duplicate wind projects, and some wind projects no longer under consideration, have been removed from the list of modelled projects;
• many 'generic' thermal and geothermal projects have been added (i.e. indicative potential projects with no specific name or location);
• generic open cycle gas turbine peakers have been added to contribute peak capacity in scenarios where this is required;
• several generic wave-power projects have been added to the list of modelled projects (these are only for use in the Primary Renewables scenario, and may only be included after 2030);
• there has not been an overall alteration to wind capital costs, as suggested by some submitters. However, in each scenario, a subset of wind and hydro projects has been selected to have lower capital costs, on the basis that generators will be able to identify and develop projects which will have better cost/benefit ratios than shown;
• demand-side response has been treated as a potential 'generator' and added to the list of modelled projects;
• costings and other parameters for many specific projects have been revised.

Most modelled projects are based on technologies currently in use in New Zealand – coal, combined and open cycle gas turbines, hydro, wind, and geothermal - with three exceptions:

• A generic pumped hydro scheme, for potential inclusion in one of the renewables-based scenarios, and speculatively located in the central North Island.  From the point of view of the scenarios, this scheme would have the benefit of providing firm capacity at peak, as well as shifting load from peak to off-peak periods.
• Several wave energy projects, for inclusion in one of the renewables-based scenarios, becoming available from 2030 onwards.  Costings are set well below current levels, implying considerable technological and market development.
• Two potential lignite plants, located in Southland and Otago, for inclusion in one or both of the thermal-based scenarios.

Note that the project lists do not include relatively small embedded plant but that an implicit assumption is made in the energy demand forecast that the contribution from embedded plant is maintained at current proportions. 

Some grid-connected projects have been designated as not yet committed but 'highly likely' to be constructed in the near future, based on information from the draft Annual Security and Reserve Energy Needs Assessment.  These projects are scheduled to occur during the first few years of the generation scenarios.  Each scenario only includes a subset of the 'highly likely' projects, and no 'highly likely' project occurs in every scenario (since they are not yet committed and any individual one may not go ahead).  The assignment of these 'highly likely' projects to scenarios is intended to be credible and consistent with the scenario 'stories', but, within these constraints, is somewhat arbitrary. 

As an example of the deployment of ‘highly likely’ projects, the Primary Renewables scenario includes the 156 MW Unison wind farm in Hawkes' Bay in 2008, a 40 MW expansion to the Rotokawa geothermal plant in 2009, two unnamed 80 MW geothermal plants in 2010 (one located in the central North Island and the other in the Bay of Plenty region), and a 200 MW unnamed wind project in 2010 (located in the Bunnythorpe area).

has been developed.  GEM is a mixed-integer linear programming model and is used to find a cost-minimizing schedule (timing and location) of new generation capacity to meet energy and incremental peak demand forecasts given assumptions about the cost and operating characteristics of modelled projects.

The generation scenarios are cross-checked in two ways.  The potential implications for transmission investment are examined using regional peak demand forecasts and a model based on an inter-regional representation of the transmission system.  Potential transmission investments are identified and modifications to the location of projects are considered.  SDDP is also used to simulate more detailed outcomes, with a particular focus on unserved energy, the use of hydro storage and HVDC flows.  Adjustments to the generation scenarios are considered in order to accommodate any issues that emerge.

A notable feature of all the scenarios is the extent to which capacity is added to meet peak demand requirements rather than to meet overall energy requirements.  This outcome suggests that the New Zealand power system may be in transition from an "energy constrained" system to a "capacity constrained" system as a result of the emphasis on base-load plant over the last 15 years and the emphasis on base-load and intermittent plant in each of the scenarios.  The effect is particularly marked in the Primary Renewables scenario where generation from low emission projects is assumed to be preferable to future thermal plant, while also displacing output from some existing thermal plant. 

Fuel limits and prices for each scenario are detailed below. The gas prices trend to the prices shown by 2020, starting from the 2006 price of $5.50/GJ.

Gas supply constraints are based on information on forecasts of future gas supply obtained from Power Projects Limited.

• Future Gas Supply pdf [1162 KB]

Carbon charge is one of the key levers used to change the relative merits of modelled generation projects.  The table below summarises the assumptions made for the scenarios.

For the Primary Renewables and SI Surplus Renewables scenarios, a high carbon charge of $40/t is modelled. This figure is not necessarily considered to be probable; rather, it is used as a means of incorporating into the model a range of possible measures which would combine to favour renewable generation over thermal. The carbon charge is assumed to be phased in over 2012-17 period, to reflect the fact that the effect on relative plant mix would likely not be instantaneous, and to limit the rate of substitution of new renewables projects for existing thermal plant.

Since consultation, the Commission has considered further the carbon charge assumption. As a result, the ‘Coal’ scenario has been replaced by a ‘Mixed Technologies’ scenario, with carbon tax raised from $0 to $15/t, and expensive but plentiful imported LNG available in the later part of the scenario.  Essentially this scenario represents the possibility of dependence on imported fossil fuels.

The rationale for this change is that the draft ‘Coal’ scenario seemed too extreme, with very large volumes of coal generation introduced, and little gas or renewables.  It was considered that a major contributor to this problem was the somewhat extreme assumption of no carbon charge (or other measures favouring renewables).  Accordingly, a moderate carbon charge of $15/t was introduced; the use of renewables increased accordingly.  The LNG supply was added to introduce further diversification, and because the Commission considered that at least one of the four scenarios should include the construction of an LNG terminal.

If a cap and trade system was to be introduced, the results would be very similar to what the Commission has modelled, depending upon the price that the carbon market settled at.

The WACC assumed in developing the generation scenarios was 8%.  This is slightly higher than the previously stated assumption of 7.7%, to notionally account for hurdle rate issues as well as to make it distinctly different from the 7% assumed for transmission investments.

Concept Consulting has prepared advice for the Commission on this issue.

• Concept discount rates pdf [71 KB]

Location factors have been used to reflect the effects of locational price on project economics.  Each modelled project is mapped to a transmission region, and each region has a location factor associated with it.  For example, an identical project would require a lower average price to be constructed were it located at Otahuhu than it would were it located at Tiwai.  The location factors used are constant and do not change in response to generation and demand changes.

The following table lists the location factors (relative to Haywards) used when developing the generation scenarios.  These were derived from analysis carried out for the Initial SOO.  The Initial SOO included a series of modeling runs performed by Energylink which represented the transmission system in some detail.  Average location factors from those modeling runs were assessed across scenarios to arrive at a static and consistent set of factors. 

South Island generation projects are assumed to pay a charge of $40/kW p.a.  This assumption was derived by taking the annualising Transpower’s stated HVDC charges and apportioning them to an assumed South Island installed capacity. 

There is considerable uncertainty around the capital costs and potential benefits of the modelled wind and hydro generation projects, which is not reflected in the baseline project cost/benefit estimates in the list of modelled projects.  As a consequence, the unmodified cost curves for wind (and hydro, to a lesser extent) are very flat, with relatively little variation between projects in LRMC.  In reality these curves should be more sloping, with some potential projects delivering more or less benefits than shown, or able to be constructed at a lower or higher capital cost.

In the scenario development, this is implemented as follows. Modelled wind and hydro projects (excluding committed and 'highly likely') are divided into four mutually exclusive subsets of roughly equal size, on an arbitrary basis.  In each scenario, one of these four subsets is selected, and it is assumed that projects in this subset possess unexpected advantages (e.g. can be constructed more cheaply, or can produce more energy, than the baseline predictions indicate).  These advantages are modelled by reducing the capital costs of the selected projects by 10% for hydro, or 20% for wind (where the uncertainties are considered to be greater).  The effect is to shift the selected projects higher up the merit order.  This has the effect of increasing the slope of the cost curves for wind and hydro, with the affected projects becoming more competitive with other forms of generation (i.e. thermals).  A useful secondary effect is to increase the diversity between scenarios - each scenario has a different set of projects with reduced costs, and hence a different build order.

In the scenario development, annual energy demand is modelled via quarterly load duration curves.  The total energy used in each island is based on the regional energy demand forecast, with expected projections summed to island level.  Allowances are made for losses and to avoid double-counting of modelled embedded generation.  The shape of the load duration curve is based on a historical reference curve.

Dry-year inflows are used when determining expansion plans. This has the effect of making the energy constraint more restrictive.

The generation scenarios in the SOO not only need to provide enough generation to satisfy energy requirements, but also need to be able to meet the demand at peak.  These requirements are implemented by using capacity constraints, both nationally, and for the North Island. 

The Commission will be using an incremental approach to the analysis of these capacity constraints.  Based on the National Winter Group (NWG) report for 2007, the projected national generation capacity in 2007 is believed (with high confidence) to be enough to meet possible peak demands.  So, the analysis of national peaking capacity is incremental—rather than assessing the total peaking capacity of the system at each stage, the additional supply capacity added by each new plant is considered.  The Commission considers that the 2007 situation (with e3p) will provide a 'safety margin' of capacity, such that initial increases in peak demand need not be met by supply.  It is assumed that the first 120 MW of peak demand growth in the scenarios can be set against this surplus and need not be matched by an equivalent amount of generation.

The analysis of North Island peaking capacity is also incremental; the constraint reflects the requirement to maintain N-G-1 security in the North Island (with expanded capacity on the HVDC link).

The peak demand forecast used to produce these constraints is calculated by applying expected growth rates to a prudent 2007 baseline. 

The capacity constraints require that increases in peak demand are either by supply or by demand-side response.  On the demand-side, a total of 300 MW of demand-side response is modelled, split into three equal tranches, becoming available in 2015, 2019 and 2023.  This might include components from automatic load shedding, smart metering, time-variable pricing, and/or demand-side aggregation.

On the supply side, the incremental MW capacity is calculated, for each new plant, as the product of the plant's maximum MW (as shown in the modelled projects list) with a 'marginal capacity factor' depending on plant type.  The marginal capacity factors are as follows:

This 'capacity factor' approach is based on the principle that the marginal improvement in 10th percentile capacity gained from adding a plant to the system is more than the 10th percentile of the availability curve of that plant – since the new plant's output is not fully correlated with existing plant (in fact, in some cases the two will be independent).

The capacity factor proposed for wind plant is 15%.  This figure is considered to be quite important but is subject to substantial uncertainty.  It has been calculated as an approximate figure by the Commission, since no publicly available research provides a well-supported estimate for the New Zealand environment (though research of this type is now in the pipeline).  The 15% figure is based on convolution analysis, in which a wide range of modelled wind availability curves have been convoluted with availability curves for other forms of generation and the 10th percentile of the resulting joint availability curve has been extracted. 

A 65% capacity factor is proposed for run-of-river hydro, based on similar analysis.  Note that all modelled hydro projects not associated with a major storage lake have been assigned to the 'run of river' category.

Generation scenarios

• Current versions of the four draft generation scenarios xls [140 KB] (Updated 11 May 2007, since superseded)

The linked spreadsheet includes, for each scenario, a schedule of projects, a summary table of generation by year, fuel type and island, and plots indicating incremental energy and peak capacities.

Note that the location of North Island peaking thermal plant at Otahuhu is effectively a placeholder - it would be expected that the locations of these plant would be redetermined when the scenarios were used.