Electricity Commission turns down Transpower's proposed 400kV Whakamaru - Otahuhu line to be installed by 2010: A review

Garry Downs, Partner and Louise Hill, Senior Associate | May 2006

Introduction

The Electricity Commission issued its draft decision to turn down Transpower's grid upgrade proposal to construct a 400kV line linking Whakamaru and Otahuhu by 2010 on 27 April 2006.

In this note, we examine the reasons behind the Commission's draft decision and set out the future timetable for consultation. In summary:

Key points

Transpower Proposal:
To construct a new 400kV double circuit line between Whakamaru and Otahuhu.

Electricity Commission Draft Decision:
Unanimous decision not to approve the proposal (draft decision only).

Rationale for Commission's decision:
The proposal reflects good industry practice in meeting the grid reliability standards; and

Transpower has complied with the processes set out in the Rules; but

the proposal does not meet the requirements of the grid investment test, as it does not maximise the expected net market benefit or minimise the expected net market costs when compared with a number of alternative projects.

Next steps:
A designated transmission customer, an authorised representative of parties substantially affected by the grid upgrade proposal or Transpower may, by 11 May 2006, request the Commission to hold a public conference.

The Commission plans to hold hearings in Manukau and Hamilton on 1 and 2 June for people to make oral submissions.

The Commission welcomes submissions from any person. Written submissions must be made to the Commission by 9 June 2006.

If requested, the Commission plans to hold a public conference in Wellington on 6 and 7 July.

The Commission intends to release its final decision in late July.

The Commission set out at the end of its draft decision a number of questions that it invites responses on.

Background to the proposal

Transpower proposed the construction of a new 400kV double circuit line between Whakamaru and Otahuhu. This construction was proposed as the first step in accomplishing Transpower's long-term strategic vision for 400kV to replace 220kV as the core grid transmission voltage.

Transpower submitted that the proposal is necessary to avoid an increase in risk to security of supply in the Auckland and Northland region at times of peak loading from 2010 and because:

• there are no generation alternatives committed in the Auckland region that would defer or avoid the need for transmission investment;
  
  
• Transpower has not been able to identify other alternatives to transmission that are reasonably likely to occur in the Auckland region, and that would defer or avoid the need for transmission investment;
  
  
• the proposal is the most economic transmission option based on a market benefit analysis; and
  
  
• environmental impacts have been taken into account in determining the proposed investment.

Transpower's economic analysis resulted in the following conclusions (as summarised by the Commission):

• a 400kV development plan for the North Island is more economic than incremental augmentation of the 220kV network;
  
  
• a 400kV development plan for the North Island is more economic than a diesel-fired peaking plant;
  
  
• a new HVDC link from the South Island to a terminal in or near Auckland diminishes the long-term value of the proposed 400kV grid augmentation;
  
  
• a 400kV development plan for the North Island is more economic than "doing nothing" as there is not enough large-scale base-loaded generation forecast to occur in any of the generation scenarios to avoid significant amounts of unserved energy;
  
  
• Transpower's analysis satisfies the requirements of the grid investment test and its sensitivity analysis covers variables that have a major impact on the results; and
  
  
• competition benefits may be significant but more work is required.

The Commission's role

Transpower's proposal to construct the 400kV line is an "investment proposal", which was part of a grid upgrade plan submitted to the Commission for approval.

If the Commission approves the investment proposal, this allows Transpower to recover the approved costs of that investment from designated transmission customers in accordance with the transmission pricing methodology set out in section IV of Part F of the Electricity Governance Rules 2003 (Rules).

The Commission is required to consider and assess Transpower's proposal in accordance with the processes and considerations set out in section III of Part F of the Rules. In particular, rule 13.4 provides that, in order to be able to approve the proposal, the Commission must be satisfied that the proposed investment:

• reflects good electricity industry practice in meeting grid reliability standards;
  
  
• complies with the processes set out in the rules; and
  
  
• meets the requirements of the grid investment test. The grid investment test is set out in clause 4 of Schedule F4, and essentially requires that a proposed investment that is necessary to meet the reliability standard must maximise the expected net market benefit or minimise the expected net market cost compared with a number of alternative projects and that such conclusion is sufficiently robust having regard to the results of a sensitivity analysis (if one is conducted).

The Commission's Draft Decision

Alternatives proposed by Commission

• installing a new 400kV transmission line between Whakamaru and Otahuhu in about 2017, with a set of low-cost intermediate investments to ensure security of supply to 2017;
  
  
• installing a new 220kV transmission line between Whakamaru and Otahuhu in about 2017 with a set of low-cost intermediate investments to ensure security of supply to 2017;
  
  
• installing a new HVDC link between Whakamaru and Otahuhu in about 2017, again with a set of low-cost intermediate investments to ensure security of supply to 2017; or
  
  
• installing a new 400kV transmission line between Whakamaru and Otahuhu in about 2021, duplexing two of the Whakamaru to Otahuhu 200kV lines (adding extra conductors beside existing ones on the same towers to increase capacity), as well as completing a set of low-cost intermediate investments to ensure security of supply to 2021.

Compared to Transpower's proposal, all the alternative projects involve intermediate investments that make more major investment unnecessary for a number of years.

The Commission noted in its briefing on 27 April 2006 that such intermediate investments are not "band aids" but are good electricity practice, supported by international experience.

Real options which may materially influence evaluation

• By virtue of delaying an investment, a real option is created because an option exists to change or further modify investment plans if demand growth turns out to be lower than expected, or if local generation is constructed.
  
  
• Staged investments (such as the HVDC alternative project) may be modified to utilise new technology if it becomes available, e.g. HVDC with 350kV polyethylene cable or gas-insulated line. The value of this option was not calculated by the Commission as the Commission considered that the value was not readily quantifiable, although it did observe that the benefit would likely be in favour of the alternative projects.
  
  
• Excess transmission capacity potentially enables generation investments to respond quickly to new generation opportunities. While the alternative projects and Transpower's proposal result in similar transmission capacities into the Auckland region, Transpower's proposal would create excess capacity over the alternative projects between 2010 and 2017. Transpower values this at approximately $190 million, but the Commission places little value on this, assessing the benefits at $5 million. The difference, according to the Commission, arises from a different view as to the likelihood of excess generation being developed by the market and the degree to which Huntly generation may be constrained.

Limitation of Transpower's analysis

Transpower's economic analysis of the alternatives to its proposal was largely limited to a comparison of development plans for the entire North Island at the 220kV and 400kV voltage levels, and delay to the proposal through use of diesel peaking plant. Many of the modelled projects presented by Transpower were independent of transmission into Auckland. Even if 400kV were chosen over 220kV for a national transmission development plan, 400kV transmission from Whakamaru to Otahuhu may not necessarily need to be part of that greater plan.

The Commission considered that Transpower has not adequately analysed the credible alternative project consisting of a new 220kV line into Auckland, and has only applied the grid investment test to one alternative project, namely a diesel peaking plant.

The Commission's estimate of capital costs

Proposal	2010 NPV cost
400kV in 2010	775
400kV in 2017	495
220kV in 2017	400
HVDC in 2017	493
400kV in 2021	607

Commission's conclusions

In analysing Transpower's proposal against the three criteria, namely whether the proposal reflects good electricity industry practice, complies with the processes set out in the Rules and meets the grid investment test, the Commission considered that:

• the proposal did meet good electricity industry practice, as the use of 400kV and higher AC transmission voltages is widespread in the developed and developing world; and
  
  
• Transpower had complied with the processes set out in the Rules; but
  
  
• the economic analysis provided by Transpower does not adequately meet the requirements of the grid investment test, primarily because Transpower has not satisfactorily considered a number of alternative projects as required by the grid investment test, since it dismissed a number of alternative transmission options based on criteria which are not consistent with the requirements of the grid investment test or the grid reliability standard. See the end of this article for the NPV of the projects, taking all costs and benefits into consideration.

Commission's draft decision

The Commission's draft decision is not to approve the Proposal.

Concurring opinion with reservations

Commissioner David Close prepared a separate statement that was attached to the end of the Commission's draft decision as Appendix 3, in which the Commissioner stated that he voted with the other Commissioners to decline approval of Transpower's proposal because it did not meet the requirements of the grid investment test when compared with the alternative transmission investment streams.

However, he stated that he has strong reservations about the way in which the grid investment test itself has been developed and applied. The Commissioner's view is that in developing and refining the test attention has been diverted from some of the objectives of the grid investment test (such as promoting certainty for investment) and from the prime purpose of the investment rules, which is to facilitate Transpower's ability to develop and implement long-term plans for investment in the grid.

In addition, the Commissioner considered that the process of identifying alternatives to Transpower's proposal has led to evaluating Transpower's proposal solely as a Whakamaru-Otahuhu transmission upgrade instead of the first stage of a longer term plan for a higher voltage over the North Island core grid.

This approach does not have sufficient regard to the "prudence and foresight" which is emphasised in the Commission's definition of good electricity industry practice.

Differences between Transpower's approach and Commission's approach

The main differences between Transpower's approach and the Commission's approach that led the Commission to conclude that the proposal did not meet the grid investment test are as follows:

1. Transpower contends that the Commission's grid investment test analysis adopts a "just in time" approach to transmission and accordingly places too great a value on delaying transmission investment. However, the Commission considers that its assessment considers risk in a symmetrical and conservative manner, erring on the side of increased reliability. The Commission's view is that since an n-g-1 security outcome is economic and achievable, ample time exists to arrange temporary measures due to any possible project delay, and without risking a significant increase in expected unserved energy.
   
   
2. The Commission placed considerable value on delaying investment, giving time to consider advances in technology or changes in the electricity system that may mitigate against a new line being needed for Auckland, such as new generation in Auckland or Northland. The Commission considered that in the period between now and when additional transmission capacity may be required, additional information will become available in relation to demand growth, commitment of additional generation capacity and technological advances for transmission that may shape the form and timing of subsequent grid upgrades.
   
   
3. The Commission's estimate of the capital cost of Transpower's proposal was higher than Transpower's estimate. The Commission considered that the main reasons were the higher cost of switchgear and lines assessed by the Commission's consultants.
   
   
4. The Commission considered that Transpower's analysis did not consider all alternative proposals and that its analysis of the benefits of its proposal were over-stated. Transpower's base case was continued development of the 220kV grid. Transpower considered that augmentation of the grid was needed, as there was no guarantee of sufficient new generation in the Auckland and Northland area to overcome transmission constraints, and that the 400kV development had significant benefits over continued development of the 220kV grid. Transpower did not, however, appear to consider in any depth delaying of the investment. The most likely transmission alternative considered by Transpower was a diesel-fired peaking plant, and the 400kV development was favoured over that option.

According to newspaper reports (The Dominion Post, 28 April 2006) Transpower does not support the grid investment test developed by the Commission and did not "comprehend" it, which means that it cannot consider potential amendments to the proposal. In addition, Transpower stated that its proposal would provide more secure supply than alternatives, and the more the investment was delayed the more risk and the more intermediate projects will be needed. Transpower considers that the Commission's alternative proposals require median load and a whole range of projects being delivered in time and in sequence.

Easements

In conjunction with submissions on Transpower's proposal and the draft decision, the Commission also seeks views on the value in progressing at this stage a transmission corridor that would accommodate a range of technologies. Establishing such a corridor would provide greater certainty to landowners and to Transpower in its grid planning function.

The Commission will also be considering whether changes to legislation may be necessary to allow Transpower to progress the transmission corridor. At its briefing on its draft decision the Commission commented that land issues were becoming increasingly more important for transmission and that if issues between landowners and Transpower are not resolved soon, there will be a crisis as Transpower faces difficulties in accessing land to maintain the transmission lines.  

Capital Costs of Transpower's Proposal and Alternative Projects (in $m 2010)

Year of investment	400kV in 2010	400kV in 2017	220kV in 2017	HVDC in 2017	400 kV in 2021
2010	709	63	63	63	296
2016	0	32	32	32	32
2017	73	762	479	553	0
2018	0	0	0	0	32
2020	32	0	0	0	32
2021	0	0	0	331	769
2022	32	0	60	0	0
2023	0	0	97	0	0
2024	41	67	0	0	0
2025	0	0	0	64	1
2026	4	0	127	42	0
NPV (as at 2010)	802	585	493	624	718

NPV Summary of Modelled Proposal and Alternative Projects ($m 2010)

	400kV in 2010	400kV in 2017	220kV in 2017	HVDC in 2017	400kV in 2021
Mean PV capital cost (A)	775	495	400	493	607
Mean PV O&M cost (B)	15	6	3	10	3
Mean PV net loss cost (C)	0	76	118	74	109
Mean PV net reliability benefits (D)	0	5	15	13	15
Mean PV terminal benefit (E)	31	30	6	15	45
Mean PV excess capacity benefit (F)	5	0	0	0	0
Mean PV total cost (A+B+C-D-E-F)	754	541	499	549	658