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Major Electricity Users' Group Inc v Electricity Commission and another [2008] NZCA 536 (5 December 2008)

Last Updated: 10 December 2008


IN THE COURT OF APPEAL OF NEW ZEALAND

CA205/2008

[2008] NZCA 536


BETWEEN MAJOR ELECTRICITY USERS' GROUP INC
Appellant


AND ELECTRICITY COMMISSION
First Respondent


AND TRANSPOWER NEW ZEALAND LIMITED
Second Respondent


Hearing: 15 October 2008


Court: Glazebrook, Chambers and Baragwanath JJ


Counsel: J E Hodder SC and T D Smith for Appellant
D J Goddard QC and S M W Kilty for First Respondent
I R Millard QC and C J L Browne for Second Respondent


Judgment: 5 December 2008 at 4.00 pm


JUDGMENT OF THE COURT

A The appeal is dismissed.

  1. The appellant is to pay each of the respondents costs for a complex appeal on a Band B basis plus usual disbursements. We certify for second counsel.

____________________________________________________________________


REASONS OF THE COURT
(Given by Glazebrook J)
Table of Contents

Para No
Introduction [1]
Overview of legislative framework [5]

Electricity Act 1992 [6]

Government Policy Statement (GPS) [9]

Electricity Governance Rules 2003 [15]

Schedule F3 – Grid Reliability Standards (GRS) [29]

Schedule F4 – Grid Investment Test (GIT) [32]
Background [38]
Standard of review [54]
Interpretation of clause 4.1 of the GIT [58]

Issue [58]

MEUG’s submissions [59]

Change in MEUG’s position [61]

The position of the respondents [63]

The Commission’s decision [65]

Evaluation [66]
Failure to consider “alternative projects” [83]
Erroneous HILP assumption [89]

Background [90]

MEUG’s submissions [97]

Evaluation [98]
Relief [102]
Result [105]
Appendix One: Glossary of Abbreviations
Appendix Two: The Electricity Governance Rules [107]
Appendix Three: Decision-making Flow Chart
Appendix Four: Investment Examples [119]

Introduction

[1] The Major Electricity Users’ Group (MEUG) is the representative body of New Zealand’s major electricity users. The Electricity Commission is the statutory entity charged with ensuring the efficiency and reliability of the national electricity grid. Transpower is the sole operator of the grid and a state-owned enterprise.
[2] MEUG sought judicial review of a decision made on 30 August 2007 by the Commission under the Electricity Governance Rules 2003 (the EG Rules) to approve a proposal by Transpower to upgrade the Otahuhu substation. MEUG’s application was dismissed by Wild J in Major Electricity Users’ Group Inc v Electricity Commission HC WN CIV 2007-485-2508 14 March 2008.
[3] There are four issues in the appeal:

(a) Whether the Commission erroneously interpreted clause 4.1 of the Grid Investment Test (GIT).

(b) Whether the Commission failed to evaluate or require Transpower to evaluate appropriate alternative projects.
(c) Whether, in approving the proposal, the Commission adopted an erroneous figure for the HILP (high impact low probability) related reliability benefits.
(d) The relief that should be granted in the event that the Court is satisfied that a reviewable error occurred.
[4] Before turning to those issues, we set out the legislative context and more detail on the background. We also make some comments on the approach to judicial review in cases of this nature. For the convenience of readers, a glossary of abbreviations used is set out in Appendix One.

Overview of legislative framework

[5] Below is a summary of the legislative framework within which the Commission operates. For ease of reference, the most relevant provisions are set out in full in Appendix Two. We also provide in Appendix Three a diagram prepared by the Commission of its required decision-making process with regard to investments.

Electricity Act 1992

[6] The Commission is established under Part 15 of the Electricity Act 1992. It is the principal body responsible for the governance of the electricity sector and has between five and nine members: s 172R of the Electricity Act. These members must have the appropriate knowledge, skills and experience to assist the Commission to achieve its objectives and perform its functions: s 29 of the Crown Entities Act 2004.
[7] The statutory objectives of the Commission include ensuring that electricity is delivered in an efficient, fair, reliable, and environmentally sustainable manner: s 172N(1)(a) of the Electricity Act. Its functions are set out in s 172O. These include formulating and recommending (to the Minister) electricity governance regulations and rules and administering those regulations and rules. The process for making electricity governance regulations and rules is prescribed by ss 172D to 172K of the Electricity Act. The rules at issue in these proceedings were made by the Minister under s 172H.
[8] Section 172ZK allows the Minister to set objectives and outcomes for the Commission. These are communicated to the Commission in a Government Policy Statement (GPS). The Commission is required by s 172O(1)(j) to give effect to the objectives and outcomes in the GPS.

Government Policy Statement (GPS)

[9] The GPS relevant to this appeal was issued in October 2006. This was after a 12 June 2006 outage at Otahuhu (see at [39] below) and the current GPS reflects the Government’s concern to avoid a repetition of that event. The Foreword begins:

Foreword

The electricity sector has a critical role to play in underpinning the Government’s growth and sustainability objectives. Sustainable economic growth will best be supported by an electricity system that:

[10] The GPS objectives, at [80], include that grid reliability should be maintained at a level required by residential, commercial and industrial users and the Government’s economic development objectives and that the efficiency of transmission services should be continuously improved so as to produce the services grid users and consumers want at least cost.
[11] Of particular relevance to this proceeding, the GPS also lists, at [80], as an objective that the transmission grid should be adequately resilient against the effects of HILP events, having regard to the load which could be disrupted and the duration of any disruption. It also provides that the transmission grid should provide adequate supply diversity to larger load centres having regard to the load which could be disrupted and the duration of any disruption.
[12] The GPS recognises that a long term perspective is appropriate and that consideration of synergies with other projects is needed. It says, at [87A], that any grid upgrade plans (GUP) must be as comprehensive as possible, ideally covering and identifying the relationships among short, medium and longer term proposals in order to enable better consideration of the interrelationships between projects and the wider synergies from the grid.
[13] Paragraph [87C] provides that GUPs must demonstrate the rationale for all expenditure (operation, maintenance and capital), taking into account the prescribed reliability standards and good industry practice for power system operation. The plans should demonstrate that the proposed expenditure is required to meet reliability standards and/or deliver the greatest net benefit after taking into account transmission alternatives and government energy policy requirements.
[14] In [87D], the GPS spells out the separate roles of Transpower and the Commission. It says that Transpower should undertake the detailed planning role and the Commission should review and approve GUPs that meet the criteria set out in the EG Rules and reject applications that fail them.

Electricity Governance Rules 2003

[15] The EG Rules deal with investment in the national grid in Section III of Part F, entitled the Grid Upgrade and Investment Rules (the GUI Rules). These provide a comprehensive set of processes governing the establishment of standards concerning investment in the grid and the analysis of proposed investments by the Commission.
[16] The purposes of the GUI Rules are set out in rule 2. These include facilitating Transpower’s ability to develop and implement long term plans for investment in the grid.
[17] In broad outline, the GUI Rules provide for:

(a) The development by the Commission of, and criteria for, grid reliability standards (GRS) (rules 4 and 5), subsequently promulgated as Schedule F3 to the GUI rules (see below at [29] - [31]);

(b) The development by the Commission of, and criteria for, a GIT (rules 6 and 7), subsequently promulgated as Schedule F4 to the EG Rules (discussed below at [32] - [37]);
(c) The development by the Commission of, and criteria for, general assumptions and data to be used in the application of the GRS and GIT to specific investment proposals, including the determination of the assets that comprise the elements of the core grid (rules 5A and 5B), statements identifying opportunities for efficient management of the grid (rule 9), grid planning assumptions (rule 10) and a centralised data set (rule 11);
(d) The submission by Transpower to the Commission of GUPs containing proposed investments (rule 12); and
(e) The approval by the Commission (if appropriate to do so, consistently with the relevant provisions of the EG Rules, including the GRS and GIT provisions), of proposed investments (rules 13 and 14).
[18] Turning first to the process for submitting and approving investments, rule 12.2 provides that the purpose of a GUP is to enable Transpower to propose, and the Commission to review and approve, reliability investments justified on the basis of the GRS and the GIT and economic investments justified on the basis of the GIT. Under rule 12.2 Transpower is required to submit a GUP to the Commission (referred to as “the Board” in the Rules) within three months of receiving a request from the Commission.
[19] The required content of a GUP is specified in rule 12.3. This requires Transpower to disaggregate its investment plans into reliability investments and economic investments. Reliability investments are defined by the EG Rules as those investments, the primary effect of which is to reduce “expected unserved energy”. This is a forecast of the amount by which the demand exceeds supply “as a result of likely planned or unplanned outages”. Economic investments, are defined as those investments that are not reliability investments, but that can be justified on the basis of the GIT.
[20] For reliability investments, rule 12.3.3 requires that the GUP include the justification for the proposed reliability investments against the GRS and the GIT, together with any options considered in identifying the proposed reliability investments and the consequences of non-investment or delay in investment as well as the forecast costs.
[21] Before approving reliability investments, the Commission must, under rule 13.2, consult with persons the Commission thinks are representative of the interests of persons likely to be substantially affected by the reliability investments and the content of the draft GUPs. A timetable for consultation and approval must be agreed between Transpower and the Commission or, failing agreement, set by the Commission.
[22] Under rule 13.3.2 the Commission must publish a notice and provide an opportunity for designated transmission customers to provide written comment on Transpower’s proposed reliability investments (rule 13.3.2.1) and request that the Commission consider alternative investments (rule 13.3.2.2).
[23] The Commission may direct Transpower to investigate further, provide further information or to evaluate alternative reliability investments, including those which would result in differing probabilities of meeting the GRS: rule 13.3.3. Rule 13.3.4 provides that Transpower may amend reliability investments in response to such requests. The Commission is also entitled (in accordance with rule 13.3.5) to undertake such inquiries, appoint such experts and consult with affected parties as it considers reasonable.
[24] When the Commission is reviewing reliability investments proposed in a GUP it must have regard to the costs imposed from any process of consultation, review, modelling or public conference: rule 12.l.3.1. It must also take into account regulatory costs generally (including Transpower’s costs) and the need to avoid unnecessary delays in the approval process: rule 13.3.1.
[25] The Commission may (subject to rule 15 discussed below at [27]) approve some or all of Transpower’s proposed reliability investments where a proposed reliability investment:

(a) reflects good electricity industry practice (GEIP) in meeting GRS: rule 13.4.1.1;

(b) complies with the processes set out in these EG Rules: rule 13.4.1.2; and
(c) meets the requirements of the GIT: rule 13.4.1.3.
[26] Rule 14 deals with economic investments. This requires the Commission and Transpower to agree on a timetable for consultation. It is Transpower’s function to undertake that consultation. To approve such investments, the Commission must be satisfied that Transpower has applied the GIT reasonably and followed any agreed consultation process: rule 14.4. The Commission can direct Transpower to consider modifying its application of the GIT: rule 14.3.2.1. It can also, after consultation with Transpower, direct Transpower to apply the GIT to alternative economic investments: rule 14.3.2.2.
[27] Under rule 15.1 the Commission must publish GUPs and a notice of intention to approve some or all of the reliability and economic investments in the GUP. Any designated transmission customer or any other party substantially affected by the GUP can, under rule 15.2, request a public conference if the interests of end use customers are materially adversely affected by the cost or service outcome of any proposed investment or where the GIT has not been properly applied. Where a public conference is held, that is intended to be a final opportunity for comment on a GUP: rule 15.3. Final approval can then be issued: rules 13.4 and 15.5. If the Commission declines approval for a reliability investment, it is required under rule 13.4.2 to publish reasons.
[28] Approval by the Commission of a GUP or particular grid investment enables Transpower to recover its investment costs from designated transmission customers on the basis of the transmission pricing methodology: rule 17. Approval also has further consequences under an administrative settlement negotiated between the Commerce Commission and Transpower under Part 4A of the Commerce Act 1986 dealing with price control of lines companies.

Schedule F3 – Grid Reliability Standards (GRS)

[29] As noted above at [17](a), rules 4 and 5 of the GUI Rules deal with the setting of GRS. Rule 4.3 sets out the principles behind such standards. They include that the GRS should take into account the GIT and that transmission investments are long-lived assets and require a long term planning perspective. Schedule F3 to the GUI Rules contains the GRS.
[30] Clause 4 of the GRS provides that the grid satisfies the GRS if:

(a) the power system is reasonably expected to achieve a level of reliability at or above the level that would be achieved if all economic reliability investments were to be implemented (clause 4.1); and

(b) with all assets that are reasonably expected to be in service, the power system would remain in a satisfactory state during and following any single credible contingency event occurring [failure of one component] on the core grid (clause 4.2).

[31] Clause 4.2 of the GRS (the N-1 criterion) relates only to the core grid. The extent of the core grid is determined by the Commission: rule 5A of the GUI Rules.

Schedule F4 – Grid Investment Test (GIT)

[32] As noted above at [17](b), rules 6 and 7 of the GUI Rules deal with the development of the GIT. Rule 6 of the GUI Rules provides that the Commission must determine the most appropriate GIT having regard to the objectives set out in rule 6.3. These objectives, against which the Commission must apply the GIT in reviewing and approving both reliability investments and economic investments under rule 6.2 include:
[33] The GIT is in Schedule F4 of the GUI Rules. Clause 4 of the GIT provides the basic test for the review of proposed investments. The general rule is that investments must be projected to have a positive net benefit in order to be approved. The exception is where a proposed investment is necessary to meet the N-1 standard on the core grid (as set out in clause 4.2 of the GRS). In such cases clause 4.1 of the GIT allows investments to have a net market cost. Any such investment must minimise the expected net market cost (or maximise the projected benefit) compared with a number of alternative projects. If it does not, then the Commission must reject the proposal put forward.
[34] Conversely, clause 4.2 of the GIT provides that, in the case of “any other proposed investments”, the proposed investment must both have a positive expected net market benefit and maximise the expected net market benefit compared with a number of alternative projects. If it does not maximise benefits compared to alternative proposals, then it must be rejected. It is notable that the focus is on public costs and benefits and not just costs to Transpower and its customers.
[35] Clause 11 of the GIT provides that the alternative projects used in applying the GIT must be limited to those appropriate in number and technology given the cost magnitude of the proposed investment, the complexity of the required modelling and the urgency of the proposed investment. Similarly clause 12 limits the analysis to that commensurate with the estimated capital expenditure involved. Clause 19 sets out the characteristics of alternative projects to be compared with any investment proposal, including that they must be technically feasible and reasonably expected to provide similar benefits as the proposed investment.
[36] Under clause 5 of the GIT the market benefits or costs for the proposed investment or alternative project are determined with regard to market development scenarios which must be compared to the base case. The base case is defined in clause 20 as the market development scenarios developed for the reasonable future state of the electricity industry without the proposed investment or any alternative project. Clauses 23 and 27 of the GIT require the Commission to take into account “costs” and “market benefit” calculated over at least a 20 year period. Under clause 7 the supply side of any market development scenarios must include committed projects, the decommissioning removal or de-rating of decommissioned assets and modelled projects. Under clause 9, where a material market benefit or cost cannot be quantified, the direction of the market benefit or cost must be identified.
[37] Rules 13 – 15 deal with the manner in which the expected market benefit is calculated. Rules 16 and 17 require there to be a sensitivity analysis, except with regard to those variables where it is either not reasonably practical or not reasonably necessary. Under clauses 4.1.2 and 4.2.3 the conclusion that clause 4.1.1 or clauses 4.2.1 and 4.2.2 are satisfied must be sufficiently robust, having regard to the results of any sensitivity analysis.

Background

[38] The Otahuhu substation, owned and operated by Transpower, is a critical entry point for electricity into Auckland and the North. It is (according to Transpower) a “legacy asset”, being old, overcrowded and with outdated technology. Prior to 2006, there had been proposals for the upgrade of the North Island grid (NIGU) put before the Commission by Transpower, which included the upgrading of the Otahuhu substation, but these were not approved by the Commission.
[39] In June 2006 an overload corroded shackle at Otahuhu failed, bringing an earthing wire down onto other wires. This caused a significant Auckland-wide power outage lasting some six hours. This led to pressure on Transpower to solve the design problems at Otahuhu quickly and to minimise the prospect of a repeat outage. As a result, on 11 August 2006, Transpower proposed an immediate solution for Otahuhu by way of an Interim Grid Expenditure (IGE) application under the transitional provisions (rule 16) in the GUI Rules (the Otahuhu IGE). This had the effect of separating the work at Otahuhu from the rest of NIGU.
[40] The Otahuhu IGE proposal involved (at an estimated cost of $79.3m):

(a) The construction of a new gas insulated switchgear (GIS), 1.5 circuit breaker switchyard adjacent to the existing air insulated switchgear (AIS) switchyard;

(b) The removal of all overcrossings at Otahuhu substation; and
(c) The diversification of the transmission circuits in and out of Otahuhu substation between the existing and new switchyards.
[41] The Commission indicated on 12 October 2006 that it was not prepared to approve the Otahuhu IGE under the transitional provisions. It would, however, have been prepared to use the IGE route to approve the removal of overcrossings and the adding of new circuit breakers for an estimated cost of $14.1m, if Transpower resubmitted just that option. Transpower considered this to be an inefficient incremental option that did not address either the short or long term needs at Otahuhu, including the additional connections needed for NIGU. Accordingly, Transpower prepared a comprehensive upgrade plan for Otahuhu as part of the 2005 GUP. This was submitted on 11 December 2006 and Option Three, set out at [45](c) (the Otahuhu Proposal) is the proposal approved by the Commission, which is the subject of this appeal.
[42] In its application for approval, Transpower compared the Otahuhu Proposal with two alternative projects (set out at [45](a) and (b) below). The first involved modifying and extending the existing switchyard. The second was to establish a new AIS switchyard adjacent to but physically separate from the existing AIS switchyard, this being required both for diversification purposes and to accommodate NIGU.
[43] Although the Otahuhu Proposal, set out at [45](c) below, outlined some works to the existing switchyard, its focus was the construction of a new GIS switchyard at the Otahuhu site, physically separate from the existing AIS switchyard. This was designed to provide diversity at the Otahuhu site and diversity of supply into and through Auckland, so that, if either the new Pakuranga switchyard anticipated by the NIGU Proposal or one of the two Otahuhu switchyards fail, all of Auckland’s demand could be met by the remaining two switchyards. The estimated cost is $99m (in 2009 dollars) including contingencies.
[44] Common to all three proposals (ie the final proposal and the alternatives proposed by Transpower) were:

(a) New bus section circuit breakers;

(b) Removal of overcrossings; and
(c) Provision for NIGU, including accommodating the need for reactive power and additional connections.
[45] The Otahuhu Proposal and the two alternative projects included:

(a) Option One involving:

(i) installing bus section circuit breakers to the existing switchyard (2009);

(ii) the removal of overcrossings by the undergrounding of overhead cables (2009); and
(iii) extending the existing switchyard to accommodate additional circuits and reactive support as required from time to time over the next 35 years (2013).
(b) Option Two involving:

(i) installing bus section circuit breakers to the existing switchyard (2009);

(ii) the removal of overcrossings by the undergrounding of overhead cables (2009); and
(iii) building a new Air Insulated Switchgear (AIS) switchyard to the north of the existing switchyard (2009).
(c) Option Three (the Otahuhu Proposal) involving:

(i) installing bus section circuit breakers to the existing switchyard (2009);

(ii) the removal of overcrossings by the undergrounding of overhead cables (2009); and
(iii) building a new Gas Insulated Switchgear (GIS) switchyard to the north of the existing switchyard (2009).
[46] On 22 December 2006, in accordance with rule 13.3.2 of the GUI Rules, the Commission gave notice that it was providing designated transmission customers and substantially affected parties with an opportunity to provide written comments on the Otahuhu Proposal or to request that the Commission consider alternatives to the Proposal. The Commission received 14 submissions in total. Three did not support the proposal. The remaining 11 were supportive.
[47] On 22 May 2007, the Commission decided to approve the Otahuhu Proposal. The decision was made by three Commissioners, including the Deputy Chair. One Commissioner dissented and one Commissioner did not take part in discussions or vote on the Proposal. In accordance with rule 15.1, on 25 May 2007 the Commission published a notice of its intention to approve the Otahuhu Proposal. It also published the reasons for its decision and the reports by its advisors that it had relied on in making its decision. The Commission held a public briefing on 27 June 2007 to assist the understanding of its decision. Both the Commission and Transpower made a presentation at that briefing.
[48] The Commission received three requests under rule 15.2 to hold a public conference and agreed to do so. The conference was held in Wellington on 23 July 2007. Prior to the conference, the Commission invited interested parties to provide written submissions on the decision to approve the proposal. Four submissions were received. Each submitting party made a presentation at the public conference, as did two other parties. Three of the presenters supported the Commission’s intention to approve the Otahuhu proposal. Three did not.
[49] On 6 August 2007, MEUG forwarded to the Commission, and various other industry participants, a letter regarding matters arising from the conference and a copy of legal advice MEUG had received which related to the interpretation of clause 4 of the GIT and the Commission’s choice of alternatives. The letter said that MEUG no longer considered undergrounding was required to accord with GEIP. The Commission’s Board considered this correspondence at its meeting on 7 and 8 August 2007.
[50] On 28 August 2007, the Commission (by a majority compromising three Commissioners, including the Deputy Chair) confirmed its decision regarding the proposal in accordance with rule 15.5. One Commissioner confirmed his minority dissent, and one Commissioner abstained from voting on the proposal. The final decision was published on 30 August 2007.
[51] Further relevant background is that Transpower had, on 20 October 2006, submitted a revised NIGU. The NIGU Proposal did not include modifications to the Otahuhu substation. However, it was integrally linked to the Otahuhu proposal because it proposed an upgrade of the transmission line connecting Pakuranga substation and Otahuhu substation, and included additional reactive support to be connected at Otahuhu.
[52] The Commission’s consideration of the two proposals (NIGU and the Otahuhu Proposal) proceeded more or less in tandem but with NIGU somewhat ahead. The Commission was thus, when considering the Otahuhu Proposal, also aware of NIGU. NIGU was approved on 5 July 2007. After this, it became a “committed project” (GIT clause 21) and thus it was required to be included in the market development scenarios used in determining the expected net market cost of the Otahuhu Proposal (GIT clauses 5 and 7).
[53] The Commission was also aware during its consideration of the Otahuhu proposal of an impending proposal for North Auckland and Northland, which would similarly require connections at Otahuhu. In May 2007 (ie during the latter stages of considering the Otahuhu Proposal and around the time of the public conference on the NIGU Proposal) the Commission and Transpower established an interim work phase on options to ensure reliable electricity supply to the North Auckland and Northland area. On 21 September 2007, Transpower submitted a new GUP, containing two proposed investments relating to North Auckland and Northland.

Standard of review

[54] It is of course accepted by all parties that the Commission must correctly interpret and apply the regulatory framework under which its decisions fall to be made. The Commission accepts that the first ground of appeal (see at [3](a) above), the alleged incorrect interpretation of the GIT, alleges that it made an error of law.
[55] With regard to the second and third grounds of appeal (see at [3](b) and (c) above), the Commission submits that the starting point must be that the legislation does not provide for any review of the merits of the Commission’s decisions on investment proposals. (The Act confers only a limited right of appeal on questions of law that may be exercised by certain industry participants: ss 172KJ and 172KL.) The Commission also submits that the intensity of review must be assessed against the background of the expert nature of the Commission, the consultation provided for in the EG Rules and also the emphasis in the EG Rules of the importance of prompt decision-making.
[56] The decisions made by the Commission on the selection of alternative proposals for modelling purposes and the probabilities of adverse events were made after proper consultation and were based on the Commission’s own industry knowledge and expert judgement. We accept the submission (as did Wild J) that those findings can be challenged in judicial review proceedings only if no reasonable body in the position of the Commission, having before it the material received by it, could have reached those decisions. This must be assessed in light of, and giving full recognition to, the Commission’s position as an expert body, the process and consultation requirements imposed on it and the nature of the investment decision involved.
[57] The Supreme Court in Unison Networks Ltd v Commerce Commission [2008] 1 NZLR 42 recently summarised the grounds on which a Court will intervene by way of judicial review in discretionary decisions made by an expert body. It said, at [55], that:

Often, as in this case, a public body, with expertise in the subject-matter, is given a broadly expressed power that is designed to achieve economic objectives which are themselves expansively expressed. In such instances Parliament generally contemplates that wide policy considerations will be taken into account in the exercise of the expert body’s powers. The courts in those circumstances are unlikely to intervene unless the body exercising the power has acted in bad faith, has materially misapplied the law, or has exercised the power in a way which cannot rationally be regarded as coming within the statutory purpose.

Interpretation of clause 4.1 of the GIT

Issue

[58] The first issue in the appeal is whether the Commission committed a reviewable error of law in holding that the Otahuhu Proposal could be assessed under clause 4.1 of the GIT. The specific issue arising in relation to this point is whether the words “necessary to meet” in clause 4.1 of the GIT, read in the context of the GUI Rules as a whole, mean that the Commission can only consider investments under clause 4.1 of GIT if they are works which are expressly linked with meeting the N-1 criterion under clause 4.2 of the GRS and no more. It is accepted by all parties that some capital expenditure at Otahuhu had to be undertaken as the substation currently fails to meet that minimum standard of grid reliability.

MEUG’s submissions

[59] Mr Hodder SC submitted, on behalf of MEUG, that, read together, the GUI Rules, the GRS and the GIT create three types of investments:
[60] In Mr Hodder’s submission, those parts of reliability investments which deal with aspects other than meeting the N-1 criterion on the core grid must be separated off or “disaggregated” (if possible). The Commission then must consider, under clause 4.1 of the GIT, the works which deal only with the N-1 criterion on the core grid. The rest of the investment must be considered under clause 4.2 of the GIT. If there is an indivisible project that addresses more than the bare N-1 criterion, then the whole project must be evaluated under clause 4.2 of the GIT. Mr Hodder encapsulated the issue as: whether the GIT clause 4.1 exception can be widened by “piggy backing”, onto N-1 investments, further investments outside the N-1 criterion. He said that it cannot.

Change in MEUG’s position

[61] It is of some importance that MEUG’s position has changed over the course of the Commission’s decision-making process, the High Court review proceeding and this appeal. Its position before the Commission, up until after the public conference, was that the Commission could only assess, under clause 4.1 of GIT, proposals that resulted in the lowest initial cost. Thus the Commission could not address projects that, in the long term, were necessary to meet the N-1 standard on the core grid. MEUG argued that this meant that the Commission should only consider the project that it would have been prepared to consider under the transitional provisions: see at [41] above. It is significant that this included the removal of overcrossings through undergrounding. It was only in its letter of 6 August 2007 (see at [49] above) after the conference that MEUG said that it no longer considered undergrounding necessary to GEIP.
[62] This submission was rejected both by the Commission (see below at [65]) and by the High Court (where it was also presented, albeit in a modified form). It has now been conceded by MEUG that, whether or not a project is necessary to address an N-1 issue on the core grid, it can be assessed over the long term. This is a concession that was quite rightly made. MEUG now concedes that the only aspect of the Otahuhu proposal that does not address the N-1 criterion is the undergrounding. It says, however, that the Commission should have considered a Modified Option One proposal, which did not include the removal of overcrossings by undergrounding (see at [45] above where the three options considered by the Commission are set out). We note that the cost of undergrounding in Option One amounted to $11m but the cost would presumably be less for the Otahuhu Proposal as that project requires only two lots of undergrounding (as against four for Option One).

The position of the respondents

[63] The Commission and Transpower accept that not every reliability investment will fall to be considered under clause 4.1 of the GIT. But in this case, the Commission considered:

(a) That the Otahuhu Proposal was a reliability investment, to which rule 13 of the GUI Rules applied; and

(b) That the Commission was required to assess the proposal under clause 4.1 of the GIT, because it did address the N-1 problem and it was thus necessary to make the proposed investment in order to meet the N-1 reliability standard.
[64] Both respondents submit that MEUG’s proposed interpretation of clause 4.1 of the GIT does not accord with the words of the clause read in the context of the GUI Rules as a whole. It also creates absurd results as set out in a number of examples prepared by Mr Goddard QC on behalf of the Commission. These are reproduced in Appendix Four (together with some commentary from the parties and from us).

The Commission’s decision

[65] It is worth setting out in full the part of the Commission’s Final Decision of 30 August 2007 that deals with the interpretation of clause 4.1 of the GIT and MEUG’s argument before it:
  1. CLAUSE 4.1 OF THE GIT

4.4.5 In its submission made during the comments period, Strata Energy Consultants (on behalf of the Major Electricity Users’ Group) stated that improvements beyond the minimum necessary to meet the N-1 Safety Net may only be justified on economic grounds - that is, such investments must meet clause 4.2 of the GIT by maximising expected net market benefits, such benefits being greater than zero.

4.4.6 The Commission does not agree with this interpretation. It would lead only to the approval of least initial cost projects, and incremental, piecemeal developments. The interpretation does not reflect that the GIT requires a long-term view of investment proposals.
4.1.2 MEUG (and its advisors), Norske Skog, and Rio Tinto expressed strong disagreement with the Commission’s statement above.
4.1.3 Those parties remain of the view that clause 4.1 of the GIT applies only to the minimum capital works required to ensure the Otahuhu Substation meets the N-1 Safety Net immediately.
4.1.4 If a proposed investment comprises more than the minimum necessary to ensure that the N-1 Safety Net is met at the time that the investment is made, MEUG, Norske Skog, and Rio Tinto consider that the investment must be disaggregated, with those elements that are more than the minimum necessary then being considered under clause 4.2 of the GIT (which requires a positive net market benefit to arise).
4.1.5 In support of this view, the relevant parties referred to the $14 million IGE option identified by Transpower in its earlier IGE Proposal, which, if implemented, would bring the Otahuhu Substation up to the GRS immediately.

4.2 Disaggregating investments

4.2.1 There is no requirement in the Rules to disaggregate a particular investment proposal. The Rules require only that a grid upgrade plan is disaggregated into reliability investments and economic investments.

...

4.2.4 Clause 4.1 and 4.2 of the GIT apply to a “proposed investment”. “Proposed investment” is defined in clause 32 of the GIT as follows:

“Proposed investment” means a reliability investment or economic investment proposed by Transpower and submitted by it to the Board for approval under rules 13 or 14, respectively, of section III of Part F of the rules. For the avoidance of doubt, an investment that is to be fully funded under an investment contract by one or more designated transmission customers that are party to that investment contract is not a proposed investment.

4.2.5 Therefore, the Commission is required to apply clause 4.1 or 4.2 of the GIT to an investment proposal as proposed by Transpower. The Commission is not required under the rules to require Transpower to disaggregate the proposal and can see no justification for doing so.

4.2.6 The position advocated by MEUG’s advisors (that only the aspects of a reliability investment that are necessary to meet N-1 at the time that the investment is made are able to be considered under rule 4.1) is inconsistent with the definitions of “reliability investment” and “proposed investment” and rules 4.1 and 4.2, as well as being inconsistent with good electricity industry practice.

4.3 The minimum necessary and required analysis period

4.3.1 The GIT requires Transpower and the Commission to consider the expected net market benefit and/or the expected net market cost of a proposed investment. The GIT was deliberately drafted this way so as to avoid the pitfalls of “least cost” investments that do not consider costs and benefits over time.

...

4.3.4 Clause 5 of the GIT requires that the market benefits and costs of a proposed investment or alternative project are determined for each market development scenario for the future with that proposed investment or alternative project by comparing that market development scenario with the market development scenario developed for the base case.

4.3.5 Clause 7 of the GIT requires the supply side of any market development scenario to include committed projects, the de-commissioning, removal or de-rating of de-commissioned assets, and modelled projects.

4.3.6 Modelled projects must be likely to occur in a market development scenario, and be reasonably expected to occur in that market development scenario within the time horizon for assessment of market benefits or costs of the proposed investment or alternative project.

4.3.7 Therefore, under the GIT analysis the expected net market benefits and expected net market costs of a proposed investment or an alternative project must include the costs and benefits of committed projects, the effects of de-commissioning etc of de-commissioned assets, and the cost of modelled projects.

4.3.8 In order to comply with these requirements, the Commission must make assumptions about the development path that would be followed over the analysis period if the particular investment proposed by Transpower is constructed. That is, the expected net market cost includes the initial costs of an investment proposal as well as those costs that would likely be incurred for other investments that would be likely to be required over the analysis period.

...

4.3.12 Therefore the Commission rejects the submission by Norske Skog that the Commission requires an investment proposal to satisfy the GRS over a 20-year period. The correct position is that, through the requirement to include modelled projects in the GIT analysis, it is reasonable for the Commission to assume that an investment proposal, together with modelled projects, will ensure that the GRS is met over the 20-year analysis period. The length of time that any particular investment proposal meets the GRS is a matter for Transpower in planning and submitting an investment proposal for approval.
4.3.13 The above also illustrates the point that the GIT facilitates a long-term view of grid development. But it is also important to recognise that the GIT contains mechanisms to ensure that the benefits of flexibility are captured. An investment proposal that contains measures necessary to ensure the N-1 Safety Net is met over the next 10 years may have a lower option value than a proposal that comprises measures addressing the N-1 Safety Net over the next 3 years.

Evaluation

[66] As noted above, Mr Hodder’s submission is that “necessary to meet the N-1 standard” means “necessary to meet the N-1 standard and no more”. We do not accept that submission. This proposed interpretation involves adding words to clause 4.1 of the GIT and we see no need to do so. Indeed, as a matter of pure interpretation of the GUI Rules and the Act as a whole, MEUG’s position is unsustainable. Clause 4.1 of the GIT cannot be interpreted as overriding the Act. The GIT is also essentially subordinate to the GUI Rules (see rules 6 and 7 of the GUI Rules) and thus could not override these Rules either.
[67] First, we do not consider that there is any obligation on Transpower to “disaggregate” investments into the three categories set out by Mr Hodder (see at [59] above). The obligation to disaggregate investments in any GUP is confined to separating out two categories of investment: reliability investments and economic investments under rule 12.3.3 of the GUI Rules. Reliability investments by definition can include aspects that do not relate to reducing expected unserved energy (see at [19] above) as long as that reduction is their primary effect. This is a strong indication that no further disaggregation was envisaged under clause 4.1 of the GIT. We agree with the Commission (as did Wild J) that the concept of disaggregation cannot be lifted over to clause 4.1 of the GIT: see [4.2.1] – [4.2.6] of the Commission’s Final decision set out at [65] above.
[68] Mr Hodder submitted that the GUI Rules and the GIT/GRS deal with different things. The former, he submitted, concern the process for consideration of GUP proposals and the latter provide a methodology for the analysis of those proposals. We do not consider that the process can be segregated from the methodology in such a way. Further, the split between process and methodology is not complete on Mr Hodder’s analysis. He proposes a further disaggregation process at GIT level between parts of the investments that come within clause 4.2 of the GRS (to be analysed under clause 4.1 of the GIT) and the rest.
[69] Further, the GUI Rules provide that any reliability investment cannot be approved unless it meets GRS in a way that reflects GEIP (see rule 13.4.1.1). This is a dual requirement – ie the GRS as well as GEIP must be met. Determining whether the GRS is met involves an assessment of not only clause 4.2 of the GRS (the N-1 criterion) but also clause 4.1 of the GRS. While the parties are agreed that clause 4.1 of GRS is not relevant in this case, that cannot always be the case. (We suspect that the parties’ agreement that clause 4.1 was not relevant was reached with some relief, given that clause 4.1 of the GRS and the associated definitions are obscure to the point of being unintelligible.)
[70] The Commission, in assessing investments, must also take into account other committed and modelled projects (see at [36] above). This implies a need to ensure that any investment be assessed in a wider context. The Commission is also obliged to ensure investments accord with the GPS (see at [11] above), including, for example, (to the extent possible) that they address HILP events.
[71] Thus it is not possible under the EG Rules, the GPS and the Act for an investment proposal to address the N-1 criterion and no more unless it coincidentally also meets the GRS (both clause 4.1 and 4.2), GEIP practice in meeting GRS and any other requirements, such as addressing HILP, required under the Act and the GPS. If an N-1 core grid project does not meet the added criteria then it must be modified so that it does. Otherwise, the Commission has no power to approve the investment.
[72] In addition, the structure of the process, as provided for in the GUI Rules, is contrary to MEUG’s position. As the GUI Rules make clear, it is Transpower’s role to put investment proposals forward in a GUP and Transpower that has the primary responsibility for providing information and analysis supporting the investment proposals in a GUP. The Commission’s role is one of review. We accept the respondents’ submission that this is implicit in the scheme of the EG Rules, and express in rules 12.1.1 and 13.3.3.
[73] Transpower and the Commission submit that the Commission cannot approve a different proposal (even where that was an alternative investment used for comparison purposes). Neither can it approve only part of an investment. We accept that submission and the related submission that the power to approve “some investments” is designed to cover the situation of a GUP containing several investments. The Commission can approve all the investments put forward, decline them all or approve some of the investments and decline others: rule 13.4.
[74] We also accept the submission that the Commission has no ability to require Transpower to put up a replacement project, although it can ask questions and invite Transpower to amend a project. Transpower is not obliged to accept the Commission’s invitation. Although the Commission can indicate the type of investment proposal it would approve (as it did with the Otahuhu IGE: see at [41] above), it remains for Transpower to devise the new investment proposal. It follows that the Commission cannot modify of its own motion projects that have been put forward and that it cannot force Transpower to accept the modification.
[75] What this means is that when the Commission was reviewing the Otahuhu Proposal, there was only one project on the table relating to Otahuhu. The structure of the process as set out above means that this will always be the case. Where there is an N-1 problem that must be addressed and a proposed investment addresses it, then the project must be necessary to address the N-1 problem in terms of clause 4.1 of the GIT because there is no other extant project that will do so.
[76] In addition, we do not consider that the interpretation put forward by Mr Hodder accords with the purpose of the GIT. His interpretation would mean that, where there is an indivisible project that does more than meet the N-1 on the core grid, then it must be assessed under clause 4.2 of the GIT, despite the fact that it may have a lesser net cost than a project that just meets the N-1 criterion and no more. Given the whole basis of clause 4.1 of GIT is to minimise cost (or maximise benefit), this result would fall outside the clear purpose of clause 4.1. We also accept the respondents’ submission that “add ons” for indivisible projects may provide substantial benefits that reduce cost and that it would be economically irrational for this not to be taken into account. The EG Rules must be interpreted in the context of the efficiency and reliability objectives of the Act: Commerce Commission v Fonterra [2007] 3 NZLR 767 at [22] – [24] (SC).
[77] One of MEUG’s concerns is the prospect of projects being gold-plated or that inefficient projects could be piggy-backed onto a N-1 project. We accept the Commission’s submission that Example Three of Appendix Four shows that cannot be the case (at least to the extent any “add ons” have a net cost). If any “add ons” have a net cost then the Commission would use the N-1 project without “add ons” as a comparator and the gold-plated or piggy-backed project would not be approved (but see a possible caveat at [128] below).
[78] There are also practical issues with the interpretation of clause 4.1 of the GIT advanced by MEUG. As pointed out by Mr Millard QC for Transpower, MEUG’s suggested interpretation makes the simplistic assumption that a proposal for work can be neatly segregated into these parts. This is not necessarily the case, particularly when dealing with remedial action required at a large complex legacy asset such as Otahuhu and where various N-1 requirements arise in the short and medium and longer term. Further, Transpower points out, even seemingly discrete items of work will carry different costings if done as part of a comprehensive scheme (with the advantages of greater buying power and spread overhead costs) than if done as a series of a stand alone items at different times.
[79] As Mr Millard also pointed out, the effect of MEUG’s argument would be that, if there is an N-1 problem and the solution is to instil an added single integrated unit that has built-in redundancy then this could not be assessed under clause 4.1 of GIT as it would provide an N-2 solution – ie the power system would remain in a satisfactory state during and following any two contingency events occurring on the core grid. Presumably a unit without built-in redundancy would have to be installed (if even available) or some other minimalist solution found. This defies common sense (and probably would, in any event, breach the mandatory requirement to meet the GRS in accordance with good GEIP). It could also be more expensive: see Example Four in Appendix Four. Example One may also be relevant to this issue as pointed out at [121] below.
[80] MEUG’s approach could also involve additional administration in that conceivably different parts of projects if disaggregated could become economic rather than reliability investments. They would thus need to be assessed under a different process (rule 14 rather than rule 13 of the GUI Rules). Further, as shown in Example Two of Appendix Four, as each individual part would in any event have to be taken into account in the analyses as modelled projects, it would make little sense to assess them separately (see discussion at [124] below).
[81] In summary, the proper interpretation of clause 4.1 of the GIT is that there must be an N-1 problem. It must be necessary (and not just desirable) to address it. The proposed project must address the N-1 issue (even if it also does other things). As the proposed project is the only extant proposal, it must, as a consequence, be necessary to address the N-1 issue.
[82] In our view, this gives a full import to the word “necessary” in clause 4.1 of the GIT, without the need to add any extra words. Further, the extra words contended for by Mr Hodder do not accord with the GUI Rules, the GPS or the Act which require the proposed project as a minimum to meet GRS in accordance with GEIP, to fit in with and accommodate any other proposed projects and (to the extent possible) cover any relevant matters in the Act or the GPS, such as addressing HILP. Finally, the interpretation advanced by Mr Hodder does not accord with the process in the GUI Rules for the proposal and approval of investments.

Failure to consider “alternative projects”

[83] The second issue in the appeal is whether the Commission acted unreasonably in failing either to test, or require Transpower to test, the Otahuhu Proposal against an “alternative project” (Modified Option One) that excluded approximately $11m of expenditure on the removal of overcrossing wires (see at [62] above). The specific issues arising in relation to this point are:

(a) Whether the Commission acted unreasonably when it did not consider a Modified Option One as an “alternative project” for the purposes of applying the GIT to the Otahuhu Proposal; and

(b) Whether, in assessing whether the Commission ought to have considered a Modified Option One, the absence of a submission to that effect from MEUG or other interested parties prior to the Final Conference is relevant and/or conclusive.
[84] This is not an auspicious ground of review. The submission must be that it was irrational for the Commission not to have considered as an alternative, a project that was not put before it by Transpower or any of the submitters. Indeed MEUG itself did not object until after the Public Conference (which is the last chance to comment) that the removal of overcrossings by undergrounding was unnecessary and this was in the course of arguing for a totally different project from the Modified Option One it now puts forward.
[85] The Commission does have a discretion under rule 13.3.3 to ask Transpower to evaluate alternative reliability investments. The issue is whether the Commission’s failure to exercise this discretion to require consideration of the particular alternative now contended for by MEUG was so unreasonable that any reasonable Commission must have acted otherwise. As pointed out by the Commission, there will often be many different alternative projects that satisfy the definition in clause 19 of the GIT. It cannot sensibly be suggested that all possible alternatives should be considered. There is a necessary process of selection, which must be carried out, having regard to GIT clauses 11 and 12, and rule 13.3.1 of the GUI Rules. As Transpower submitted, the GUI Rules are intended to prevent paralysis through over-analysis (with all the consequential delays and costs).
[86] We accept the Commission’s submission that the fact that no submitter suggested a Modified Option One, when submissions on alternative projects were called for, points strongly against it being so plainly relevant that a failure to include it as an alternative project was irrational and thus a reviewable error. We also accept Transpower’s submission that the cost and technical feasibility of a Modified Option One have never been examined by the Commission (given that it was not asked to consider it) and that there is no evidence before the Court on whether it was even a real-world, practically workable option. In addition, we note that it is not surprising that undergrounding was seen as an important part of the Otahuhu proposal. We understand that the existence of overcrossings played a part in the June 2006 Otahuhu outage (see at [39] above).
[87] MEUG submits further that the Commission did not make any finding in relation to whether the removal of overcrossings was either necessary to meet the N - 1 criterion or required by GEIP. We do not agree. We interpret the Commission as saying that, in the circumstances of this case, which involved a major redevelopment, the removal of overcrossing was necessary for GEIP, provided this could be done at a reasonable cost. The Commission said:

8.3 Removing overcrossings and GEIP

8.3.1 During the conference there was some discussion regarding whether removing overcrossings constituted good electricity industry practice.

8.3.2 The Commission would generally expect a “greenfields” substation site with no undue site limitations to be designed so as to avoid the use of either overcrossings or expensive cabling.

8.3.3 However, cabling could be required in circumstances where a substation site is crowded, or close to residential or industrial properties.

8.3.4 In a substantial redevelopment of an existing switchyard, the Commission would expect the removal of overcrossings if this was possible at a reasonable cost.

[88] We also note that the removal of overcrossings may well have been seen as related to reducing HILP events, as instructed by the GPS. The Government commissioned Connell Wagner Report into the 12 June 2006 outage advised that risks of a repeat could be mitigated by undergrounding the 220kV circuits which over-cross the 110kV busbar. Connell Wagner was later retained by the Commission to review the Otahuhu proposal. Their report of 28 March 2007 comments at [1]:

We also agree that a part of the works, such as removal of overhead crossings and undergrounding of some of the 220kV feeders, as suggested in the Proposal are essential to upgrade the security of supply at Otahuhu.

Erroneous HILP assumption

[89] The third issue in the appeal is whether, in the economic comparison of the alternative projects tested, the Commission erred in adopting the value of HILP-related reliability benefits to be attributed to the Otahuhu Proposal. The specific issues arising in relation to this issue are:

(a) Whether the Commission asked the wrong question when it adopted a one in 100 year probability for the calculation of HILP-related reliability benefits; and

(b) Alternatively, whether the Commission acted unreasonably in determining that it could be reasonably satisfied that the requirements of the GIT were met given the Commission’s use of a one in 100 year probability for HILP events.

Background

[90] In order to apply the GIT, it is necessary for the Commission to assess the costs and benefits of the investment proposal and of the alternative projects that are being considered by it. One important input in this context is an estimate of the value of unserved energy (see above at [19]) avoided by the proposal (or alternative project), also referred to as “reliability benefits”. This requires the Commission to estimate the likelihood and extent of unserved energy in each relevant scenario, and multiply this by the appropriate value of unserved energy. It is common ground that one input into this process is an estimate of the probability of a HILP event, of a kind that would be avoided by implementing the Otahuhu Proposal or Option Two (each of which involved two separate switchyards) as compared with Option One (one switchyard).
[91] There is no doubt that the Commission’s assessment of HILP-related reliability benefits was critical to its finding that the Otahuhu Proposal had the highest net present value as the Commission attributed $11.7m to HILP-related reliability benefits for that Proposal. This was derived from assuming a one in 100 year probability of a HILP event that would (absent diversity of supply at the Otahuhu substation) cause a $100m loss to electricity consumers.
[92] The estimate adopted by the Commission of a one in 100 year risk was put forward by Transpower, after Transpower’s original higher probability estimate had been queried by the Commission. It was consistent with the approach of Transpower’s expert consultant Siemens and was also supported by submissions from Genesis Energy Ltd and from Vector Ltd.
[93] The Commission also had before it a study by Commission staff based on Transpower’s 2005/2006 Quality Performance Report (QPR) regarding the frequency of HILP-related events. That report lists “significant outage events” on the transmission grid from 1987 to 2006 (inclusive). The Commission staff estimated the probability of occurrence of a HILP event at a substation of approximately one in 1500 years. The Commission staff estimated the accuracy of this observation within 80 per cent limits as one in 500 years to one in 10,000 years.
[94] As explained by the Deputy Chair of the Commission in evidence before the High Court, the majority was not satisfied that the quantitative approach of the Commission’s staff was a reliable basis for estimating HILP risk, given the limited data available and the inconsistency between the theoretical conclusion reached through this exercise and “recent experience and common sense”. In adopting the one in 100 year probability in the May 2007 decision, the majority stated at [6.3.51] that:

The Commission considers that the fact that HILP events have a low (but not zero) probability of occurring means that it is very difficult to reliably calculate what the probability is. However, given the very high impact of these events, the Commission considers that it is left in the position where it must simply exercise its judgment as to whether it is prudent to have Auckland exposed to the prospect of a single major substation being affected by a low probability event, or whether two substations offer the degree of reliability that is required, and adopt a notional probability that reflects that judgment.

[95] In its Final Decision the majority said:

6.3 Quantifying HILP-related benefits

6.3.1 It is difficult to quantify the probability of substation-wide HILP outage events since they are infrequent and it is difficult to construct a statistically sufficient sample period on which to draw concrete conclusions.
6.3.2 The Commission considered a 20 year sample of events in Transpower’s 2005/2006 Quality Performance Report, which indicated that the probability of occurrence of a HILP event at any given substation could be approximately one every 1500 years, with an 80% confidence limit in the range of one in 500 to one in 10,000.
6.3.3 However, the Commission was not satisfied that it could safely rely on this assessment of probability to analyse costs and benefits given the time period of observations, the potential range of unpredictable events, and the possible duration of an outage. This remains the Commission’s view.
6.3.4 In its supporting analysis Transpower took the view that the substation wide event at Otahuhu was a 1 in 100 year occurrence, and that the cost to consumers could be $100 million, based on the estimated cost of the 12 June 2006 outrage. Based on this view, Transpower concluded that there was a HILP-related reliability benefit of $1 million per annum for a dual substation development path at Otahuhu.
6.3.5 The Commission has relied on the 1 in 100 year rate and Transpower’s related analysis for its decision.
6.3.6 Vector and Genesis both supported this approach, recognising the importance of prudent and practical judgment in determining how to analyse HILP events and related reliability benefits.
6.3.7 In making its decision the Commission recognised that, regardless of the Pakuranga substation development to 220kV, a significant amount of the load supplying the Auckland and North Auckland regions will likely be supplied via Otahuhu in the future. Specifically, in Transpower’s supporting analysis for the NIGU Proposal, it is clear that Otahuhu will remain the most critical substation in the region until at least 2042. This factor was acknowledged by Vector in its submission.

...

6.4 “Gold-Plating” precedent

...

6.4.5 In particular, as set out in paragraph 6.3.51 of the May 2007 Reasons for Decision Document, the Commission chose to exercise judgment, and adopted a notional probability reflecting that judgment, as to whether it is prudent to have Auckland, New Zealand’s major population centre, exposed to the prospect of a single major substation being affected by a low probability but high impact event. These factors related specifically to the Otahuhu substation and its significance in terms of the continued supply of electricity to Auckland.

[96] Commissioner Pinnell, in his dissenting opinion in May 2007, stated that he considered that Transpower’s estimate of HILP-related reliability benefits was overstated “by more than an order of magnitude”, and that there was no material difference in reliability between the Otahuhu Proposal and the other options considered by Transpower. He maintained that position in the Final Decision.

MEUG’s submissions

[97] Mr Smith, who presented this part of the argument on behalf of MEUG, submits that the Commission, far from neutrally assessing the direction and magnitude of the benefit associated with HILPs, selected its preferred option based on its holistic intuition as to which investment proposal was “better”. He submits that the Commission selected a “notional probability” to support that outcome and reasoned backwards, from a conclusion (the risk of another Auckland outage has to be avoided) to its selected factual finding. Mr Smith also submits that there was insufficient data on which to come to the conclusion. Further, he criticises the Commission for not using clause 9 of the GIT to account for HILP-related benefits.

Evaluation

[98] Wild J concluded that, given the critical importance of the Otahuhu substation for many years to come (and thus the particularly high impact of any HILP event), the cautious approach adopted by the Commission in the exercise of its judgement could not be viewed as unreasonable. In addition, the Judge considered that the support of Vector and Genesis for the one in 100 year probability adopted by the Commission was difficult to reconcile with MEUG’s submission that the probability is unreasonably high.
[99] We agree with Wild J’s analysis. There was a basis in the evidence for the Commission to opt for the one in 100 year probability. We thus do not consider that the Commission was reasoning back from a preferred result. It was merely taking a cautious approach, as it was entitled to do. Indeed, such an approach can be seen as mandated, given the importance placed on the avoidance of HILP events by the GPS (and particularly in light of the events at Otahuhu of June 2006). Further, it was obviously necessary for the Commission to take account of the importance of the Otahuhu substation to the electricity supply for Auckland and North of Auckland despite NIGU. The GPS mandates that the load which could be disrupted is taken into account when dealing with HILP events (see at [11] above).
[100] As to MEUG’s submission that there was inadequate material before the Commission, we note that no further evidence was put before the Court by MEUG to show what further work could have been done to arrive at a better probability figure. The Court is not in a position to guess what any further work might (or might not) show. By their nature HILP are difficult to quantify (low probability). We accept Mr Goddard’s submission that, in such circumstances, the Commission was right to be cautious about the risk of numerical estimates taking on a spurious certainty without the exercise of judgment. We also accept the Commission’s submission that it would not have helped MEUG’s position if the Commission had undertaken an analysis under clause 9 of the GIT. There would still have to have been some attempt at quantification in order to compare the projects.
[101] In summary, as the respondents submit, this is a classic example of a matter which called for the exercise of judgement by an expert body, based on the material before it and on its own industry knowledge and expertise. This ground of appeal fails.

Relief

[102] The question of remedy does not arise given that the appeal is to be dismissed.
[103] There were, however, strong reasons in support of the respondents’ contention that, even had there been a reviewable error, any relief should have been confined to declarations to guide future decision-making processes. This is particularly the case given that the position now taken by MEUG was not an option advanced to the Commission. Further, Transpower was entitled to treat the Commission’s decision as valid and proceed with the work (as it has done). This is particularly the case as there was an urgent N-1 issue that had to be addressed.
[104] We also note that the respondents, as an alternative submission, on the first ground of appeal, submitted that any misinterpretation of clause 4.1 of the GIT was immaterial because the Otahuhu Proposal could have been approved under clause 4.2 of the GIT (as noted in the Commission’s Final Decision of 30 August 2007). Given our finding on the proper interpretation of clause 4.1 of the GIT, we did not need to examine this submission (or MEUG’s contention that there are process reasons for rejecting it). It may, however, have provided a further reason for limiting the relief granted.

Result

[105] The appeal is dismissed.
[106] The appellant is to pay each of the respondents costs for a complex appeal on a Band B basis plus usual disbursements. We certify for second counsel.

Solicitors:
Chapman Tripp, Wellington for Appellant
Buddle Findlay, Wellington for First Respondent
Transpower NZ Limited, Wellington for Second Respondent

APPENDIX ONE

Glossary of Abbreviations


the Act
Electricity Act 1992
AIS
Air Insulated Switchgear
EG Rules
The Electricity Governance Rules 2003
GEIP
Good Electricity Industry Practice
GIS
Gas Insulated Switchgear
GIT
Grid Investment Test, being Schedule F4 to the GUI Rules
GPS
Government Policy Statement on Electricity Governance, October 2006
GRS
Grid Reliability Standards, being Schedule F3 to the GUI Rules
GUI Rules
Grid Upgrade and Investment Rules, being Section III of Part F of the EG Rules
GUPs
Grid Upgrade Plans, a plan for grid expansions, replacement and upgrades
HILP event or HILPs
A High Impact, Low Probability event
IGE
Interim Grid Expenditure
MEUG
Major Electricity Users’ Group Inc
N-1 Safety Net (or N-1 criterion or N-1 Reliability Standard)
With all assets that are reasonably expected to be in service, the power system would remain in a satisfactory state during and following any single credible contingency event occurring on the core grid
National grid
The electricity transmission network
NIGU Proposal
North Island Grid Upgrade Proposal
NPV
Net Present Value

APPENDIX TWO

The Electricity Governance Rules

[107] In this Appendix we set out the most relevant provisions of the EG Rules. In the original defined terms are in bold. We have removed this emphasis for ease of reading. We also note that references in the EG Rules to the Board should be read as references to the Commission.
[108] Relevant definitions in Part A of the EG Rules include:

“economic investments” means investments in the grid that can be justified on the basis of the grid investment test under section III of part F and are not reliability investments.

...

“expected unserved energy” means a forecast of the aggregate amount by which the demand for electricity exceeds the supply of electricity at each grid exit point as a result of likely planned or unplanned outages of primary transmission equipment.

...

“N-1 criterion” means that, with all assets that are reasonably expected to be in service, the power system would be in a secure state.

...

“reliability investments” means investments by Transpower in the grid, or alternative arrangements by Transpower, the primary effect of which is, or would be, to reduce expected unserved energy.

...

“satisfactory state” means that none of the following occur on the power system:

(a) insufficient supply of electricity to satisfy demand for electricity at any grid exit point;

(b) unacceptable overloading of any primary transmission equipment;
(c) unacceptable voltage conditions; and
(d) system instability.

...

“Secure state” means that the power system:

(a) would be in a satisfactory state; and
(b) would remain in a satisfactory state during and following any single credible contingency event wheresoever occurring on the grid.

...

“Single credible contingency event” means an individual credible contingency event comprising any one of the following:

(a) a single transmission circuit interruption;

(b) the failure or removal from operational service of a single generating unit;

(c) an HVDC link single pole interruption;

(d) the failure or removal from service of a single bus section;

(e) a single inter-connecting transformer interruption;

(f) the failure or removal from service of a single shunt connected reactive component.

Grid upgrade and investment rules

[109] Rule 2 of the GUI Rules provides:
  1. Purpose of the grid upgrade and investment rules

The purposes of the rules in section III [the GUI Rules] are to:

2.1 facilitate Transpower’s ability to develop and implement long term plans (including timely securing of land access and resource consents) for investment in the grid;
2.2 assist participants to identify and evaluate investments in transmission alternatives;
2.3 facilitate efficient investment in generation;
2.4 facilitate any processes pursuant to Part 4A of the Commerce Act 1986; and
2.5 enable the cost of approved investments to be recovered through the transmission pricing methodology applied in transmission agreements.
[110] Rule 12 of the GUI Rules provides:

12 Grid upgrade plans

12.1 Purpose of grid upgrade plans

12.1.1 The purpose of a grid upgrade plan is to enable Transpower to:

12.1.1.1 propose, and for the Board to review and approve, reliability investments that are justified on the basis of the grid reliability standards and the grid investment test; and

12.1.1.2 propose, and for the Board to review and approve, economic investments justified on the basis of the grid investment test.

12.1.2 These rules establish differing processes for consideration and approval by the Board of the proposed investments referred to in grid upgrade plans, depending on the nature of the proposed investment;

12.1.3 In making any determinations or exercising any discretion under rules 12, 13, 14, and 15, the Board must have regard to:

12.1.3.1 the costs imposed on Transpower, designated transmission customers, end use customers, and the Board itself arising from any process of consultation, review, modelling or public conference;

12.1.3.2 the likelihood of benefits to end use customers exceeding regulatory costs.

12.2 Obligations on Transpower in respect of grid upgrade plans

12.2.1 Subject to rule 12.2.2, Transpower must submit a grid upgrade plan to the Board within 3 months of receiving a written request from the Board, or such other date as the Board agrees, and may submit a grid upgrade plan for Board consideration at any other time.

12.2.2 Unless requested to do so by the Board, Transpower may not submit a grid upgrade plan to the Board in respect of a reliability investment that has been proposed by Transpower in accordance with the provisions of a transmission agreement or rule 5.6 of section II.

12.3 Content of grid upgrade plans

Grid upgrade plans submitted by Transpower under rule 12.2 must include:

12.3.1 a comprehensive plan for asset management and operation of the grid;

12.3.2 information on investment contracts;

12.3.3 investment plans disaggregated into the following categories:

Reliability investments comprising:

- proposed reliability investments;

- justification for proposed reliability investments against the grid reliability standards and the grid investment test;

- any options considered in identifying the proposed reliability investments;

- consequences of non-investment or delay in investment; and

- forecast costs of proposed reliability investments;

Economic investments comprising:

- economic investments proposed by Transpower;

- justification of proposed economic investments against the grid investment test;

- any options considered in identifying the proposed economic investments; and

- forecast costs of proposed economic investments.

12.3.4 Such other content as prescribed in writing by the Board, to ensure that grid upgrade plans include such information that the Board considers is reasonably required to enable the Board and interested parties to evaluate proposed transmission investments, such as indicative pricing impacts of investment proposals.

[111] Rule 13 of the GUI Rules provides:
  1. Approval of reliability investments
    • 13.1 Purpose

This rule sets out the processes for consultation, and Board approval of reliability investments proposed in Transpower’s grid upgrade plans.

13.2 Consultation
13.3 Board process for approving reliability investments
13.4 Board approval of reliability investments

The Board may:

13.4.1 Subject to rule 15, approve some or all of Transpower’s proposed reliability investments where a proposed reliability investment:

13.4.2 If the Board declines to approve a reliability investment under rule 13.4.1 above, it must publish reasons.

[112] Rule 15 of the GUI Rules provides:

15. Publishing of grid upgrade plans and approvals

15.1 Board to publish grid upgrade plans and intention to approve

The Board must publish grid upgrade plans and a notice of its intention to approve some or all of the reliability investments and economic investments in the grid upgrade plan.

15.2 Requesting a public conference

If a designated transmission customer, an authorised representative of parties substantially affected by the grid upgrade plan, or Transpower consider that:

15.2.1 the interests of end use customers are materially adversely affected by the cost or the service outcome of a proposed investment set out in a grid upgrade plan, or

15.2.2 the grid investment test has not been applied properly to a grid upgrade plan,

the designated transmission customer, authorised representative, or Transpower may, within 10 business days of the date of publication of the notice of the Board’s intention to approve some or all of the investments in a grid upgrade plan, request the Board to hold a public conference.

15.3 Purpose of a public conference

The purpose of a public conference is to provide a final opportunity for comment on the grid upgrade plan.

15.4 Board may agree or refuse request for public conference

15.4.1 The Board may agree or refuse the request to conduct a public conference.

15.4.2 If the Board refuses a request to conduct a public conference, the Board must publish its reasons for the refusal.

15.5 Board may confirm or amend investments in grid upgrade plan

15.5.1 Following the public conference, the Board may confirm or amend investments in the grid upgrade plan.

15.5.2 Where no public conference is held, Board decisions concerning investments in the grid upgrade plan are final.

Grid reliability standards

[113] Rule 4 of the GRS provides:
  1. For the purpose of clause 3, the grid satisfies the grid reliability standards if:
    • 4.1 the power system is reasonably expected to achieve a level of reliability at or above the level that would be achieved if all economic reliability investments were to be implemented; and
    • 4.2 with all assets that are reasonably expected to be in service, the power system would remain in a satisfactory state during and following any single credible contingency event occurring on the core grid.

Grid Investment Test

[114] The test itself is set out in clause 4, which provides:
  1. A proposed investment satisfies the grid investment test if the Board is reasonably satisfied that:

4.1 for a proposed investment that is necessary to meet the reliability standard set out in clause 4.2 of the grid reliability standards:

4.1.1 the proposed investment maximises the expected net market benefit or minimises the expected net market cost compared with a number of alternative projects; and

4.1.2 if sensitivity analysis is conducted, a conclusion that a proposed investment satisfies clause 4.1.1 is sufficiently robust having regard to the results of that sensitivity analysis; or

4.2 for any other proposed investment:

4.2.1 the proposed investment maximises the expected net market benefit compared with a number of alternative projects;

4.2.2 the expected net market benefit of the proposed investment is greater than zero; and

4.2.3 if sensitivity analysis is conducted, a conclusion that a proposed investment satisfies clauses 4.2.1 and 4.2.2 is sufficiently robust having regard to the results of that sensitivity analysis.

[115] Clause 9 of the GIT provides that:

Where a material market benefit or cost cannot be quantified, the direction of the market benefit or cost and likely magnitude of the market benefit or cost must be identified.

[116] Clause 19 provides a definition of alternative projects:

“Alternative projects” means any alternative transmission augmentation projects and transmission alternatives to the proposed investment, including any variant of the proposed investment that involves a non-negligible change in the timing of that proposed investment, that are:

19.1 technically feasible;
19.2 reasonably practicable having regard to the matters set out in clauses 8.1 to 8.4;
19.3 reasonably likely to proceed if neither the proposed investment nor any other alternative project proceeds and unlikely to proceed if the proposed investment does proceed;
19.4 reasonably expected to provide similar benefits, in type but not necessarily in magnitude, to relevant nodes, as the proposed investment; and
19.5 reasonably expected to enable the deferment of investment of the type contemplated by the proposed investment for a period of 12 months or more.
[117] Clause 32 defines a proposed investment as:

“Proposed investment” means a reliability investment or economic investment proposed by Transpower and submitted by it to the Board for approval under rules 13 or 14, respectively, of section III of part F of the rules. For the avoidance of doubt, an investment that is to be fully funded under an investment contract by one or more designated transmission customers that are party to that investment contract is not a proposed investment.

Comment

[118] As Wild J noted, the EG Rules are long and complex and in some cases, it seems to us, unnecessarily so. Various parts have been drafted at different times, leading to issues with integration. They would, in our view, benefit from some rationalisation and redrafting.

Is the primary effect of the investment (or would the primary effect be) to reduce expected unserved energy?

APPENDIX THREE: Decision-making flow chart


GEIP in meeting the GRS (r 13.4.1.1)?
Complies with rule processes (r 13.4.1.2)?
Economic Investment

no

Meets the GIT (r 13.4.1.3)?

no


Reliability Investment

yes


Rule 14 of section III of part F applies.
Transpower consults on whether it has applied the GIT reasonably in accordance with rule 14.2.4
Rule 13 of section III of part F applies.
The Commission seeks comments on proposal and alternatives to proposal in accordance with rule 13.3.2


Is the investment necessary to meet the reliability standard in clause 4.2 of the GRS (schedule F3)? That is, is the investment necessary so that, with all assets that are reasonably expected to be in service, the power system would remain in a satisfactory state during and following a single credible contingency event on the core grid?
Has Transpower followed agreed consultation process (r 14.4)?
Clause 4.2 of the GIT applies
Has Transpower applied GIT reasonably (r 14.4)?
Clause 4.2 of the GIT applies
Clause 4.1 of the GIT applies
Which clause of the GIT applies?

The Commission’s decision criteria
The Commission’s decision criteria
yes


APPENDIX FOUR

Investment Examples

[119] The Commission set out the following four examples to illustrate some of the practical difficulties with MEUG’s approach. We reproduce the examples here with some additional commentary. The numbers of course are merely used to illustrate the points. They are not based on or intended to be in any sense “real world” examples.

Example 1: N–1 time frame differences

Proposed project
Years for which
N–1 met
Transpower investment
Net market cost over 20 years
X
2
$10m
$50m
Y
10
$20m
$45m
Z
20+
$50m
$35m
[120] On the Commission’s approach, Transpower would be able to propose any of projects X, Y or Z under GIT clause 4.1, but only the project with the lowest net market cost could be approved – in this case, Z. On MEUG’s approach before the Commission, Y and Z could not be proposed under GIT clause 4.1.
[121] We note, however, that it has now been conceded by MEUG that investments can address N-1 over the long term. On this changed approach before us, measures designed to meet the N-1 criterion over a 20 year period can be proposed. However, as Transpower points out, there could still be issues with MEUG’s approach as, if the aim is to meet N-1 over the entire period, this may involve for example times when N-2 might be met for a period of overlap. According to MEUG, it would not be permissible to examine that overlap under clause 4.1 of the GIT.

Example 2: Technically independent investments

Proposed project
Transpower investment
Net market cost (benefit)
A
$30m
$20m
B + C (technically independent,
B can be done without C but C is dependent on B first being done)
$60m
$15m
B without C
$50m
$30m
C
$10m
($15m)
[122] On the Commission’s approach, Transpower would be able to propose B + C, and this proposal should be approved under GIT clause 4.1 as the least cost method of meeting N-1.
[123] MEUG says that Transpower could propose B without C under GIT 4.1. C could then be treated as a modelled project so B will be approved. C could presumably be approved separately under GIT clause 4.2 (and, we note, possibly after a different process under the GUI Rules if, standing alone, it is an economic investment).
[124] We accept the Commission’s submission that MEUG’s position may lead to an illogical result and that it, at best, creates unnecessary complications:

(a) It makes no sense for project B to be approved unless project C is approved, when the case for project B is dependent on project C going ahead;

(b) It is not possible to approve project C unless project B is approved;
(c) It makes no sense to require two separate approvals following two separate analyses under separate GIT (and GUI) provisions;
(d) If B has any element not technically needed to deliver N-1 then on MEUG’s approach it could not be proposed under GIT clause 4.1, even if this is what makes it possible to do C as well. Neither B nor C could be approved.

Example 3: Gold-plating/piggybacking avoided on Commission’s approach

Proposed project
Transpower investment
Market benefits
Net market cost over 20 years
M
$30m
$10m
$20m
M + P
$35m
$14m
$21m
G
$40m
$15m
$25m
[125] Project M is required to meet the N-1 standard. P is a “piggy-back” or “gold-plating” add on which costs an additional $5m, but only delivers additional market benefits of $4m ie there is a net cost of $1m. If Transpower proposed
M + P then the Commission would adopt M as an alternative project, and reject
M + P as not being the least cost way to achieve N-1 under GIT clause 4.1.
[126] G is a different “gold-plated” approach to solving the same N-1 concern, costing $10m more than project M but delivering additional market benefits of only $5m. If Transpower proposed project G then the Commission would adopt M as an alternative project, and reject G as not being the least cost way to achieve N-1 under GIT clause 4.1.

Example 4: a less expensive N–2 project

Proposed project
Transpower investment
Market benefits
Net market cost over 20 years
Q (N-1)
$50m
$20m
(benefits of $55m less future costs of $35m)
$30m
R (N-2)
$80m
$70m
$10m
[127] On MEUG’s approach, project R goes beyond what is technically needed to deliver N-1, so could not be proposed under GIT clause 4.1. Nor could it be approved under GIT clause 4.2 as it entails a net market cost. Although project R is the most efficient way to ensure that the N-1 standard is met, MEUG’s approach would mean that it could not be approved under the GUI Rules. We accept the Commission’s submission that this makes no sense. By contrast, on the Commission’s approach, project R can be proposed and approved under GIT clause 4.1 as investment is necessary to meet the N-1 standard and project R is an investment which will result in the N-1 standard being met.
[128] We can understand, however, that there may be some legitimate residual unease at the prospect of projects being assessed under clause 4.1 of the GIT which go well beyond addressing the N-1 criterion and which contain large discrete parts that may distort the market costs and benefits analysis. This concern should be able to be addressed by the careful choice of alternative projects or by the power of the Commission to request modifications to any proposed project. If it does in the future prove to be an issue, then there may need to be amendments to the GIT to address this.Has TP followed agreed consultation process (r 14.4)?

Economic Investment

EC’s decision criteria


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