465005PartIV.pdf

North Island 400 kV Upgrade Project

Investment Proposal

Part IV – Cost Benefit Analysis

© TRANSPOWER NEW ZEALAND LIMITED 2005. ALL RIGHTS RESERVED

TABLE OF CONTENTS
1
SUMMARY ............................................................................................................................... 3
2
COST/BENEFIT ANALYSIS APPROACH .............................................................................. 3
2.1
Defining the base case.................................................................................................... 3
2.2
Costs considered............................................................................................................. 4
2.2.1
Capital costs ............................................................................................................... 4
2.2.2
Operating and maintenance costs .............................................................................. 4
2.2.3
Dismantling costs........................................................................................................ 5
2.2.4
Property and easement costs ..................................................................................... 5
2.2.5
Approval process costs............................................................................................... 5
2.2.6
Project management costs ......................................................................................... 5
2.3
Benefits or costs evaluated ............................................................................................. 5
2.3.1
Avoidance of unserved energy ................................................................................... 5
2.3.2
Energy loss differences............................................................................................... 5
2.3.3
Differences in energy costs......................................................................................... 6
2.3.4
Differences in carbon costs......................................................................................... 6
2.3.5
Differences in ancillary service costs.......................................................................... 6
2.3.6
Generation reliability value difference......................................................................... 6
2.4
Other Assumptions.......................................................................................................... 6
2.4.1
Timeframe ................................................................................................................... 6
2.4.2
Discount rate............................................................................................................... 7
2.4.3
Weightings applied to generation scenarios ............................................................... 7
2.4.4
Competition Benefits................................................................................................... 7
2.5
Calculation of expected net market benefit ..................................................................... 8
2.6
Sensitivity Analysis.......................................................................................................... 9
3
COST SUMMARY .................................................................................................................... 9
3.1
Development Plan Costs................................................................................................. 9
3.2
Proposed 400 kV Investment Costs.............................................................................. 11
4
“DO NOTHING” ANALYSIS – IS LARGE SCALE BASE-LOADED GENERATION AN
ECONOMIC ALTERNATIVE TO TRANSMISSION?..................................................................... 12
4.1
Costs ............................................................................................................................. 12
4.2
Benefits ......................................................................................................................... 12
4.2.1
Expected net market benefit ..................................................................................... 13
4.2.2
Sensitivities ............................................................................................................... 13
4.2.3
Conclusion ................................................................................................................ 14
5
COST BENEFIT OF 400 KV HVAC VERSUS 220 KV HVAC............................................... 14
5.1
Capital Cost Summary .................................................................................................. 14
5.2
Cost/benefit analysis results ......................................................................................... 16
5.3
Development Plan Sensitivity Analysis Results ............................................................ 18
6
EXPECTED NET MARKET BENEFIT OF THE PROPOSED 400 KV HVAC GRID
AUGMENTATION .......................................................................................................................... 20
6.1
400 kV Line Sensitivity Analysis Results....................................................................... 23
6.2
400 kV Line using the Electricity Commission’s Scenarios........................................... 25
7
ALTERNATIVES TO TRANSMISSION WHICH MAY ECONOMICALLY DEFER
TRANSMISSION ............................................................................................................................ 26
7.1
Request for Information document................................................................................ 26
7.1.1
Load Shedding Bidding Programme......................................................................... 26
7.1.2
Generation plant ....................................................................................................... 26
7.2
Approach to evaluate alternatives to transmission to defer transmission..................... 27
7.3
Sensitivities ................................................................................................................... 30
7.4
Conclusion..................................................................................................................... 31
8
SUMMARY ............................................................................................................................. 31
Part IV - Cost Benefit Analysis
2

1 Summary

This Part IV sets out the cost benefit methodology used to assess the proposed
investment. This methodology is consistent with the Electricity Commission’s Grid
Investment Test. The cost benefit analysis demonstrates the following conclusions.

A long run development plan for the transmission network at 400 kV is more
economic than continuing with incremental augmentation at 220 kV. The expected
net market benefit of a 400 kV development plan over a 220 kV development plan is
estimated at $133 million. Therefore 400 kV is the most economic choice for the
main backbone voltage of the National Grid.

There are substantial benefits in implementing transmission augmentation when
compared to a “do nothing” alternative which allows only for that generation
anticipated in either Transpower’s or the Electricity Commission’s generation
scenarios to be established.

The proposed investment has a substantially higher expected net market benefit
than the best case transmission alternative of a diesel fired peaking plant. The
expected net market benefit (cost) of a diesel fired peaking plant ranges between -
$75 and -$105 million for one year deferral of transmission.

In summary the proposed investment based on the construction of a 400 kV double
circuit transmission line between Whakamaru and Otahuhu is the most economic
alternative to provide long run security of supply into the upper North Island and
satisfies the requirements of the Grid Investment Test.

2 Cost/benefit
analysis
approach

The cost/benefit approach used for this analysis is consistent with the Grid Investment
Test as required for investment proposals submitted to the Electricity Commission under
the Grid Upgrade Plan provisions of Part F of the Electricity Governance Rules.

2.1 Defining the base case

Transpower’s current Grid Reliability Standards specify a deterministic criterion which is
widely used by electricity transmission businesses in many parts of the world.

The Grid Reliability Standards require that Transpower maintain the core grid to an N-1
standard as discussed in Part II of this submission. Under this criterion, it is necessary
only to compare developments which are technically feasible and will, at a minimum,
satisfy the deterministic standard.

This contrasts with the purely economic approach which would require a value to be
ascribed to unserved load. Using such an approach, the base case would include
market development scenarios which include expected new generation and which reflect
expected demand growth, but which do not include new transmission development (that
Part IV - Cost Benefit Analysis
3

is a “do nothing” base case). The economic justification for transmission development
would then depend upon maximising the economic benefit of the proposed new
transmission investment by reducing the extent of the unserved load in the particular
region under consideration.

In developing its generation scenarios, Transpower assumes that new generating
capacity will continue to be installed to meet electricity requirements throughout New
Zealand. The generation scenarios are intended to provide Transpower with a basis for
proposing grid augmentation for a range of plausible generation developments.

The base case for analysis of the transmission options implicitly assumes that sufficient
generating capacity will be installed to meet the overall standard of a 1 in 60 year
severity of a “dry year”.

Since 220 kV is the current core grid voltage, the base case used for this analysis
includes expected demand growth, expected new generation, and continued
development of the grid at 220 kV to satisfy the Grid Reliability Standards for each of the
nominated generation scenarios.

2.2 Costs considered

All costs included in the cost/benefit analysis are estimates in 2005 New Zealand dollars
i.e. they do not account for inflation and a “real” discount rate is used. However, special
provision is made for the assumption that the costs of acquiring property rights and
easements will escalate at 1% above the average inflation rate.

Since the cost/benefit analyses are all comparisons of technically feasible alternatives
(including alternatives to transmission development such as distributed generation) only
those costs which vary between the cases need to be included in any comparisons. The
costs of maintaining the existing grid, for instance, are not included because they remain
unchanged whichever case is being analysed.

The costs included in the analysis are summarised in this section. Part V of this
submission provides further information about the estimated costs for the proposed
400 kV reliability investment.

2.2.1 Capital
costs

The capital costs for the transmission options comprise estimates of the cost to design,
purchase and construct new transmission assets (eg transmission towers, conductors,
substation equipment). The approach used to determine these cost estimates and their
estimated range over which the results are sensitised, is described in section 3.

For alternatives to transmission, publicly available cost information has been used and
the source is referenced.

2.2.2  Operating and maintenance costs

Costs in this category are estimates of the costs of operating and maintaining either the
transmission assets or alternatives to transmission relevant to each case.

Part IV - Cost Benefit Analysis
4

2.2.3 Dismantling
costs

Dismantling costs are the estimated costs of dismantling and removing assets that are no
longer required. These costs are “net”, being the cost of dismantling less any scrap
value realised from the sale of recovered material.

2.2.4  Property and easement costs

These are the costs of securing the property rights needed for new or altered
transmission assets, or alternatives to transmission. These costs include the costs of
purchasing land and easement rights.

2.2.5  Approval process costs

These are the legal and administrative costs of obtaining approval for the proposed
reliability investment. The costs include satisfying the requirements of the Resource
Management Act 1991, the Electricity Act 1992, the Public Works Act 1981 and other
relevant legislation.

2.2.6  Project management costs

These are the costs associated with project managing the build of new assets. A
standard value of 8% has been used, which includes a mixture of Transpower’s internal
and external costs.

2.3  Benefits or costs evaluated

The following benefits or costs which are relevant to the comparison of alternatives have
been considered in completing the cost/benefit analysis:

2.3.1  Avoidance of unserved energy

Differences in the level of unserved energy between the base case and each scenario
have been quantified in MWh where relevant.  The unserved energy has been calculated
taking into account the generation available in each of the generation scenarios.
Unserved energy has been valued at $20,000 MWh.

2.3.2  Energy loss differences

Any investment in transmission augmentation will generally reduce the extent of energy
losses. The reduction in losses is a benefit which is quantified and valued.

Transpower has applied different values for such loss reduction recognising that
transmission augmentation may serve to carry base load power flows or incremental
power flows. Base-load loss differences are valued using the long run marginal cost
which includes a capital cost for additional generating plant that would be required to
make-up for the losses incurred. Incremental, or peak load loss differences are valued
using the short run marginal cost of the marginal generation plant1.


1 Marginal plant is based upon the predominant mix of new thermal plant in the particular scenarios
considered and is assumed to be gas fired in Scenario 1, coal fired in Scenario 2 and the average cost of gas
and coal is used in the other scenarios .
Part IV - Cost Benefit Analysis
5

The costs of generation required to make-up the transmission losses differ depending
upon the Generation Scenario and (depending on the Scenario) range from the
generation cost based on gas to the cost of coal or oil fired generation. The costs used
are sourced from a publicly available report prepared for the Electricity Commission by
Parsons Brinckerhoff Associates, “Thermal and Geothermal Generation Plant
Capabilities,” dated December 2004.

2.3.3  Differences in energy costs

Some transmission options or alternatives to transmission will enable different generation
dispatch patterns. For example, relieving a transmission constraint may enable
expensive thermal generation to be displaced by cheaper hydro or wind generation.
Where such differences are material, the dispatch differences are derived, the variable
costs of generation are calculated in each case (primarily fuel costs) and the cost
difference is calculated. The variable costs of generation used are also sourced from
Parsons Brinckerhoff Associates report referenced above.

2.3.4  Differences in carbon costs

The relieving of a transmission constraint may enable expensive thermal generation to
be displaced by hydro or wind generation with a consequential reduction in the CO2
burden. Where such differences are material, the dispatch differences are derived, the
tonnes of CO2 generated in each case are estimated and the cost difference is calculated
using a value of $15 per tonne CO2.

2.3.5  Differences in ancillary service costs

Some transmission options or alternatives to transmission may enable different levels of
ancillary services to be required. For example, voltage stability is the limiting design
factor in the Auckland area and different investments will require the purchase of more or
less dynamic voltage support from existing synchronous condensers or generators.
These differing amounts of voltage support requirement are estimated and costed at the
average voltage support cost in Auckland for 2004.

2.3.6  Generation reliability value difference

Transmission assets typically provide approximately 99.0% reliability, and a grid
designed to an N-1 standard is available and provides continuity of supply 99.99% of the
time. Unplanned outages occur only 0.3% of the time, but on account of redundancy,
failure of supply occurs only 0.01% of the time.

In contrast, generation assets are typically 85-90% reliable, with planned outages
occurring 5-10% of the time and unplanned outages about 5% of the time. Generation
can only approach the same level of service to consumers if multiple generators are built,
or individual generators have multiple redundancy in their generating units. Where
relevant, estimates are made of the amount of unserved energy that will accrue, as a
result of the unreliability of each configuration of transmission and generation considered.
2.4  Other Assumptions

2.4.1 Timeframe

Transpower has also applied the technique that uses residual values to extend the
analysis to consider 40 years of costs and benefits This is particularly relevant to HVAC
Part IV - Cost Benefit Analysis
6

transmission augmentation which will have an expected technical and economic life in
excess of 50 years and there are significant benefits accruing after the first 20 years.

2.4.2 Discount
rate

A pre-tax real discount rate of 7% consistent with the Electricity Governance Rules is
used to determine the present value of future cash flows.

2.4.3  Weightings applied to generation scenarios

The generation scenarios will be given equal weighting (ie 20% each) in calculation of
the expected net market benefit, consistent with the Electricity Governance Rules.

2.4.4 Competition
Benefits

In situations where load can be supplied from either local generation or the grid, the level
of competition in the energy market for that load is influenced by the level of transmission
constraint. When the transmission to that load constrains, competition is reduced and
local generators have a certain amount of market power which can be used to extract
monopoly profits from consumers. Relieving the transmission constraint enhances
competition and eliminates the ability of the generator to exert market power.

This benefits consumers in two ways. Firstly, enhanced competition actually lowers the
cost of electricity, and secondly it also lowers the price of electricity. The price change
consists of the cost change plus the extent to which generators can exercise market
power.

Price changes due to the exercise of market power (decreases in consumer surplus at
the expense of an increase in producer surplus, or the reverse), are collectively known as
value transfers, and are not classified as competition benefits.

Competition benefits are that piece of the price change associated with cost changes.
The competition benefits of a transmission investment are defined as the increase in size
of the net consumer and producer surplus due to enhanced competition in the energy
market2 as a result of the investment.

This increase in surplus3, resulting from generators offering closer to their short run
marginal cost, theoretically leads to a decrease in the overall cost of dispatch as:
•  operating costs of existing generation are reduced, leading to cheaper generation
displacing expensive generation;
•  capital expenditure on new generation is deferred or avoided;
•  demand increases due to lower prices.

There is little consensus in the literature and amongst practitioners over a precise
method for estimating competition benefits.   However, a lower bound on their value can
be determined by estimating the increase in consumer and producer surplus due to
demand response to lower marginal electricity prices resulting from the investment.

Transpower has developed an approach for calculating such a lower bound on the
competition benefits and this is described in the supporting document “A Methodology for
Calculating the Lower Bound of Competition Benefits” (see Volume 2: Supporting

2 Usually as a result of reducing generator market power
3 Also known as a reduction in deadweight loss
Part IV - Cost Benefit Analysis
7

Documents). At this time however, we do not have the price elasticity of demand
information required to undertake the calculations.

The Part F rules allow competition benefits to be included in the cost-benefit analysis,
provided such inclusion is appropriate, but do not require it. Transpower will continue to
work on obtaining the necessary data to calculate a lower bound on competition benefits.
The resulting competition benefits may be significant.

2.5  Calculation of expected net market benefit

The approach Transpower uses to calculate the expected net market benefit is a net
present value analysis. Rather than being the outcome of a static spreadsheet
calculation, the expected net market benefit is calculated by a Monte Carlo simulation in
which demand is varied between the low and high bounds of the demand growth
forecasts.

Figure 2-1 illustrates 1000 demand paths produced from a typical Monte Carlo
simulation:

Forecast Demand Paths
Auckland & North Isthmus
7,000
6,000
High Demand Growth
Forecast
5,000
(MW) 4,000
3,000
Peak Load
Low Demand Growth
2,000
Forecast
1,000
0
2004
2009
2014
2019
2024
2029
2034
2039
2044
Year

Figure 2-1 Illustration of demand paths from a Monte Carlo simulation

Transmission lines are large investments, with an economic life in excess of 50 years.
There is considerable uncertainty when looking far into the future and in the particular
case of transmission lines, uncertainty in:

•  Future energy demands
•  The location of new generation
•  Technology changes that reduce the need for transmission.

Some transmission options and potentially alternatives to transmission include an
inherent value, in that they include future investment flexibility to deal with uncertainty.
Part IV - Cost Benefit Analysis
8

For example, projects which are built incrementally in line with growth in demand reduce
the possibility of overbuild, because later investments can be deferred or cancelled
should demand growth not be as high as expected.

Transpower’s approach to calculating expected net market benefit does not capture all of
this inherent value, in that a separate calculation is made for each generation scenario,
but it does capture the value attributable to the uncertainty in demand growth.

2.6 Sensitivity Analysis

Transpower has sensitised the list of variables shown in Table 2-1, being those that may
have a material impact on the cost/benefit analysis:

Variable
Range
Discount rate – transmission
4% to10%
Discount rate – alternatives
7% to 10%
Value of unserved energy
$10K to $30K
Value of losses
- 50%to +50%
Probability market development scenarios
0% to 40% ea
Capital Cost:
-10% to +50%
Operating and Maintenance Cost
-30% to +30%
Table 2-1: Table of variables which will be sensitised

Demand is not sensitised due to the effect of demand varying between the low and high
bounds of the demand growth forecasts already being reflected in the Monte Carlo
technique which calculates expected net market benefits.
3 Cost
Summary

This section summarises all of the transmission costs used in the cost / benefit analysis.
3.1  Development Plan Costs

The 220 kV and the 400 kV grid development plans have been built up for each
generation scenario, as described in Part III, section 5 of this submission. The costs
presented here relate only to those developments which are unique to each transmission
option4.

Table 3-1 below shows the total costs (expressed in 2005 dollars) as they would be
incurred for the base case 220 kV development plan out to the year 2040. It should be
noted that the Operation and Maintenance Costs (O&M) have been included in this table
for the purpose of comparing one transmission option against another. Other overhead
costs associated with grid augmentation such as statutory approvals, property acquisition
and project management have been included for the same reason. The treatment of
capitalised cost of Interest During Construction (IDC) is taken account of in the projected
incidence of investment costs.

4 If a grid augmentation is required at the same time in both the 220 kV and the 400 kV development plans,
the costs have been excluded on the basis that they are not necessary to compare development plans. this
is a widely used approach in carrying out economic comparisons.
Part IV - Cost Benefit Analysis
9

220 kV Development Costs
$ million (2005)
Scenario Numbered ¨
No.1
No.2
No.3
No.4
No.5
Av.
Line
+
Cable
capital
costs
611 474 1,054
376 662 635
Substation
capital
costs
102
82 160
29 36 82
Property
451 363 732 194 402 428
O&M
83 56 97 21 15 54
Dismantling
costs
4 4 4 4 4 4
Project
Management
Costs 99 80 162
49 88 96
Approval
Costs
20 10 22 10 9  14
Total
1,369 1,067 2,232 683  1,216 1,313
Table 3-1: 220 kV Augmentation Plan Costs $million (2005)

Table 3-2 below shows the total costs (expressed in 2005 dollars) as they would be
incurred for the proposed 400 kV development plan out to the year 2040. Similar
qualifications apply to the cost estimates in this table as for Table 3-1 above so that they
may be directly compared.

400 kV Development Costs
$ million (2005)
Scenario Numbered ¨
No.1
No.2
No.3
No.4
No.5
Av.
Line
+
Cable
capital
costs
508 362 569 205 216 372
Substation
capital
costs
227 185 338 99  151 200
Property
248 199 320 97  105 194
O&M
106 84  126 46  54  83
Dismantling
costs
4 4 4 4 4 4
Project
Management
Costs 79 60 99 33 38 62
Approval
Costs
32 20 31 11 11 21
Total
1,203 913  1,485 494  579  935
Table 3-2– 400 kV Augmentation Plan Costs $million (2005)

Table 3-3 shows the present value of the total costs which are unique to the base case
(220 kV) development plan, in 2005 dollars.

220 kV Development Costs
Present value $ million (2005)
Scenario numbered¨
No.1
No.2
No.3
No.4
No.5
Av.
Line
+
Cable
capital
costs
354 234 427 176 277 294
Substation
capital
costs
43 39 54 9  10 31
Property
265 186 326 98  195 214
O&M
17 12 18 4  2  11
Dismantling
costs
2 2 1 2 2 2
Project
Management
Costs
60 44 72 30 41 49
Approval
Costs
14
8 13
3 3 8
Total
757 525 910 322 532 609
Table 3-3 - 220 kV Development Plan Costs $million (discounted)

Table 3-4 below shows the present value of the total costs which are unique to the
proposed (400 kV) development plan, in 2005 dollars.

Part IV - Cost Benefit Analysis
10

400 kV Development Costs
Present value $ million (2005)
Scenario numbered ¨
No.1
No.2
No.3
No.4
No.5
Av.
Line
+
Cable
capital
costs
302 231 308 153 159 231
Substation
capital
costs
122 105 154 73  98  110
Property
167 142 194 85  89  136
O&M
24 19 26 12 14 19
Dismantling
costs
2 2 2 2 2 2
Project
Management
Costs  48 39 53 25 28 39
Approval
Costs

21 15 19 10 10 15
Total
686 553 757 361 401 552
Table 3-4 – 400 kV Development Plan Costs $million (discounted)
As can be seen from Table 3-3 and Table 3-4 above, the 220 kV development plan is
$378 million (on the average) more expensive than the 400 kV development plan on a
straight dollar comparison, but on a present value basis, this reduces to $57 million (on
the average).
3.2  Proposed 400 kV Investment Costs

The costs associated with the proposed 400 kV investment, ie the 400 kV double circuit
line and underground cable from Whakamaru to Otahuhu, that are used for the purposes
of the cost/benefit analysis, are shown in Table 3-5.

Item
$million (2005)
Line capital costs
205
Substation capital costs
99
Property 97
O&M 46
Dismantling costs
4
Project Management Costs
33
Approval Costs
11
Preliminary Design & Investigation
12
Total 507
Table 3-5 – 400 kV first investment costs

A further set of costs are calculated, which include an estimate of costs associated with
facilitating transmission across Auckland to North Isthmus. These costs also need to be
incurred to ensure the energy flowing through the proposed new 400 kV line can reach
load in Auckland and the North Isthmus.

Item
$million (2005)
Line capital costs
407
Substation capital costs
99
Property 97
O&M 57
Dismantling costs
4
Project Management Costs
49
Approval Costs
11
Preliminary Design & Investigation
12
Total 737
Table 3-6 – 400 kV First Investment Costs Including Across Auckland Costs
Part IV - Cost Benefit Analysis
11

4  “Do Nothing” analysis – Is large scale base-loaded
generation an economic alternative to transmission?

Transpower has undertaken analysis has been undertaken to determine whether the new
generation that is forecast to emerge in the Auckland/North Isthmus region according to
the generation scenarios, substitutes for transmission, and whether building transmission
as well has a positive expected net market benefit.

4.1 Costs

The costs included in the analysis are the base case costs ie the costs of the 220 kV
development plan. A sensitivity is included using the costs of the 400 kV development
plan.

4.2 Benefits

The avoidance of unserved energy at $20,000 per MWh dominates the benefits included
in the economic analysis. While there are a number of other benefits attributable to the
proposed investment these have not been quantified or included in the analysis because
they are relatively insignificant as compared to the avoidance of unserved energy. For
completeness these other benefits include:

•  Energy loss differences
•  Differences in energy costs
•  Differences in carbon costs
•  Differences in ancillary service costs
•  Generation reliability value difference

Energy loss differences, differences in energy costs and differences in carbon costs,
would together represent the cost of meeting the otherwise unserved energy and as such
would be a negative benefit if transmission was built. However, even if an average
generation cost were used for thermal plant, of 7.5 cents per kWh, this only equates to
$75 per MWh.

Ancillary service costs may increase in view of the higher demand being served but even
if they were as high as the average cost of transmission, which is highly unlikely, that
would only equate to $75 per MWh.

Generation reliability value is not a significant factor either. The previously unserved
energy will be served through transmission, with an estimated reliability of 99.99%. The
generation reliability cost will be 0.001% of $20,000 per MWh, or $2 per MWh.

Therefore, even if all of these were summed together, the likely maximum they could add
is $152 per MWh, hence it is considered unnecessary to reflect them in the analysis.
Rather, sensitivity analysis is undertaken on the unserved energy cost, using a low cost
of $10,000 per MWh.
Part IV - Cost Benefit Analysis
12

4.2.1  Expected net market benefit

The expected net market benefit of building transmission, as a result of applying the
above assumptions, is:

$ million (discounted)


Scenario number ¨
No. 1  No. 2
No 3
No. 4
No. 5
Average
Line capital costs
354
234
427
176
277
294
Substation
capital
costs
43
39 54 9  10 31
Property
265
186 326 98  195 214
O&M
17
12 18 4  2  11
Dismantling
costs
2
2 1 2 2 2
Project Management Costs
60
44
72
30
41
49
Approval Costs
14
8
13
3
3
8
TOTAL
COSTS
757
525 910 322 532 609
Avoidance of unserved energy
4,625
10,491
74,281
90,976
56,293 47,333
Total Benefits
4,625
10,491
74,281
90,976
56,293  47,333
Net Market Benefit
3,868  9,967
73,371  90,654  55,761
Expected Net Market Benefit

46,724
Table 4-1 Expected Net Market Benefit Per Scenario

4.2.2 Sensitivities

The expected net market benefit has been sensitised for uncertainty in the cost estimates
and the unserved energy cost, with the following results:

$ million (discounted)
Sensitised
Expected Net Market
value
Benefit
Base case without sensitivity applied

46,724
Total Costs
-10%
46,785
Total Costs
+50%
46,420
Unserved energy cost
$10,000
23,058
Unserved energy cost
$20,000
46,724
Unserved energy cost
$30,000
70,391
Table 4-2: Expected Net Market Benefit Sensitised for Uncertainty

As a separate sensitivity, the 220 kV development costs have been replaced by the 400
kV development costs, with the following result:

$ million (discounted)
Sensitised
Expected Net Market
value
Benefit
Base case without sensitivity applied

46,724
Total costs reflecting 400 kV development plan

46,782
Table 4-3: Replacement of 220 kV Development Costs with 400 kV Development Costs

Part IV - Cost Benefit Analysis
13

4.2.3 Conclusion

From this analysis it is clear that both the base case (220 kV HVAC) and 400 kV HVAC
have a highly positive expected net market benefit in all generation scenarios. Therefore,
it can be concluded that:

•  there is not enough large scale base-loaded generation forecast to appear to the
North of Auckland in any of the generation scenarios to avoid significant amounts
of unserved energy and thus large scale base-loaded generation does not
substitute for transmission, and

•  it is economic to augment existing transmission into the area to avoid the forecast
unserved energy, and

•  there is no certainty that the generation included in the generation scenarios will
go ahead early enough to have any material effect on the timing of grid
augmentation.

5  Cost benefit of 400 kV HVAC versus 220 kV HVAC

Previous studies have shown 400 kV HVAC to be the preferred technology from a wide
range of alternative technologies including HVDC, for long-term development of New
Zealand’s national transmission grid. In this Section, Transpower compares a possible
long-term grid augmentation plan using a 400 kV HVAC against a base case
representing a “business as usual” case whereby the core grid elements continue to be
designed and built to 220 kV HVAC.
5.1  Capital Cost Summary

The following charts compare the cumulative capital costs associated with grid
augmentation plans for the upper North Island development using 220 kV and 400 kV
technology for each of Transpower’s generation scenarios.

The costs shown in the charts below include line, substation, dismantling, property and
approval costs only. They do not include operations and maintenance costs,
transmission losses or project management costs.

Cumulative Capital Cost
Gas Scenario Development Plan
2,500
400 kV
220 kV
2,000
1,500
on
li
il
$m 1,000
500
0
2005
2010
2015
2020
2025
2030
2035
2040

Scenario 1
Part IV - Cost Benefit Analysis
14

Cumulative Capital Cost
Coal Scenario Development Plan
2,500
400 kV
220 kV
2,000
1,500
on
li
il
$m 1,000
500
0
2005
2010
2015
2020
2025
2030
2035
2040

Scenario 2
Cumulative Capital Cost
Renewables Scenario Development Plan
2,500
2,000
400 kV
220 kV
1,500
illion
m
$ 1,000
500
0
2005
2010
2015
2020
2025
2030
2035
2040

Scenario 3

Cumulative Capital Cost
Hydro Scenario Development Plan
2,500
400 kV
220 kV
2,000
1,500
on
lli
$mi 1,000
500
0
2005
2010
2015
2020
2025
2030
2035
2040

Scenario 4

Part IV - Cost Benefit Analysis
15

Cumulative Capital Cost
Low Demand Scenario Development Plan
2,500
400 kV
220 kV
2,000
1,500
lion
$mil 1,000
500
0
2005
2010
2015
2020
2025
2030
2035
2040

Scenario 5
Figure 5-1: Cumulative Capital Cost Summary
As the charts in Figure 5-1 above show, the cumulative capital cost for 220 kV is higher
in all scenarios, although grid augmentation at 400 kV costs incurs higher initial costs
which pay off in the medium term.
5.2 Cost/benefit analysis results

The results of the cost/benefit analysis are shown in Table 5-1.

400 kV Advantage over Base Case $million (discounted)
Scenario numbered ¨
No. 1
No. 2
No. 3
No. 4
No. 5
Average
Line capital costs
52
3
120
23
117
63
Substation
capital
costs
-79 -66 -101
-64 -88 -79
Property
98 43 132
13 106
78
O&M
-6 -7 -8 -8 -11
-8
Dismantling
costs
0 0 -2 0 0 0
Project Management Costs
12
5
19
5
13
11
Approval
Costs
-6 -7 -6 -7 -7 -7
Total Costs
71
-29
153
-39
130
57
Avoidance of unserved energy
0
0
0
0
0
0
Energy loss differences
95 75 105
18 85 76
Differences in energy costs
0 0 0 0 0 0
Differences in carbon costs
0 0 0 0 0 0
Differences in ancillary service costs
0 0 0 0 0 0
Generation reliability value difference
0 0 0 0 0 0
Total Benefits
95 75 105
18 85 76
Net Market Benefit 400 kV
166
47
258
-21
215

Expected Net Market Benefit 400 kV

133
Table 5-1: Expected Net Benefit of 400 kV HVAC Augmentation of Supply to
Auckland/North Isthmus Compared With 220 kV HVAC

The only material benefit that is applicable to the comparison of alternative transmission
technologies dealt with in this section is the value of the lower transmission losses
offered by the choice of a higher voltage level.

The value of transmission losses has been evaluated at the long run marginal cost
(LRMC) of the most likely generation in each scenario, for example, gas fired in Scenario
Part IV - Cost Benefit Analysis
16

1, coal fired in Scenario 2. Taken on average for all scenarios, the average value of
losses is around $77/ MWh in 2020.

The analysis demonstrates that (on average) the 400 kV HVAC development option has
an expected net market benefit of $133 million compared with the 220 kV HVAC base
case development option.

Table 5-1 above, also shows that the 400 kV grid augmentation between Whakamaru
and the Auckland/North Isthmus region is economically least attractive for Scenario 4.
This scenario is based upon the assumption of extensive generation in the South Island
in the short to medium term which would essentially be developed to supply loads in the
North Island. This generation development in the South Island is assumed to be based
upon new hydro resources being developed (Project Aqua plus other new hydro) but
could equally be thermal generation based on the use of indigenous coal. It is also
assumed that this development would take place within a reasonable period after the
400 kV augmentation of the grid supplying Auckland is completed.

If such large scale generation should develop, it is assumed that a new high capacity
HVDC link would be established to deliver the new generation to a site near Auckland. If
the HVDC terminal station is either in or near Auckland, the 400 kV development would
have a low ongoing value for supply to Auckland and the North Isthmus which is reflected
in the evaluation.

Equally well, the existence of the proposed 400 kV HVAC augmentation between
Whakamaru and Auckland could be taken into account at the relevant future time and the
HVDC terminated near Whakamaru where the availability of land and access is less
likely to be and an issue than close to Auckland. If a terminal site to the south of
Auckland is the preferred development in the future, the proposed 400 kV HVAC
augmentation between Whakamaru and Auckland would have a substantial ongoing
value which is not reflected in this scenario.

In reality, the possibility of a large scale generation in the South Island within a
reasonable time-span which would warrant the construction of a major new HVDC link
(rather than simply upgrading the existing link) seems to be of a low probability compared
with the other generation scenarios that have been considered.

This points to the issues that may be introduced by taking a simple arithmetic average
across all the generation scenarios. This approach assumes:

(i)  that all scenarios have a similar likelihood of occurring with the result that a
“unlikely” scenario could unduly bias the result, and
(ii)  more importantly, it assumes that the outcome for any one particular scenario is
equally acceptable in the context of future development of the national grid as it
is for any other scenario.

This latter point is not considered in the Grid Investment Test. To put this point in the
current context, the result of giving undue weight to scenario 4 was considered which
would lead one to choose an extension of the 220 kV and the potential pitfalls of having
to provide a further 220 kV line (or even migrate to 400 kV) some 10 years or so later if
scenario 4 did not eventuate.

On the other hand, if this scenario was discounted as being the least likely, a decision in
favour of 400 kV HVAC would leave the door open to the widest range of possible
options including (as mentioned above) the possibility of siting a HVDC terminal station
Part IV - Cost Benefit Analysis
17

for a future HVDC link south of Auckland or even further south nearer Whakamaru. This
has a very definite option value as suggested earlier in this Part IV but the possibility of
putting a dollar value on such a future option has not been done in this instance as it is a
difficult concept to give practical effect to.

If, for the reasons set out above, if scenario 4 is excluded from the calculation of the
average of the expected net market benefit for the alternative scenarios, this increase the
advantage of the 400 kV HVAC option over the “business as usual“ 220 kV option from
$ 133 million to $ 172 million.
5.3 Development Plan Sensitivity Analysis Results

Table 5-2 shows the results of the various sensitivities applied to the cost benefit analysis
set out in the previous section. The expected net market benefit is the weighted average
of the 400 kV development plan over and above the base case across all five generation
scenarios5.

Expected Net Market Benefit
$million (discounted)
Sensitivity Factor
Benefit
Base case without sensitivity applied
133
4% discount rate
275
10% discount rate
66
Loss value + 50%
172
Loss value – 50%
95
0% weighting on Scenario 4
172
40% weighting on Scenario 4
95
Capital costs + 50%
169
Capital costs -10%
128
O & M costs + 30%
133
O & M costs – 30%
133
Table 5-2 – Sensitivity Results for Expected Net Market Benefit of 400 kV

There is an economic advantage of the 400 kV investment over and above the base case
in all of the sensitivity analysis.

Figure 5-2 shows that as the discount rate increases, the advantage of the 400 kV over
the base case diminishes. However, even at the worst case of 10%, the advantage is
still $66 million.

5 The sensitivity results are the weighted average over all scenarios assuming that each scenario
carries an equal weighting of 20%.
Part IV - Cost Benefit Analysis
18

Sensitivity - Discount Rate
Sensitivity - Weighting on Scenario 4
Expected Net Market Benefit of 400kV
Expected Net Market Benefit of 400kV
300
200
250
d
e
150
200
ount
c
ounted 100
150
disc
100
n
illion dis
o 50
li
$m
il
50
m
$
0
0
0%
20%
40%
60%
80%
100%
4%
5%
6%
7%
8%
9%
10%
-50
Discount Rate Variation

Scenario 4 Weighting
Sensitivity - O & M Variation
Sensitivity - Value of Losses
Expected Net Market Benefit of 400kV
Expected Net Market Benefit of 400kV
133.2
200
180
133.1
160
ted
n
133
u
140
ounted
132.9
120
isco
d
100
132.8
disc 80
on
li
132.7
il 60
$million
m
$ 40
132.6
20
132.5
0
-30%
-10%
10%
30%
-50%
-30%
-10%
10%
30%
50%
Cost Variation
Loss Value Variation
Sensitivity - Capital Cost Variation
Expected Net Market Benefit of 400kV
180
160
140
120
scounted 100
di
80
60
llion
40
$mi
20
-
-10%
10%
30%
50%
Cost Variation

Figure 5-2: - Sensitivity Chart of Expected Net Market Benefit of 400 kV over Base Case

The analysis is fairly sensitive to the value of losses and this is to be expected given that
this is a key point of difference in assessing the relative benefits of the project. However,
it should be noted again, that even if the value of losses is decreased by 50% this would
equate to an average marginal cost of generation of around $43/ MWh in 2025. This is
less than the SRMC of a coal fired plant excluding any carbon tax. Transpower therefore
considers that the loss figures used represent a reasonable view of their future value.

The weighting for Scenario 4 was also sensitised given that this is the scenario which
favours the base case to the greatest degree. All other scenarios had an equal weighting
applied. The significance of Scenario 4 and this sensitivity was discussed previously.

It was not considered necessary to sensitise the other scenarios as this would only
provide different variations of positive expected net market benefit.
Part IV - Cost Benefit Analysis
19

The cost sensitivities were applied to both the 400 kV and the 220 kV6 total costs and
since the 220 kV total costs are higher than the 400 kV total costs, the benefit of the 400
kV increases as the capital costs increase.

6  Expected Net Market Benefit of the proposed 400 kV
HVAC grid augmentation

The Electricity Governance Rules provide that the grid investment test7 is to be applied
by the Board (the Electricity Commission) to review and approve reliability investments
and economic investments.

Furthermore,  the grid investment test (see Schedule F4 to Schedule II of Part F of the
Electricity Governance Rules) states that:

4. “A
proposed investment satisfies the grid investment test if the Board (now
the Electricity Commission) is reasonably satisfied that :

4.1. the
proposed investment maximises the expected net market benefit
compared with a number of alternative projects ;
4.2. the
expected net market benefit of the proposed investment is greater
than zero; and
4.3.  if sensitivity analysis is conducted, a conclusion that a proposed
investment satisfies clauses 4.1 and 4.2 is sufficiently robust having
regard to the results of that sensitivity analysis.”

Transpower considers that its economic analysis and methodology is consistent with that
required under the Grid Investment Test.

This estimation of the expected net market benefit has been carried out and included in
this submission for the sole purpose of assisting the Electricity Commission considering
its position.

In seeking to establish the net market benefit for a particular grid augmentation,
Transpower has to rely on an assumption that the generation scenarios included in the
particular  market development scenarios used to determine the net market benefit
contain sufficient generating capacity to meet the electricity requirements of New
Zealand as a whole. Otherwise, there will be a concern that the results will contain an
artefact arising from insufficient generation in the scenarios used. In developing its own
generation scenarios, Transpower has been particularly careful to ensure that provision
has been made for sufficient generation throughout New Zealand.

The expected net market benefit has been calculated by undertaking the same analysis
as used for the “do nothing” analysis in section 4, but with the proposed 400 kV double
circuit line from Whakamaru to Otahuhu only in service. In the “do nothing” base case,
no transmission is built and there is a cost associated with unserved energy in the
Auckland and North Isthmus regions.

6 It is considered unlikely that there would be a significant variation in the 400 kV costs which
would not also be reflected in the base case costs, hence, the sensitivity was applied equally to
both cases.
7 The italicised terms defined in the Electricity Governance Rules
Part IV - Cost Benefit Analysis
20

The “present value” of unserved energy that would be avoided by the proposed reliability
investment comprising a 400 kV double circuit line from Whakamaru to Otahuhu is
calculated, and this is compared to the “present value” cost of the proposal.

Isolating Avoided Unserved Load
to One Investment
5,000
4,500
4,000
3,500
Unserved load avoided by
further developments
3,000
2,500
MW
Unserved load avoided by first investment
2,000
Current Transmission
Upgraded Transmission
Limit
Limit
1,500
1,000
500
-
2005
2010
2015
2020
2025
2030
2035
2040

Figure 6-1: Illustration of Unserved Load Avoided by Initial 400 kV Investment

Figure 6-1 is an illustration of how unserved load can be isolated to one transmission
investment.  The avoided unserved load (MW) figure is the area shown in green which is
the difference between the existing load capacity in Auckland and North Isthmus area
and the future load capacity once the proposed investment has been built. The area in
red is the unserved load that would be avoided by subsequent investments such as
further grid augmentation or development of major generation in the Auckland area or
north of Auckland.

The unserved energy associated with the proposed reliability investment is calculated
separately for each market development scenario. In this analysis, the unserved energy
figure used in the analysis is the average result over 1,000 demand paths lying between
the maximum and minimum load forecast so that the results are robust for a range of
load developments (effectively the “expected” unserved energy that will be avoided by
building the first 400 kV investment).

In this analysis, the transmission option under consideration is the proposed 400 kV
augmentation of the North Island grid between Whakamaru and Otahuhu and the
expected net market benefit of this proposal is to be evaluated. Because it is common to
all generation scenarios, the estimated present value cost of implementing the proposed
investment as well as reinforcing the the 220 kV network across the Auckland Isthmus8 is
set separately in Table 6-1 below. Care should be taken in comparing this table with the
capital cost estimates shown elsewhere in this submission as the costs are “present

8 The investment costs to reinforce the Auckland isthmus are included because without this
reinforcement, demand will not be able to be supplied at peak times to the North Isthmus and
Northland. Therefore the in order for the proposed investment to be credited with serving the
North Isthmus and Northland demand the cross Auckland reinforcement must be included.
Part IV - Cost Benefit Analysis
21

valued” and also contain a 40 year estimate of the operation and maintenance costs of
the proposal.

Present Value Costs of Building, Operating and
Maintaining the Proposed 400 kV
Reliability Investment

$million
Line + Cable capital costs
309
Substation capital costs
73
Property 85

Dismantling costs
2
Project Management Costs
38
Approval Costs
10
Operation & Maintenance
15
Preliminary Design & Investigatio
10
Total Costs
542

Table 6-1 - Present Value Cost of the Proposed Investment
Table 6-2 below shows the results of the cost benefit analysis over all scenarios for the
proposed investment including the necessary cross Auckland Isthmus 220 kV
reinforcements. The average column shows the weighted average assuming each
scenario carries an equal weighting of 20% each.

Expected Net Market Benefit of Proposed 400 kV Reliability Investment for Transpower’s
Generation Scenarios
$million discounted
Scenario Number ¨
No.1
No. 2
No. 3
No. 4
No. 5
Average
Avoidance of unserved energy
3,830
7,118
42,911   49,115   36,073   27,809
Less total cost of proposed 400 kV
reliability
investment
542 542 542 542 542 542
Net Market Benefit
Proposed 400 kV Investment
3,288  6,575 42,369 48,573
35,530
Expected Net Market Benefit
Proposed
400
kV
Investment
27,267

Table 6-2 – Expected Net Market Benefit of First 400 kV Investment

The average expected net market benefit assuming it is relevant to give all generation
scenarios the same weight is $ 27,267 million.

Three conclusions may be drawn immediately from this Table 6-2 as follows:

(i)  the numbers obtained from such an analysis are extremely large being many
billions of dollars,
(ii)  the range of the net market benefits is extremely large being from $3.3 billion to
$48.6 billion,

The reason the numbers are extremely large is that the net market benefit is evaluated
over a period of 40 years on the basis that the proposed reliability investment will not be
built. Quite clearly, if the proposed reliability investment is not built and the national
welfare suffers losses of the order of magnitude indicated in the above table, then some
form of alternative development would likely take place to remedy the situation.

Part IV - Cost Benefit Analysis
22

Transpower concludes the following from the numbers in Table 6-2:

(i)  that Scenario 1 appears to be the least robust for the proposed reliability
investment.  This is because Scenario 1 includes a substantial amount of base
load generation near Auckland or in the North Isthmus using gas as a fuel but
this is dependent upon further discoveries of gas in commercial quantities and
new gas transmission infrastructure. The postulated development does not
provide for new generation in a time-frame that adversely affects the economic
value of proceeding now with a 400 kV development but the availability of local
generation reduces the quantum of unserved energy in the longer term.

(ii)  that Scenario 4 is the most robust for the proposed reliability investment. This
raises questions as it has been shown in Section 5 of this Part IV that for
Scenario 4, the proposed 400 kV grid augmentation is the least attractive when
compared with continued development of the 220 kV grid.  The reason for this is
that Scenario 4 has the least amount of generation in the immediate Auckland
area and there is greater reliance in the longer term on the transmission grid
south of Auckland to provide security of supply and minimise the unserved
energy.

(iii)  While the assumed termination of a new HVDC link from the South Island in or
near Auckland diminishes the long term value of the proposed 400 kV grid
augmentation, in the longer term with the new HVDC link in service, it is
necessary to have the augmented transmission between Whakamaru and
Otahuhu in service to continue to supply some 2000 MW into Auckland. It has
been indicated earlier in this section that the 400 kV HVAC option would reduce
transmission losses and minimise the use of easements to achieve this end.

6.1  400 kV Line Sensitivity Analysis Results

Table 6-3 and Figure 6-2 below shows the results of the various sensitivities applied to
the cost/ benefit analysis. Table 6.3 shows the expected net market benefit of the 400 kV
development plan over and above base case9.

Expected Net Market Benefit
- $million discounted
Sensitivity
Benefit
Base Case without Sensitivity applied
27,267
4% discount rate
55,793
10% discount rate
15,893
Unserved load value - $10,000/ MWh
13,364
Unserved load value - $30,000/ MWh
41,173
0% weighting on Scenario 1
33,263
40% weighting on Scenario 1
21,274
Capital costs + 50%
27,009
Capital costs -10%
27,320
O & M costs + 30%
27,265
O & M costs -30%
27,272
Table 6-3: Expected Net Market Benefit Against Various Sensitivities

9 Apart from the ‘weighting” sensitivity, the sensitivity results show the weighted average ENMB
over all scenarios assuming that each scenario carries an equal weighting of 20%.
Part IV - Cost Benefit Analysis
23

Sensitivity - Discount Rate
Sensitivity - Cost of Unserved Energy Cost
ENMB of 400kV First Investment
ENMB of 400kV First Investment
60,000
80000
70000
50,000
60000
ENMB at base discount
ed
ed 40,000
50000
ount
c
scount
s 40000
30,000
illion di
llion di 30000
ENMB at base value of $20,000/
$m 20,000
$mi
20000
10,000
10000
0
-
$5,000
$15,000
$25,000
$35,000
$45,000
4%
6%
8%
10%
Unserved Energy Cost Variation ($/ MWh)
Discount Rate Variation

Sensitivity - Weighting on Scenario 1
Sensitivity - Capital Cost
ENMB of 400kV First Investment
ENMB of 400kV First Investment
35,000
27,600
30,000
27,400
ENMB at base weighting of 20%
ENMB at base capital cost
27,200
25,000
d
ted
te
n
n
u
u
o
27,000
o
20,000
c
c
is
d
n
26,800
15,000
illion dis
illio
m
$m
$
26,600
10,000
26,400
5,000
26,200
-
-50%
-30%
-10%
10%
30%
50%
70%
90%
0%
20%
40%
60%
80%
100%
Weighting
Cost Variation

Sensitivity - O & M Cost
ENMB of 400kV First Investment
27,280
27,275
27,270
ed
ENMB at base O & M cost
scount 27,265
n di
llio 27,260
$mi
27,255
27,250
27,245
-50%
-30%
-10%
10%
30%
50%
70%
90%
Cost Variation

Figure 6-2: Sensitivities of the Initial 400 kV Investment

As expected when comparing the proposal to a base case of “no transmission”, any
reduction in the discount rate will reduce the expected net market benefit of the proposal,
however even at a rate of 4%, the expected net market benefit of is still $27,200 million
positive.

Variations in the cost of unserved energy affects the expected net market benefit of most
significantly of all the sensitivities, but again, even at the low value of $5,000/ MWh, the
expected net market benefit of is still positive at $6,411 million.

The sensitivity around the weighting of the scenarios was tested on Scenario 1, which
returns the lowest expected net market benefit of due to the significant amount of
modelled generation in the Auckland/ North Isthmus region in this scenario. The
weighting on all other scenarios is assumed to be equal when varying Scenario 1’s
Part IV - Cost Benefit Analysis
24

weighting. At the extreme of raising this Scenario’s weighting to 100%, the expected net
market benefit of is still $3,289 million positive.

The cost sensitivities demonstrate that the analysis is robust against significant cost
variations with very little variation around the base value - even if costs were to double
the expected net market benefit of the proposal would still be in excess of $26 billion.
6.2  400 kV Line using the Electricity Commission’s Scenarios

A sensitivity analysis has been undertaken using the Electricity Commission’s generation
scenarios which form part of the Statement of Opportunities.

The Electricity Commission’s scenarios all contain less generation in the upper North
Island than Transpower’s resulting in Transpower’s scenarios providing a harder
economic test for the proposed 400 kV line between Whakamaru and Otahuhu. This can
be demonstrated by sensitising the economic analysis using the Electricity Commission’s
2005 Generation Scenarios10.

Given that there is substantially less assumed generation in the Auckland/ North Isthmus
region under the Electricity Commission’s scenarios than in the scenarios used in this
analysis, the proposed investment will essentially avoid a larger proportion of the
potential unserved energy. As a result the accrued benefits of the proposed investment
will be higher.

Table 6-4 below shows the results of the economic analysis using the benefit of the
avoided unserved energy under the Electricity Commission’s generation scenarios. The
average column shows the weighted average assuming each scenario carries an equal
weighting of 20% each.

$million discounted

Scenario Number ¨
No. 1
No. 2
No. 3
No. 4
No. 5
Average
Avoidance of unserved energy
13,086  32,207  97,375  101,838   58,263   60,554
Less total cost of proposed 400 kV  542
542
542
542
542
542
reliability investment
Net Market Benefit 400 kV
Investment
12,544  31,665  96,833  101,295   57,720
Expected Net Market Benefit 400 kV
Investment
      60,011
Table 6-4: Expected Net Market Benefit of first 400 kV Investment under Electricity
Commission Scenarios
As mentioned above, the benefit from avoidance of unserved energy is over twice that
shown in the analysis using Transpower’s generation scenarios.  As a result, the
Expected Net Market Benefit is over twice that from using Transpower’s scenarios, at
$60,011 million.

10 For this exercise Transpower has used the generation scenarios published in the “Initial
Statement of Opportunities” dated May 2005.
Part IV - Cost Benefit Analysis
25

7  Alternatives to transmission which may economically
defer transmission

Section 6 concluded that building the proposed 400 kV double circuit line from
Whakamaru to Otahuhu, in 2010, has a positive expected net market benefit, under a
range of reasonable scenarios.  This section considers whether there are any
alternatives to transmission which might economically defer the need for transmission in
2010.
7.1  Request for Information document

As discussed in Part III of this report, Transpower’s approach to the question of an
alternative to transmission deferring the need for the grid augmentation, was to issue a
Request for Information document seeking information on potential “transmission
alternatives” (the term used in the Electricity Governance Rules).
Part III also describes the analysis of the submissions received in response to the
Request for Information and identifies the following alternatives to transmission as
qualifying for further consideration.
•
Load Shedding Bidding programme targeting peak demand reductions
•
Peaking generation plant, diesel fired
•
Base-loaded generation plant, gas fired

7.1.1  Load Shedding Bidding Programme

Although there is potential for a load shedding bidding programme to deliver peak MW
load savings, no programmes are known to operate at present. Hence, there is
considerable uncertainty about whether such a programme could deliver the quantity of
load and certainty required in the Auckland area to defer transmission with the required
degree of confidence.

The proposal did not provide adequate information on these matters. Particular
questions that would need to be resolved relate to the total amount of sheddable load in
the Auckland area and the extent to which a Load Shedding Bidding Programme would
compete for sheddable load already available for other purposes. If sheddable load in
the Auckland area is a scarce resource, then introducing a load shedding bidding
programme may just serve to push up the prices being asked for instantaneous reserve.
Because of these uncertainties, and the lack of data, this scheme is not considered as a
viable alternative to transmission at this stage.

However Transpower has sponsored an independent investigation of such a programme
to assess its potential benefits and to develop a design and implementation strategy.

7.1.2 Generation
plant

Only the diesel fired peaking plant and gas fired base-loaded plant generation proposals
are considered as potential contenders from an economic perspective at this stage.

Cost/benefit analysis has been undertaken to determine whether the use of such
alternatives to transmission would have a positive expected net market benefit.

The analysis does not take a view on the form of the arrangements that would need to be
in place to enable such alternatives, but does assume that the contractual arrangements
Part IV - Cost Benefit Analysis
26

would mean that the generation would be available to be dispatched, as and when
required by Transpower. The practical use by Transpower of local generating plant,
particularly for the base-loaded generation, has not been considered as such a generator
would be a participant in the overall energy bidding market and Transpower has no place
there.

7.2  Approach to evaluate alternatives to transmission to defer
transmission

Rather than consider the particular generation plants offered in the RFI, a more generic
approach was taken, whereby diesel generation equivalent to 1, 2, 3 and 4 years worth
of demand growth (assuming medium demand growth) was considered. The applicability
of these results to the economics base-loaded generation are discussed separately.

Costs

The capital and operating costs used, were sourced from various sources including
Parson Brinckerhoff Associates “Thermal and Geothermal Generation Plant Capabilities”
report, dated December 2004 and East Harbour Limited’s “Cost of Fossil Fuel
Generating Plant” dated September 2002.

Capital
Fixed costs
Fuel costs
Other
cost
$m/MW/annum
$/MWh
variable costs
$m/MW
$/MWh
1 0.019  164.86
8.00
Table 7-1: Diesel Peaking Plant Capital and Operating Costs
It is not clear what value should be assigned to the residual value of the diesel plant after
1, 2, 3 or 4 years use. The plant might either be scrapped entirely, or if constructed in
such a way as to be moveable, it could be transported elsewhere for use. For the
purposes of this analysis, the economics have been calculated assuming both no
residual value and a 50% residual value.

Benefits
The primary benefit of deferring the 400 kV HVAC proposal past 2010 is that the capital
cost of the 400 kV HVAC proposal is deferred. This equates to approximately a $24
million per annum saving on the capital cost of the whole project, or $17 million per
annum saving if the property and easement costs are excluded.

Of the other benefits considered:

•  Energy loss differences
•  Differences in energy costs
•  Differences in carbon costs
•  Differences in ancillary service costs
•  Generation reliability value difference

The first three were considered using SDDP11 to determine an optimum national
generation dispatch for each size of peaking generation. The model was optimised on a
short run marginal cost basis for generation costs, rather than making assumptions about

11 Stochastic Dual Dynamic Programme
Part IV - Cost Benefit Analysis
27

market participant bidding behaviour. This approach ensures that the dispatch results are
minimum cost from a national perspective, as required by the Grid Investment Test.

By calculating the cost of the national dispatch in this manner, the differences due to the
first three benefits above, are all captured.

Ancillary service costs are calculated assuming:

−
Reserve costs will not vary. Reserves are purchased based on the largest
single generating unit in each island. Although transmission constraints can
result in “islanded” demand, reserves are not purchased to cover regional risks
caused by such islanding.

−
Voltage support costs will vary. It is assumed for the purpose of this analysis
that demand met using peaking generation will not require voltage support, but
that if the same demand is met using transmission, then voltage support will be
required. Actual 2004 voltage support costs for Zone 1 are used as the
forecast cost for future voltage support.

Generation reliability differences are calculated using the methodology previously
described. The estimated unserved energy in the Auckland/North Isthmus area for each
transmission/generation configuration is calculated and valued at $20,000 per MWh.

Results
The results are summarised in Table 7-2 below for the case where all of the costs
associated with the proposed 400 kV gird augmentation (including property and
easement costs) are deferrable.
Part IV - Cost Benefit Analysis
28

$ million (discounted)
Peaking
Peaking
Peaking
Peaking
plant
plant
plant
plant
1 year
2 years
3 years
4 years
deferral
deferral
deferral
deferral
Total 400 kV cost deferred, Zero residual value for generation
Costs

Capital cost generation12
54  104 152 196
Benefits

Deferred
transmission
cost
24 46 67 87
National dispatch cost benefit
0
-1
-2
-7
Voltage support cost benefit
1
2
4
6
Generation reliability cost benefit
-70
-127
-170
-197
Residual value peaking plant
0
0
0
0
Total benefits
-45 -80 -102
-111
Expected net market benefit
-98
-184
-253
-307

Total 400 kV cost deferred, 50% residual value for generation
Costs

Capital
cost
generation
54  104 152 196
Benefits

Deferred
transmission
cost
24 46 67 87
National dispatch cost benefit
0
-1
-2
-7
Voltage support cost benefit
1
2
4
6
Generation reliability cost benefit
-70
-127
-170
-197
Residual value peaking plant
23
43
60
74
Total
benefits
-22 -37 -42 -37
Expected net market benefit
-75
-141
-194
-233
Table 7-2: Expected Net Market Benefit of Installing Diesel Fuelled Plant in the Auckland
Area to Defer Transmission Augmentation Assuming Property & Easement Costs are
Deferrable
Table 7-3 shows the corresponding result if the property costs are taken not to be
deferrable.


12 Note that these costs do not include land costs, installation costs, project management costs,
etc, and so are not determined on the same basis as transmission . Neither do they include the
cost of other infrastructure required e.g. noise abatement, diesel storage tanks, or a diesel
pipeline.

Part IV - Cost Benefit Analysis
29

$ million (discounted)
Peaking
Peaking
Peaking
Peaking
plant
plant
plant
plant
1 year
2 years
3 years
4 years
deferral
deferral
deferral
deferral
Partial 400 kV cost deferred, Zero residual value for generation
Costs

Capital
cost
generation
54  104 152 196
Benefits

Deferred
transmission
cost
17 33 48 62
National dispatch cost benefit
0
-1
-2
-7
Voltage support cost benefit
1
2
4
6
Generation reliability cost benefit
-70
-127
-170
-197
Residual value peaking plant
0
0
0
0
Total benefits
-52
-93
-121
-136
Expected net market benefit
-105
-197
-273
-332

Partial 400 kV cost deferred, 50% residual value for generation
Costs

Capital
cost
generation
54  104 152 196
Benefits

Deferred
transmission
cost
17 33 48 62
National dispatch cost benefit
0
-1
-2
-7
Voltage support cost benefit
1
2
4
6
Generation reliability cost benefit
-70
-127
-170
-197
Residual value peaking plant
23
43
60
74
Total
benefits
-29 -51 -61 -62
Expected net market benefit
-82
-154
-213
-258
Table 7-3 - Expected Net Market Benefit of Installing Diesel Fuelled Plant in the Auckland
Area to Defer Transmission Augmentation Assuming Property & Easement Costs are Not
Deferrable
7.3 Sensitivities

The results for the most favourable case (ie the case with the highest expected net
market benefits), where the total cost of the 400 kV AC proposal is deferred and the
peaking plant has a 50% residual value, have been sensitised for uncertainty in the cost
estimates and the benefit costs, with the following results:

$ million (discounted)
Sensitised
Expected Net Market Benefit
value

Peaking
Peaking
Peaking
Peaking
plant
plant
plant
plant
1 year
2 years
3 years
4 years
deferral
deferral
deferral
deferral
Transmission cost
-10%
-78 -146 -200 -242
Transmission cost
0
-75 -141 -194 -233
Transmission cost
+50%
-63 -118 -160 -190
Generation cost
-30%
-67 -123 -168 -199
Generation cost
0
-75 -141 -194 -233
Generation cost
+30%
-84 -159 -220 -268
Table 7-4: Expect Net Market Benefit After Sensitivities Analysis of Peaking Plant

Part IV - Cost Benefit Analysis
30

7.4 Conclusion

The expected net market benefit of installing diesel peaking generation and deferring the
400 kV HVAC proposal is negative under all conditions considered in the analysis. It is
concluded that building the 400 kV AC proposal in 2010, rather than using alternatives to
transmission to defer the proposal, is a robust investment.
8 Summary

The cost benefit analysis has demonstrated that, under a range of reasonable scenarios
and sensitivities, building the proposed 400 kV double circuit line from Whakamaru to
Otahuhu, in 2010, produces a positive expected net market benefit compared to “do
nothing” and also that the 400 kV proposal has the highest expected net market benefit
of the transmission options considered.

The analysis also demonstrates that the large scale base-loaded generation as set out in
both Transpower’s and the Electricity Commission’s generation scenarios do not
substitute for transmission. Furthermore the analysis shows that diesel fired peak
generation plant is not an economic alternative to transmission.

Therefore, the cost/benefit analysis has demonstrated that the proposed augmentation of
the grid between Whakamaru to Otahuhu at 400 kV and associated substation works in
2010, is economic and should be recommended.

This analysis is consistent with the Grid Investment Test required for such a Reliability
Investment under the Electricity Governance Rules and demonstrates that the 400 kV
proposal meets the requirements of that test.

Part IV - Cost Benefit Analysis
31