POWERCO’S SUBMISSION TO THE COMMERCE COMMISSION IN RESPONSE TO ITS DRAFT DECISION PAPERS OF 23 DECEMBER 2002 AND 31 JANUARY 2003

Introduction

This document supplies Powerco’s submission to the Commerce Commission, in relation to its draft decisions relating to the Regulation of Electricity Lines Businesses (31 January 2003).

Powerco has contributed at every stage of the Commerce Commission’s process in establishing a method of price control for electricity lines businesses.

Powerco’s stance has been to support the development of a workable, fair and even- handed regulatory structure, that delivers long term benefit for consumers while still providing incentives to businesses to operate efficiently and effectively.

However, Powerco has serious concerns about the proposals contained in the Commission’s January draft decisions. Our concerns relate primarily to:

· The effectively universal nature of the control proposed;

· The proposals’ inconsistency with achieving the purpose statement;

· The likely impact of the proposals, including flight of capital from the sector, a loss of dynamic efficiency, and a deterioration of infrastructure due to reduced investment in maintenance and improvement.

This submission includes a number of parts, namely:

· The summary of our legal arguments; · Our responses to the Commerce Commission’s specific questions, and · Submissions from Powerco’s expert witnesses: o John Hagen – Chairman, Deloitte Touche Tohmatsu (NZ) o David Emanuel - Professor, University of Auckland o Barry Upson - Chairman, Powerco Limited o Kerrin Vautier – Research Economist o Alan Tregilgas – Practicing Utilities Regulator in Australia o UMS Group – International Utilities Benchmarking Consultancy o Steven Boulton – Chief Executive, Powerco Limited

Each element of the submission deals with a different aspect of Powerco’s argument against the current Commerce Commission proposals.

THRESHOLDS, ASSET VALUATION, AND INFORMATION DISCLOSURE

Executive Summary

1 Powerco’s first argument is that the proposed thresholds are unlawful as they amount to universal price control. There are related arguments of unlawfulness as to components of the Commission’s proposed thresholds.

2 The second argument is that, lawfulness to one side, components of the proposed thresholds are inconsistent with Section 57E (and Section 1A) as to:

(a) WACC

(b) “X” factors

(c) Point estimates as opposed to ranges of tolerances

(d) Using a starting value of recalibrated ODV which is too low

3 Thirdly, there are substantial detriments inherent in the Commission’s proposal including:

(a) There are no incentives for investment or efficiency improvement

(b) There will be dynamic efficiency losses

(c) There will be capital flight from this sector

none of which has been assessed by the Commission as part of a regulatory impact assessment which is an implicit requirement of Section 57E, given the umbrella objective of “long term benefit of consumers”.

Timeline

4 On 8 August 2001 Part 4A, Commerce Act 1986, was implemented.

5 On 21 March 2002 the Commission issued its first discussion paper. Particular aspects to be noted are these: - 2 -

· The Commission gave considerable weight to the purpose statement in Section 57E (paragraphs 1.1 – 1.5).

· The Commission noted (paragraph 1.6) that thresholds are intended to provide incentives to all regulated businesses to modify their behaviour and will affect all large electricity lines businesses.

· The Commission proposed four possible thresholds (paragraphs 1.10 – 1.13, 8.2).

· The Commission then analysed different mixes of the four thresholds, concluding that Option 1 best met the purpose statement of the Act (paragraphs 1.15, 1.18, 6.22, 6.36, 8.61 – 8.63).

· Option 1 involved two components: an indexed price path and a benchmarking study with a quality criterion.

· The Commission explicitly recognised deficiencies in other options (eg paragraph 8.49).

· The Commission set out its proposals for control including price

caps, the setting of P0 and X together with objective quality standards.

6 Powerco, and other lines businesses, set out their concerns that the proposed thresholds amounted, effectively, to universal control and were thus unlawful (eg see paragraph 2.15, UnitedNetworks submission May 2002; page 5, Powerco submission 9 August 2002). Lines businesses were particularly concerned that undue weight had been given to identifying and removing “excessive profits”, which was argued to have flowed from an overly mechanistic interpretation of Section 57E(a).

7 On 23 December 2002, effectively the last business day before Christmas, the Commission issued a paper on thresholds, asset

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valuation methodology and information disclosure, which set out a bare bones proposal with very little reasoning (the December Draft Decisions).

8 On 31 January 2003 the Commission published a further paper, fleshing out some of the details in the December paper (the January Draft Decisions). The proposed thresholds had changed from those set out in the December paper.

9 Powerco argues that the Commission’s proposed thresholds now include proposals previously recognised as deficient by the Commission in its March 2002 discussion paper.

Procedural Deficiencies in Consultation Process

10 While the December Draft Decisions established some broad outlines for the Commission’s proposed thresholds regime, these were significantly amended in the January Draft Decisions. With submissions due 28 February 2003, Powerco effectively has one month within which to address the significant issues and arrange for appropriate experts to give their opinions. That is simply insufficient time. These submissions (and the attached expert reports) reflect those circumstances. Powerco will continue to review these issues up to and including the conference in the week 10-14 March.

11 Nevertheless, it is Powerco’s submission that the Commission, by setting its own time line (there is nothing in the statute mandating that other than the direction in Section 57G(1)) is prejudicing the ability of Powerco to make a sufficient contribution to the Commission’s decision-making process.

12 Powerco also notes, with concern, that the two papers contain little or no explicit reasoning justifying certain key proposals. Moreover, there does not appear to be any serious engagement with the arguments raised by participants at earlier stages of the process. The Commission has not set out the statutory authority relied upon by it for all of its various proposals. The quality of the consultation process would have been

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enhanced if the Commission’s discussion papers had been more comprehensive.

13 The Commission makes a number of assumptions about consumer preferences. There does not appear to be any evidence supporting these assumptions.

The Commerce Commission’s Key Concept?

14 Apparently lying at the heart of the January Draft Decisions is the following:

“The Commission’s proposed thresholds provide incentives for lines businesses to continue improving the quality of their services while reducing prices in real terms. The Commission expects these price reductions to flow transparently to electricity consumers.” (page 2)

This appears to be the Commission’s paraphrase of Section 57E.

15 There are two particular flaws in this summary. First, the proposed thresholds will generate disincentives rather than incentives. Secondly, there is no apparent basis for the Commission’s expectation that price reductions will flow through to electricity consumers. Powerco now expands upon both arguments.

16 First, the lack of incentives. The purpose of regulation is to mirror competitive markets (March 2002 Discussion Paper, paragraph 4.28). The promotion of dynamic efficiency is a key factor in any regulatory regime. By contrast, the proposed thresholds provide none of the necessary incentives. A price path followed by an ex-post analysis of excess profits removes any incentives to management. There appears to be recognition by the Commission that “excessive profits” may actually include efficiency gains. However, the comments recorded in paragraphs 78 and 79 of the December Draft Decisions are insufficiently precise (and any event operate ex-post) to provide any comfort to Powerco. Certainly, they do not provide any incentives. Powerco, too,

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takes no comfort from the suggestion that a profit threshold may only be short term (December Draft Decisions, paragraph 94).

17 As a particular example of the problem, Powerco says there will be no incentives for it to invest in additions and/or improvements to its electricity network (including for example, (1) the connection of embedded generation to its electricity network and (2) the construction of an electricity reticulation network in a new subdivision). This argument will be developed by its witnesses. In essence, this argument is that investment in additions and/or improvements to its electricity network requires Powerco to commit investors funds. Unless the additions and/or improvements have the potential to exceed the investor’s cost of capital, these investments will not proceed. Under the Commission’s proposed thresholds (in particular the profit thresholds), investment in additions and/or improvements to its electricity network will not proceed as Powerco’s cost of capital is materially higher than the upper limit of the Commission’s proposed WACC range (i.e., 8%). This will be the case, notwithstanding that it does not automatically follow that if Powerco breaches the Commission’s proposed thresholds it will be subject to a declaration of control. Powerco (and its providers of capital) cannot assume that it will prevail (and therefore not be subjected to control) if its rate of return is at least equal to its “real” cost of capital - which is materially higher than the upper limit of the Commission’s proposed WACC range (i.e., 8%).

18 The Commission seems to have lost sight of the use of “strong incentives” in Section 57E(b). Indeed, incentives (let alone strong incentives) to improve efficiency appear to have been sacrificed in the face of short-term nominal and real price reductions (presumably resulting from the Commission’s focus upon “excessive profits”).

19 A price path, without the ex-post profit analysis, is less objectionable and, with a proper “X”, may well satisfy Section 57E. Powerco tends to agree with the Commission’s summary of the benefits of a price path (paragraph 82, December Draft Decisions). This is similar to what the

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Commission says in paragraph 8.49 of its March 2002 Discussion Paper. That, however, is not a formal concession by Powerco. As always, the devil will be in the detail. And, at the moment, the Commission’s proposed thresholds go far wider than simply a price path.

20 Secondly, Powerco comments upon the Commission’s expectation of consumer benefit. There is no explanation by the Commission as to why it has this expectation. Indeed, all evidence to date suggests that retailers do not pass through price gains made by them. The Commission’s proposals could well result in a wealth transfer to (in many cases) Government-owned retailers.

21 Obviously, though, the question of consumer benefit is an important one. Powerco agrees with the Commerce Commission at paragraph 4.11 of its March 2002 Draft Decisions:

“The focus in Part 4A is not on the interests of acquirers or suppliers of goods or services, but rather on the long-term benefit of electricity consumers.”

See also paragraph 4.23 of the same paper.

22 In the face of such an acknowledgment, it is not sufficient for the Commission to rely upon an expectation. If the Commission has some mechanism in mind which would underpin such an expectation then it should disclose that. Such analysis must underpin a regulatory impact assessment (see below). The Commission must satisfy itself that the proposed thresholds will result in the long-term benefit of electricity consumers (ie, that there is a net benefit when benefits are assessed against detriments).

Section 57E and “Excessive Profits”

23 Powerco has already made detailed submissions in relation to purpose statements such as Section 57E (pages 4 and 5, submissions dated 9 August 2002). It does not repeat those submissions here.

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24 It observes that the answer given by the Commission to question 42 in relation to the ENA meeting must be wrong. The first sentence in that answer elevates the purpose statement well beyond its intended role. Powerco also submits that the third bullet point in the Commission’s press release of 27 February 2003 is wrong. It is not accurate to speak of fulfilling each of the criteria in Section 57E as is done in the press release.

25 Against that general background, we make the following additional submissions about the use of “excessive profits” in Section 57E(a). In the December and January Draft Decisions, there appears to be an undue fixation upon the identification and removal of “excessive profits”. Yet, as the Commission previously noted in its March 2002 discussion paper, the definition of “excessive profits” is troublesome (paragraphs 4.27 to 4.29, 6.17 and 6.21).

26 The Commission has proceeded on the assumption that any profit in excess of WACC, over the medium term, is “excessive”. Powerco does not believe that is an adequate interpretation for the reasons that follow.

27 Section 57E(a) refers to targeted control which is effected by ensuring that suppliers are limited in their ability to extract excessive profits. Plainly, this does not require the Commission to identify and then remove all profits in excess of WACC. Indeed, there is a strong argument that a profit is “excessive” only if it exceeds WACC by a margin (say 2 or 3%). This argument overlaps with that made by the Commission itself at paragraph 8.41 of its March 2002 Discussion Paper. The word “excessive” carries pejorative overtones and the degree of pejorative overtone increases when combined with the verb “extract”. Nevertheless, the Commission has plainly interpreted “excessive” more liberally than Powerco advocates and has interpreted “extract” to mean “earn”. It wrongly uses the adjective “excess” interchangeably with that of “excessive”.

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28 And, moreover, the Commission seems to have lost sight of the emphasis upon “limited” used in Section 57E(a). Part 4A is not about stripping out all identified profits in excess of WACC. Rather, it requires the Commission to design a regime that will limit a supplier’s ability to extract profit that exceeds WACC by an appropriate margin.

29 The requirement for a margin above WACC is mandated by at least two factors. First, there is the uncertainty inherent in any calculation of WACC. Secondly, competition under the Commerce Act is to be workable or effective – not perfect. Medium-term “excessive” profits are not necessarily indicative of a problem. Indeed, they may be justified by the risk of assets becoming stranded in a particular instance (as Powerco submitted at the November 2002 conference).

30 The Commission should have regard to the final report issued by the Australian Productivity Commission issued in September 2002. The Commission concluded that regulators should not be overly ambitious or precise in their efforts to remove perceived “monopoly rents” from the income streams of regulated businesses, (see section 4.6 page 134 of Report 17 of the Australian Productivity Commission entitled “Review of National Access Regime” which was released on 17 September 2002)

Unlawfulness

31 Powerco submits that the proposed thresholds (that is, those proposed in the January Draft Decisions) are unlawful. It now sets out those reasons which it says support that submission. In doing so, however, it notes that it has had insufficient time within which to review these proposals. As noted above, the discussion papers contain little argument with which to engage. Powerco reserves the right to develop and expand upon these reasons following further consideration.

32 It has four discrete arguments, although these all overlap. The four arguments are:

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(a) The proposed thresholds are unlawful because they amount to universal price control. It is the degree of prescription/control embodied in the so-called thresholds that is the key concern.

(b) Transmission charges are wrongly included within the proposed price path and, while the Commission’s position in relation to contestable services is uncertain, they should also be excluded from the proposed price path.

(c) The information disclosure provisions of Section 57T are being relied upon by the Commission for unlawful purposes.

(d) The regulated asset base is too limited if there is to be an assessment of “excessive profits” as the Commission has proposed.

33 The first argument remains that previously advocated: the proposed thresholds amount to universal price control. The current proposals – more interventionalist than anything previously foreshadowed – simply emphasise the point. While it is accepted that thresholds may create incentives to modify the behaviour of all market participants, the intrusive regime proposed by the Commission goes well beyond the establishment of thresholds. The Commission appears to recognise the difficulty of distinguishing between thresholds and control. Yet it does not explain why it considers that its proposals do not go beyond the establishment of thresholds (December Draft Decisions, paragraph 83). This is despite the fact that extensive submissions have already been made on this topic.

34 The proposed thresholds regime is universally coercive and intended to be such. The Commission’s emphasis on speed of impact is part of this. The Commission obviously assumes that companies will try and avoid breaching those thresholds. The Commission’s proposal is extensive and very intrusive. It includes, at the least, the following components:

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· Banding lines businesses into three categories. “Those lines businesses that have been performing relatively poorly would face a higher X …” (media release 2003/104). The Commission will make judgements about efficiencies and excessive profits (January Draft Decisions, Executive Summary page 3 and paragraph 11). The Commission had originally concluded that one band only was appropriate (December Draft Decisions, paragraph 84).

· Establishment of P0 (effectively) by the above banding process and by setting a benchmark as at 8 August 2001 (January Draft Decisions, paragraphs 6, 9, 57). Effectively, this is to back-date the regulation, prior to the Commission finalising its regime.

· The establishment of X (as in CPI-X). A maximum of 5% is proposed. Such a high figure is not conservative (cf March 2002 Discussion Paper, paragraph 8.25). There is very little reasoning justifying the selection of the various percentage figures. Application of the price path to the revenue stream as distinct from opex is particularly onerous.

· Annual explanations by lines companies (if price path exceeded). Although it is not entirely clear, the Commission appears to rely upon Section 57I as justifying such a requirement (March 2002 Discussion Paper, paragraph 8.27). The subsequent papers do not address the matter explicitly. It appears to be assumed that lines companies will simply volunteer their explanations in order to avoid control.

· The generation of information and accounts, including audited regulatory accounts, by lines companies.

· Spot audits of lines companies.

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· The irrevocable adoption by lines companies of a particular valuation methodology (DHC or ODV) for inclusion in the “regulatory accounts”.

· Calculation of excessive profits which includes establishing an appropriate asset base and WACC to provide a benchmark. By using a point estimate of WACC the Commission effectively ensures that more than 50% of all lines businesses (assuming the majority have a WACC greater than 7%) will breach the threshold. That is a very high proportion more consistent with the declaration of control than establishing thresholds.

35 In establishing the proposed thresholds, it is obvious that the Commission has endeavoured to have regard to the purpose statement in Section 57E. The various components of Section 57E (particularly “excessive profits”) feature throughout the discussion papers. Overall, though, the proposals fail to meet the purpose in that they are not in the long-term benefit of consumers. As has been argued previously, the Commission has placed great weight on some aspects in Section 57E, at the expense of assessing how the long-term benefit of consumers might be enhanced. The Commission has not traded off the various components of the purpose statement, contrary to what it originally noted in its March 2002 Discussion Paper (paragraph 1.15).

36 The Commission’s proposals provide no incentive for a lines company to remain as an electricity lines business. If it improves efficiencies it will make “excessive profits” (as the Commission has interpreted that term) and will need to justify retention of these. It cannot assume it will prevail in such a contest. For a listed company such as Powerco the proposed thresholds regime is worse than control. That is because control would, at least, provide some certainty. Instead, the market is faced with a series of ex-post decisions to be made by the Commission, with no guidance as to how the Commission will approach the matter.

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37 The second argument as to unlawfulness follows from the Commission’s proposals to include transmission charges within the proposed price path (January Draft Decisions, paragraphs 19, 53, 56). In effect, the Commission expects Powerco to achieve efficiencies in relation to a charge over which it has no control and no hope of control. In terms of Section 19(1), Electricity Amendment Act 2001, Powerco is obliged to pay Transpower its charges so long as calculated in accordance with the transitional pricing methodology (as defined in Section 19 of the Electricity Amendment Act 2001) and has no obvious right to dispute Transpower’s charges other than if Transpower has had an arithmetical error in calculating its charges under the transitional pricing methodology.

38 The regulatory regime in Part 4A of the Act focuses on the business of Powerco as a large electricity lines business. The definition in Section 4, Electricity Industry Reform Act 1998, emphasises the ownership of lines to convey electricity. Section 57G(1)(a) talks about thresholds “for the declaration of control in relation to large electricity lines businesses”. Section 57F talks about declaring “all or any goods or services supplied by a large electricity lines business in markets directly related to electricity distribution” as controlled. A lines business does not supply electricity. By statute it cannot do so. It provides distribution services. It simply passes on the transmission charges. It does not sell transmission services. They are not part of the service that it provides and should fall outside the thresholds. Consequently, it is unlawful to include transmission charges within the price path.

39 Moreover, for a lines business on 5%, passing through transmission costs (Transpower regulated at 3%) requires the lines business to achieve efficiencies in relation to charges over which it has no control.

40 It seems doubtful that contestable services are intended, by Part 4A, to be included within the regulated price. The Commission’s position is not entirely clear (January Draft Decisions, paragraphs 39, 40 and 144). The better position appears to be that identified in the December Draft Decisions (paragraph 26) where the Commission noted that it was

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minded to exclude contestable services from the price path. There is no good reason to include contestable services within the price path.

41 The third argument of unlawfulness flows from the Commission’s indication of a requirement that lines companies provide certain data and information (January Draft Decisions, paragraphs 68, 86, 87, 88, 93, Table 5, 118, 142). In the Executive Summary (January Draft Decisions, page 4) the Commission makes it clear that the proposed regulatory accounts relate to the targeted control regime per se. The Commission relies upon Section 57T for this power (December Draft Decisions, paragraph 57). But Section 57T does not appear to authorise the provision of such accounts solely as part of a thresholds regime. Section 57T(1) makes clear the purpose of the subpart. It is about making information available to inform “a wide range of people” about key factors such as quality, security, etc. It is not there to facilitate a thresholds regime, nor is it limited in its audience to the Commission.

42 Moreover, the Commission does not clearly have power to force lines companies to have this material audited (eg see January Draft Decisions, paragraphs 122, 142, 168, 169, 171). The ambit of Section 57T(8)(b) is unclear but certification should not be assumed to be synonymous with auditing. In the absence of clear reasons from the Commission, however, it is difficult to advance this submission much further.

43 Furthermore, the Commission does not appear to have power to force lines companies irrevocably to choose between two different valuation methodologies in valuing its asset base (January Draft Decisions, paragraph 148). Sections 57T(2)(b) and 57T(8)(a) appear to empower the Commission to prescribe the form and manner of any methodology but that is simply for the purposes of information disclosure. It is not necessarily intended to have significance beyond that disclosure and, in particular, is not intended to be the regulated asset value for the determination of “excessive profits”.

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44 The fourth argument as to unlawfulness flows from the Commission’s conclusion that the asset base for the identification of “excessive profits” is limited to the system fixed assets as defined in this part of the Act (January Draft Decisions, paragraphs 106, 151). Yet, there is no suggestion in the Act that these assets comprise the only relevant assets of a lines company. Consequently, the Commission is wrong to talk about the various components of Part 4A as if they were an integrated and complete package (December Draft Decisions, paragraph 8). Powerco emphasises that there is nothing in that part which requires the Commission to calculate “excessive profits” simply on the basis of system fixed assets. The existence of intangibles and easements (January Draft Decisions, paragraphs 155, 163) is acknowledged by the Commission, but there is no real argument as to why these should fall outside the regulated asset base.

45 The Commission has taken too narrow an asset base. Inevitably, this will result in a conclusion of “excessive profits”. It is no answer to say that the Commission will update the handbook because this still will not include all relevant assets. However, at the very least, the handbook does need to be updated because the values are too low.

Regulatory Impact Assessment

46 At page 4 of its submission dated 9 August 2002 Powerco advocated an overall cost-benefit analysis as part of the threshold examination. It maintains that argument.

47 Despite recognition by the Commission of the desirability of a low-cost regulatory regime (December Draft Decisions, paragraph 2) there is no analysis of the considerable direct cost that the proposed thresholds will place upon lines companies such as Powerco, yet alone the indirect costs.

48 We note the Commission’s answer to question 3 posed by the Electricity Networks Association (ENA). The Commission said there was no requirement in Part 4A for the Commission to conduct such an

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assessment. On the assumption that the Commission and Powerco interpret the expression “regulatory impact assessment” the same way (ie as a cost-benefit analysis) then Powerco disputes that answer. The requirement in Section 57E for the Commission to act in the long-term benefit of consumers implicitly mandates such an analysis.

49 The benefits from the Commission’s proposal are likely to be minimal. This can be illustrated. If we assume that X is 3%, that CPI is 2.3%, and that the average lines charge (as per 2002 disclosures) is $740 per ICP, then the average line charge in the fifth year would be $712 per ICP, a reduction of $28 by the fifth year. For a domestic consumer this equates to $2.69 per month (GST incl) or less than 10 cents per day. There are just under 1.8 million ICPs in New Zealand, so this amounts to an annual saving of $50 million in the fifth year or $45 million in today’s currency. That is an absolutely trivial benefit when the direct and indirect costs of regulation are taken into account (although Powerco has not endeavoured to calculate all of those costs).

50 In making any assessment of cost/benefit the Commission must err on the side of conservatism. Standard practice in Australian regulatory circles is to act conservatively, recognising the intrusive and deleterious impact of poorly constructed regulation.

Price Path Threshold 1 Is the Commission’s No, the Commission’s proposed approach is not appropriate. Powerco believes that the proposed approach proposed approach to contains fundamental errors of law. These are laid out in detail in Powerco’s accompanying submission. the price path appropriate? If not, what Powerco has consistently argued against an inputs approach to thresholds, and this is still our position. method would improve upon the Commission’s In addition, we have a number of concerns at a practical level. proposed approach? First, there must be normalisation of cost, price, and quality, which must reflect the geographic and demographic features of the network. Powerco has a predominantly rural network with low customer density and lower per-customer use than many other lines companies. This means that Powerco has intrinsically high cost and low quality relative to denser networks, and these network features must be taken into account in any price path structure.

Secondly, the form of price threshold proposed by the Commission provides no incentives for efficiency improvement. The classification of businesses into three categories based on (amongst other things) “excessive profits” is an ex ante profit constraint and effectively is used by the Commission as a surrogate for setting P0. The addition of a retrospective profit threshold after 5 years, as proposed by the Commission, is a significant disincentive to businesses.

Powerco believes that this price path combined with an ex post profit threshold will destroy all incentives for realising efficiency. We recommend that the profit threshold should be abandoned.

Thirdly, in an orthodox CPI-X price control regime (as opposed to thresholds regime), the role of establishing P0 at the start of a regulatory regime is to remove excess profits. A regulatory bargain is then struck in which the regulator sets a price path based on a realistic assessment of cost saving and allowing for any necessary increases in costs or need for capital injection. This sets a target for the company to beat by making additional efficiency gains. There is no ex post check on profits, which means that companies are able to retain the additional efficiency gains earned (thus providing incentives for efficiency). A consequence of this is that companies that create efficiencies during the regulatory period will expect to earn profits greater than their WACC.

The proposals in their current form do not establish a regulatory bargain and do not present a target beyond which efficiency gains may be kept. In other words there is a ceiling but no floor to returns and therefore no intrinsic incentive to make additional efficiency gains.

2 On what basis should Powerco does not agree with the Commerce Commission’s approach of separating companies into three the Commission sort the bands. There should be no such banding as part of a thresholds regime. It is subjective and the Commission lines businesses into the have produced no rationale as to how the companies will be allocated into bands. See Upson evidence. proposed three categories? The three-band system is effectively a P0 reset, as recognised by Commission staff in recent dialogue with Powerco.

If, however, the Commission is determined to proceed with the three-band approach, rolling averages of price, cost efficiency and excessive profits should be used to minimise the effect of single-year fluctuations. Prior to 1 April 1999, lines businesses were bundled with retail companies and their performance data was to some degree aggregated. This would make a 4-year rolling average the longest practical period in 2003.

Investment efficiency is arguably more important than operating efficiency, yet this is virtually impossible to describe with a simple arithmetical index. To take investment efficiency into account there should be a weighting between opex and capex, so we recommend consideration be given to:

Relative operating cost efficiency: (4 year rolling average direct + indirect cost)/ICP Relative capital efficiency: Asset Value/ICP

Note that using ICPs as a denominator (rather than km or kWh) avoids distortions due to system characteristics.

Powerco does not believe that it is necessary for the Commission to consider price as an additional element in the banding exercise, but if the Commission is determined to use price, then it should be distribution price only, and it should be normalised for demography, customer and load density.

3 Is the Commission’s No, the Commission’s proposed range for X factors is not appropriate. proposed range for X factors appropriate? If An X factor if applied should not apply to the revenue line – rather to revenue net of uncontrollable costs not, how could this (transmission, financing and capital). The X figures to a maximum of 5% are simply too high if they are approach be improved? applied across the entire revenue base. Is there other evidence the Commission should Typically there is a 5:1 ratio of controllable costs to total revenue in lines businesses. A 5% reduction in consider in determining revenue therefore translates to a 25% reduction in controllable costs, which compounded year-on-year for 5 the X factors? years is clearly unachievable for any business.

The Commission’s use of overseas regulatory decisions ignores the difference in starting points. NZ prices are already as low as in the UK & Australia, so it is difficult to see how reductions as high as five percent per annum can be considered realistic or desirable for New Zealand (see UMS evidence).

Typically transmission is excluded from distribution business price paths in overseas regimes.

For a company on X=5%, the implication of the Commerce Commission’s approach is that the company will be expected to reduce its own costs by 10% of the value of transmission charges. This is the 2% difference between the price paths of Transpower and the lines business over the 5 year period. In Powerco’s experience, negotiation with Transpower has never proved effective. Transpower’s charges are the allocation of a formulaic revenue requirement, set and enforced by statute and no lines business has any ability to affect them.

Distribution business opex is approximately 20% of its total costs – the remainder being financing, transmission and capital-related. It is therefore Powerco’s submission that the X factor reduction only be applied to opex, and not to uncontrollable costs, as is currently the Commerce Commission’s intention.

4 Is the Commission’s Powerco has no objection to CPI being used as the index. Our concern is more the scope of control in terms choice of index of revenues and prices, than the index. appropriate? If not, what index should be used and why?

5 Is the Commission’s As we argue in answer to question 3, the price path should not apply to the entire revenue line but solely to approach to determining those components of cost that are controllable. average prices appropriate? If not, what Powerco submits that that contestable services should be excluded from the price path. We note the method would improve apparent inconsistency between paragraph 40 in the Commission’s paper, in which the Commission upon the Commission’s proposes to include all on-going charges and paragraph 144, where the tendency is to exclude contestable proposed approach? activities.

6 Is the Commission’s Yes. We agree with the concept of normalisation of price. We agree with the methodology proposed for the proposal for normalising inclusion of an implicit rebate, but we do not agree that this should apply only to Trust-based companies, on the price path for the basis that they give rebates to consumers. consumer trust-owned businesses appropriate? The formula proposed calculates the implicit rebate based on the degree to which ROI falls short of WACC. If not, what method This analysis should apply to any company earning less than WACC, not just Trust-based companies. would improve upon the Commission’s proposed Unless implicit rebates are applied to all lines business pricing, Trust-owned companies with high costs and approach? low prices will be under no obligation to improve their efficiency.

In addition, we argue that normalisation should ensure consistent treatment of all “below the line” items – in particular: rebates, discounts and subvention payments.

7 Is the Commission’s We repeat that the price path should be applied only to costs that are controllable by lines businesses. Sunk proposal of accounting asset returns, transmission costs and fixed financing costs should equally be treated as pass-through costs for cost pass-through for for regulatory purposes. selected items appropriate?

8 How could the In theory transmission costs can be minimised by reducing quantity or price or both. The opportunity for lines Commission provide businesses to minimise price is extremely limited due to Transpower’s pricing methodology. incentives for lines businesses to minimise Lines companies have a strong record of limiting quantities (i.e. demands on the transmission system) their transmission costs, through the use of load control. There is a natural affinity between demand control for transmission and the while allowing the pass- management of local constraints on distribution systems. through of these costs? In Powerco’s view those incentives still exist and any additional pressure through including transmission in the price path is totally unwarranted and will only mean that companies will be more likely to breach the price path. In many cases, particularly where the company’s X factor is higher than Transpower’s, the company will be unable to avoid breaching the price path.

Distributors do not resell transmission: where distribution businesses are subject to CPI-X price paths overseas, transmission costs are treated as a pass-through. This is because the services provided by the network transmission grid is shared by all interconnected parties. Individual transmission customers have limited ability in practice to influence either their individual cost or the quality of a regulated transmission service. Therefore, this cost component should not be part of distribution business price path.

9 Should the See our response to question seven. We believe that pass-through should be extended to include all Commission’s criteria uncontrollable costs. for selecting items for cost pass-through be refined? If so, how? 10 How should the Powerco believes price should be assessed on a four-year rolling average, beginning four years before the Commission treat price implementation of the new regime. This approach will smooth the distortions of one-off events, without the decreases occurring need for explicit data corrections. before the setting of the thresholds?

Quality Threshold 11 Is the Commission’s Quality is the dual of price – it makes no sense to set a price threshold without specifying the quality of proposed approach for service to which it is meant to apply. quality assessments for distribution businesses Rather than establishing a quality threshold in its own right, Powerco believes that the Commission’s concern appropriate? If not, what should be to specify the quality to which its price path is constrained. method would improve upon the Commission’s We do not believe that the use of trends in quality performance is either efficient or a reflection of customer proposed approach? preferences. We suggest that the quality “threshold” should be set in terms of absolutes rather than year on year changes.

We nonetheless support the Commission’s focus on leading practice and quality management.

Trend analysis for reliability performance is a useful discipline, but must cover a sufficiently large timeframe to smooth out the effects of unusual weather patterns. Short-run reliability measures of 4-5 years and long-run of 6-10 years would be more appropriate.

Planned outage performance is a consequence of optimising reliability, direct costs and asset investment. In so doing, asset managers trade off: live and dead-line techniques for overhead line construction and maintenance, and the higher costs of assets which improve security.

The trade-offs involve striking a balance between the costs of achieving a certain level of security with the value that end consumers place on it.

Hence, there is a trade-off between direct costs, asset investment and planned outage performance. A threshold that is set in terms of the continuous rate of improvement in reliability will lead to a breach by a large majority (if not all) of the lines companies, which we believe is inconsistent with the proper setting of thresholds.

12 Is the Commission’s The industry has been developing, in Part F of the proposed Rule Book for an Electricity Governance Board, proposed approach for mechanisms by which transmission customers can use transparent and, where possible, market mechanisms quality assessments for to establish, change and price transmission services. These arrangements provide for a considerably more Transpower sophisticated treatment of transmission quality than the limited set of thresholds the Commission proposes. appropriate? If not, what method would improve If quality is regarded as a constraint within which a price path is to operate rather than a threshold in its own upon the Commission’s right, it may be sensible to echo Transpower’s obligations under Part F rather than to establish simpler (and proposed approach? potentially inconsistent) thresholds as part of this regime. 13 Are there any criteria Paragraph 87 proposes criteria for exclusion of abnormal events outside the control of the lines company. that could objectively Powerco agrees with this philosophy for excluding such events but suggests the criteria be extended. define exceptional events ex ante? In particular, consideration needs to be given to the threshold of SAIDI to identify what is meant by a significant incident. The driver for the size of an outage event is customer minutes, not SAIDI, and hence the pass though events should be identified by its customer minute contribution. So, for example, a single uncontrollable event that resulted in loss of supply to a reasonable sized community (such as 2500 customers) for a reasonably significant time (say 3 hours), would be a reasonable threshold (at 450,000 customer minutes).

The SAIDI criteria for a significant event proposed by the Commission would result in smaller lines business being able to pass through significantly smaller incidents than a larger lines business (for Powerco with a customer base of 280,000, a SAIDI threshold of 3 minutes equates to an event of 840,000 customer minutes. For a smaller lines business with a customer base of 30,000 customers, a SAIDI threshold of 3 minutes equates to an event of 90,000 customer minutes). . The proposed SAIDI pass-through threshold would therefore have the effect of reducing the incentive to improve the reliability of the smaller lines business.

14 What are the costs and Powerco accepts that MAIFI would provide additional performance information with a reasonable cost. benefits of the proposed requirements for Powerco would support the reporting of performance at a feeder level. Overall system reliability performance disclosure of is driven by both the performance of the subtransmission network (including zone substations) and the MAIFI, call centre distribution network (feeders). The lowest practical level of common service is the feeder, and reporting performance, customer performance at this level is possible. There are, however, some issues to be decided about the nature of this complaints, connection reporting, such as, are up-stream outages included, and how will feeder-based targets be determined? service performance, and reliability at the We see that it would be difficult for the Commission to set targets or assess performance in this area on a feeder level? consistent basis across the industry, in particular given the influence of the subtransmission security on the feeder performance. Powerco therefore recommends that feeder performance (aggregating both feeder and relevant subtransmission outages) should be disclosed in companies’ Asset Management Plans, rather then being a threshold in its own right.

Powerco does not support the disclosure of call centre performance. The Commission should be aware of the interposed Use of System Agreements that exist, whereby the retail company manages the customer interface. Also, some call management systems download messages to the telephone exchange on current outages, hence customers ringing for outage information will be satisfied with the message on the exchange and abandon their call. This could mean that good customer service (having valuable information as an automated message) would unfairly affect the abandoned call statistic.

Powerco does not see any value in disclosure of technical quality complaints. The Commission needs to be mindful of the separation that currently exists between the flow of information from the end-customer to the Lines Business in respect of changes to customer loads. Since the split of line and energy businesses, distributors have considerably less information about the type of appliances connected to their networks. For example, a motor controller may cause harmonics that interfere with other consumers’ equipment (such as computers). In this environment, lines businesses have no option but to react to quality complaints, as they have no ability to control the loads that are attached to their network.

We do not agree that interruptions should be disclosed by type. Connection to Powerco’s network is competitive (contractors have to be approved, but are engaged directly by end consumers) and yet it is these contractors who are responsible for connection (and for connection-related interruption). This is therefore not Powerco’s responsibility.

15 Should disaggregated We support feeder-level disclosure of reliability. As we observe in our answer to question 1, network reliability performance characteristics vary considerably by feeder category, and segmenting feeder performance in terms of ICP be recorded and density (CBD, urban, rural) is essential. disclosed by grid connection point, by Clearly, increased levels of reporting comes at a cost, and the Commission needs to ensure that the individual feeder, or by increased costs of disclosure do not outweigh any related asset management benefits. category of feeder (e.g. CBD, urban, rural)? If so, how could this be best implemented?

Profit Threshold 16 What issues may arise The Commission proposes separating revaluations due to optimisation from other revaluations, and it does in differentiating not intend to allow optimisation revaluations to be directly compensated (January Draft Decisions, paragraph between revaluations 108). This approach stems from the Commission’s desire to expose lines companies choosing ODV to due to optimisation and optimisation risk, although lines companies would receive partial compensation through a slightly higher to other types of WACC. revaluations? Are revaluations due to The Commission treats optimisation differently from asset stranding (January Draft Decisions, paragraphs economic impairment 138 and 139). However, the ODV Handbook includes asset stranding within its definition of optimisation. always distinguishable, in practice, from those As optimisation revaluations do not receive any direct compensation in the excessive profit calculation, lines due to optimisation? companies that choose ODV may attempt to reclassify what should be optimisation revaluations as other revaluations.

The 0.15% margin to be added onto the WACC of lines companies that choose ODV looks to be arbitrarily determined. The Commission states that it considered historical evidence on optimisation and used this as a basis for considering the potential for future optimisation in arriving at its 0.15% margin. It should be noted that the level of optimisation as a proportion of ODRC for New Zealand’s electricity distribution companies in the 2001 financial year amounted to 2.2%1. It is unclear how such levels translate to the Commission’s 0.15% margin.

Given the uncertainty regarding the definition of optimisation, the potential for “gaming”, the arbitrariness of the Commission’s 0.15% factor, and combined with our proposal to use only ODV asset valuations going forward, we would suggest that the Commission dispense with its proposal to separate optimisation revaluations from other types of revaluation. It is essential that the margin on WACC for optimisation correctly compensates investors for the downside risk that balances the effect of downward revaluation. See Tregilgas evidence.

1 Recalibration of Asset Values of Large Electricity Line Owners, Parsons Brinckerhoff Associates Ltd, August 2002

17 Is the Commission’s No. We strongly disagree with the Commission’s proposed approach for the assessment of excess profits. proposed approach for the assessments of There are a number of concerns at a practical level. excess profits appropriate? If not, what An average industry WACC is clearly not appropriate. Lally’s own analysis identifies that Powerco’s method would improve observed asset beta in the market is greater than that suggested for the excess profit threshold. Therefore, upon the Commission’s by definition Powerco will not be able to avoid breaching the profit threshold if it meets its investors’ proposed approach? expectations for economic returns generated. See Emanuel evidence.

We also argue that the proposed asset base is inadequate (standard values are out of date and too low, intangible assets are not included, there is no account taken of training or commissioning). Under FRS-3, “fair value” for assets reflects their fully installed and commissioned cost. See Hagen evidence.

18 What components of the The excess profit measurement is profoundly distortionary and should be removed from the regime. See excess profit Powerco’s main submission. measurement need to be set by the Commission? For example, should the Commission prescribe depreciation rates? 19 Is the Commission’s No, the Commission’s numbers are too low, and asset betas and the market risk premium require proposed WACC range adjustment. for lines businesses appropriate? If not, what See Emanuel evidence. parameters require adjustment in the WACC calculation and why? 20 Is the Commission’s It is not appropriate. The Commission’s proposed adjustment of 0.15% is not supported on the Lally paper proposed adjustment for and there is no supporting rationale in the Commission’s Discussion Paper. optimisation risk appropriate? If not, what No company will be “indifferent” to the choice of methodology. is the appropriate size of this adjustment and why?

Regulatory Accounts 21 Is the Commission’s No. See evidence of John Hagen. proposed approach of allowing lines businesses a choice of valuation methodology going forward appropriate? 22 Are there any additional Not applicable (because it assumes a positive answer to the previous question). issues the Commission should consider to achieve consistency in profit assessment of businesses when they choose different valuation methodologies? 23 Are the Commission’s See response to question 24, below. proposals regarding regulatory accounts appropriate?

24 Are the Commission’s The Commission proposes that lines companies prepare a set of regulatory financial statements for the proposed requirements purpose of determining performance against the excessive profits threshold. As far as possible, the for regulatory accounts Commission would like these financial statements to be in line with the financial statements that are now consistent with the required to be prepared under the Regulations. Subject to what follows, we agree with this approach. requirements for financial statements The development of the targeted control regime calls into question the very necessity of preparing financial under the Regulations, statements pursuant to the Regulations (in their current form). The Regulations were developed when the such that the same environment was one of “light handed regulation” which encompassed information disclosure coupled with disclosed accounts the threat of regulation. The regulatory regime has now changed. would satisfy both requirements? The Commission notes situations where the regulatory financial statements could diverge from the financial statements prepared under the Regulations, such as to exclude contestable activities or when a merger or acquisition occurs. We would suggest that the regulatory financial statements proposed by the Commission be developed so as to replace the financial statements required under the Regulations. This means that a third set of financial statements will not need to be prepared. Additional disclosures can be accommodated by note disclosure.

In paragraph 150 of the Commission’s January Draft Decisions, the Commission states that following a business acquisition or merger the valuation of system fixed assets of the smaller lines company may change so as to be consistent with the valuation methodology of the larger lines company. We disagree with this approach as, under the purchase method, the acquirer’s accounting policies predominate. This means that the valuation methodology of the acquired company’s system fixed assets may need to change to be consistent with those of the acquirer, irrespective of their relative sizes.

The Commission also proposes that lines companies retain an acquired company’s regulated asset base upon a business acquisition or merger rather than record an acquired company’s regulated asset base at acquisition cost. The Commission doesn’t want revaluations that result from an acquisition or merger to “swamp” more routine revaluations, such as due to replacement cost inflation. We disagree with the above approach, as it is inconsistent with FRS-3. Any revaluations that result from business acquisitions or mergers can be explained by lines companies, and if necessary backed out, to identify the underlying level of routine revaluations.

25 Is a valuation handbook Yes, a handbook for ODV is desirable and necessary. We do not believe a handbook is necessary for DHC. necessary or desirable? Any handbook prepared must be predictable and correct. What components of the valuation methodology We would expect the Commission to consult separately on the drafting of new valuation handbooks. should the Commission prescribe? 26 Would the The Commission’s proposals for the treatment of transfer pricing are high-level. Shared services must, Commission’s proposals however, be transfer priced at avoidable cost. Any regulatory intervention to the contrary will remove any regarding transfer synergy between the businesses in common ownership and effectively force divestment and the actual pricing be adequate to increase in lines business overhead costs. This is both distorionary and inefficient. ensure recorded costs are fair and reasonable? Where services are transfer priced within a company, we strongly disagree with the Commission’s suggestion How might the that the suppliers of these services themselves should be subject to thresholds or price control. We are Commission approach uncertain as to the Commission’s intention in this regard but would expect the controls to apply only to the to this issue be asset owner or lines business itself – who will rationally seek the least cost provider for services of a given improved? quality and so discipline the prices paid for them through competition.

Evidence of John Hagen

· Chairmain, Deloitte Touche Tohmatsu (NZ) · Chairman, Accounting Standards Review Board (NZ)

Evidence of John Hagen, Deloitte Corporate Finance

I address two issues:

1. What is the most appropriate asset valuation methodology for regulatory purposes?

2. What is the most appropriate asset base for regulatory purposes?

I also speak to questions 16 and 21 to 24.

1. Asset Valuation Methodology

Our previous submission dated 11 November 2002 concluded that replacement cost-type methodologies such as optimised depreciated replacement cost (“ODRC”) or optimised deprival value (“ODV”) were the most appropriate way of valuing the specialised assets of electricity lines businesses, both for establishing opening values and for valuing assets in the future. Our reasoning for choosing replacement cost (in particular ODV) over historic cost is based on the following:

· Prices based on asset values determined by ODV are consistent with prices charged by an efficient new entrant into an industry, and thus are consistent with prices that would prevail in an industry in long run equilibrium.

· The asset records of many lines companies are inadequate and incomplete for the determination of historic costs. In particular, several lines companies on vesting (including Powerco) based their valuation of fixed assets on tax values which were somewhat arbitrarily determined.

· There is no conclusive evidence that the switch to ODV allowed lines companies to earn excess profits, negating one of the key arguments of those arguing against ODV. In particular, the inadequate asset records of many of the lines companies resulted in lines companies “finding” previously unrecorded assets throughout the 1990s, and this was responsible for a significant proportion of the revaluations that have occurred over the past decade.

· ODV not only enables dynamic efficiency to operate but also allows the optimisation process to penalise inefficient investment.

· ODV apportions key risks, such as demand and technological risk, onto those parties more able to bear and mitigate them.

· Retaining a replacement cost methodology minimises regulatory risk brought about by changing from ODV to historic cost.

Our reasoning for choosing ODV over other replacement cost-type methodologies reflects the potential for increasing contestability in the provision of electricity distribution services, e.g. through distributed generation. This enables lines companies to maintain regulatory financial statements in line with financial statements required under the Electricity (Information Disclosure) Regulations 1999 (the “Regulations”).

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While we agree with the Commission’s proposal to require opening values of system fixed assets to be based on ODV, the proposal to allow lines companies to choose either ODV or depreciated historic cost (“DHC”) to value their system fixed assets going forward creates a number of unnecessary complications. Our recommendation would be for the use of ODV alone:

· As lines companies will still need to maintain ODV valuations to meet the requirements of the Regulations, compliance costs are not being saved.

· The choice of asset valuation methodology going forward may depend, among other factors, on the interaction between current pricing and expectations of future replacement inflation. For example, a lines company whose current prices result in a current return on investment (“ROI”) greater than its weighted average cost of capital (“WACC”) may prefer to adopt DHC if it expects replacement costs to increase in future. This is because it may have to implement more drastic price reductions if it were to choose ODV as positive revaluations will place upward pressure on its ROI.

· Lines companies will effectively be separated into two groups, those that use ODV going forward and those that use DHC. This makes benchmarking more difficult.

· In addition, the Commission has stated that it will use comparative analysis of prices, costs, quality and profits in order to assign X-factors to lines companies. By allowing lines companies to choose asset valuation methodology, it may not be possible for the Commission to adequately undertake this comparative analysis next time around.

· Furthermore, the Commission has, somewhat arbitrarily, proposed adding a 0.15% margin to the WACC of lines companies choosing ODV to allow for optimisation risk. If only ODV valuations were allowed going forward, then either this margin could be dispensed with or else the application of this margin would be of less importance as it would apply equally to all firms.

· A further consideration is that lines companies may wish to switch asset valuation methodologies, for example, following a merger or acquisition. Indeed, we are unclear as to how the regulatory financial statements would adjust following the acquisition of a DHC (ODV) lines company by an ODV (DHC) lines company. As the Commission requires continuity of asset values in the regulatory financial statements, a lines company may end up with different parts of its network being valued using different methodologies. Alternatively, the acquiring lines company may be required to subsequently revalue the acquired system fixed assets (“SFA”) to ODV (DHC) which may result in a one-off shock to the acquirer’s excess profit calculation which, assuming no change in pricing methodology, may threaten the acquirer’s excess profit threshold (unless the Commission “looks through” such revaluations). We note that the Commission is also suggesting a departure from the purchase method of accounting for business combinations at paragraph 150 of its January Draft Decisions where it proposes that the accounting policies of the larger company in a merger or acquisition should predominate rather than those of the acquirer (irrespective of size).

A simplified approach of mandating just one asset valuation methodology – we advocate ODV – would alleviate most of the complications noted above.

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2. Appropriate Asset Base

The excessive profits threshold is based on testing whether lines companies set prices so as to consistently earn greater than a regulated return on their regulated asset base. The regulated asset base is calculated to be the sum of working capital and fixed assets which explicitly excludes intangible assets.

In turn, the major portion of fixed assets will be SFA which are to be initially valued at ODV. The ODV Handbook specifically excludes from SFA any head office buildings, furniture and equipment, motor vehicles, tools, plant and machinery, works under construction, consumers’ meters and consumer-based local control relays, and non-network land and stores/spares.

The ODV Handbook does, however, include easements obtained and registered against a land title after 1 January 1993, and paid for, provided that the sum paid has not already been expensed. Unfortunately, the ODV Handbook is unclear on how such easements should be valued.

Given that most line companies didn’t pay for many of their land access rights, there may be difficulties in including existing unregistered land use rights into the asset base. However going forward, the issue of easements for new distribution lines could become a significant issue and therefore their valuation would also become important. Given the ambiguity regarding their valuation, this should be addressed. To be consistent with the ODV methodology, the valuation of all easements should be at replacement cost reflecting the fact that these are specialised assets that would need to be replaced if the lines company were to be deprived of this segment of the network.

In addition, there is no mention in the ODV Handbook of how interest during construction should be treated, presumably because works under construction is not included in SFA. However, works under construction is explicitly excluded from the asset base used to calculate ROI and hence presumably lines businesses are unable to earn a return on these assets. Accordingly, as lines businesses cannot earn a return on works under construction, it seems appropriate to include interest under construction in the assessment of replacement costs of SFA.

On a business acquisition or merger, the Commission proposes to treat any excess of the acquisition cost over the regulated asset base, as recorded in the regulatory financial statements of the acquired company, as an intangible asset. The Commission does not want the resulting revaluation of regulatory assets to “swamp” more routine revaluations such as due to replacement cost inflation. We do not agree with this approach as it is inconsistent with FRS-3. The acquirer’s regulatory asset base should reflect the acquisition cost of the acquired company’s regulatory assets. Any revaluations that result can be explained by the acquirer and, if necessary, backed out to identify the underlying level of routine revaluations.

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Evidence of David Emanuel

· Professor, Department of Accounting & Finance, University of Auckland · Principal of Ernst & Young Corporate Finance Ltd STATEMENT OF DAVID MUNROE EMANUEL

1. My full name is David Munroe Emanuel. I am a Professor in the Department of Accounting and Finance at the University of Auckland, a position I have held since 1983. I am also a Principal with Ernst & Young Corporate Finance Limited, the financial consulting arm of Ernst & Young, Chartered Accountants.

Qualifications and Experience

2. I hold a Doctor of Philosophy degree, and a Master of Commerce degree with first class honours in Accounting. I am a fellow of the Institute of Chartered Accountants of New Zealand.

3. I have acted as a consultant for accounting and legal firms, and a number of government departments. My current duties at Ernst & Young Corporate Finance Limited include valuations of shares and other financial instruments, advice on efficient remuneration design, advice about capital structures, and other financial advisory services.

Scope of Opinion

4. I have been asked for an opinion about (a) the approach used by the Commerce Commission to determine the weighted average cost of capital (“WACC”) for electricity lines companies, (b) the actual numbers that have been suggested, (c) any special features about the approach and the numbers that have relevance to PowerCo Limited (“PowerCo”), and (d) any recommendation that I may have about a “threshold WACC” number that would be used in the excessive profits calculation.

5. The main documents that I have read in preparation of this statement are the Commerce Commission’s draft decisions dated 23 December 2002 and 31 January 2003, and Associate Professor Martin Lally’s report dated 31 January 2003 titled “The Weighted Average Cost of Capital for Electricity Lines Businesses”. (“Lally”).

Introductory Comments

6. Lally outlines an approach to the calculation of WACC that uses the Brennan-Lally version of the capital asset pricing model (“CAPM”) for the estimation of the equity cost of capital. This is then combined with an estimated cost of debt, given a particular level of leverage, L, to determine a range of WACCs. This range depends upon a range of market risk premia and a range of asset betas. The range of asset betas determines the equity betas, and the range of equity betas plus the range of possible market risk premia determine the final range of WACCs.

7. The Lally report is comprehensive and methodologically sound. It provides an appropriate basis for the progression of issues that the Commerce Commission is asked to address. However as in all cases of this sort, the devil is in the detail. There are some aspects of the analysis where I would use different numbers (or different ranges as the case may be). There is also an issue about the impact of leverage on WACC, where the Lally report states “whether this (0.40%) is a sufficiently large figure to be troubled with is debatable” which is, in my view, worth inclusion.

The CAPM

8. The CAPM requires estimates of a risk free rate, a tax parameter that is applied to the risk

free rate, an estimate of a DjTj term (assumed to be zero here), the beta coefficient, and the market risk premium.

9. I agree a five-year rate should be used in this analysis, which is the recommendation of the 31 January draft determination.

10. When we use the CAPM in a valuation at Ernst & Young, we typically set the TI parameter at .33, which is the value in the Lally report. However we note that some valuers use lower rates and in a previous piece of work Lally1 used 0.24. In the Lally and Marsden (2002)

paper, TIs of .27 and .28 are used. To the extent that the TI value that is used is “too high”,

the final ke value (the equity cost of capital) will be too low.

1 Martin Lally, The Real Cost of Capital in New Zealand: Is It Too High? (New Zealand Business Roundtable, 2000)

2 11. We also typically use a variant of Lally’s degearing formula (where we include a debt beta, but do not include any debt tax shield/gain on debt term). I agree that estimating debt betas is problematic, but debt betas are arguably not zero. I return to this below (in the context of PowerCo), although I do not regard this as a major issue.

12. Lally uses a range of asset betas, which are from 0.30 to 0.50. The discussion of the determinants of asset betas is comprehensive and appropriate. The central issue here is what new effect will the introduction of this targeted regime have on asset betas, compared with the prior regime? The problem is that it is not simply a question of whether the new regime is more risky in some absolute sense – it is a question of the impact of the regime on systematic or non-diversifiable risk within the context of the CAPM. The new regime, as enunciated, appears to have characteristics that make it more risky than the US, and possibly more risky than the UK regime. It is more risky than the US regime, where the price adjustment procedures provide relatively good protection from changes in demand and costs. Beta is expected to increase if the firm is limited in its ability to adapt to (undiversifiable) changes in demand and costs. In this respect, the proposed regime would appear to be no less risky than the UK regime. The average asset beta for UK electricity distributors is around 0.582. There is a case for increasing the range of asset beta values to say 0.60 on the upper side. As a consequence I conclude that an appropriate range for the asset betas is 0.40 to 0.60. Note that this places the top end of the range at approximately the same value as the average for UK distribution companies, so these numbers are arguably still “low”.

13. Lally uses a market risk premium of 7% with a range from 6% to 8%. This is a new and lower central value, down from the 8% parameter that he has used previously, and down from the value of 9% that was commonly used up to the 2000 year. This lower value is now used as the recently produced paper of Lally and Marsden (2002) “has the advantage of greater transparency in its taxation assumptions and estimates; accordingly it is preferred”. (Lally, p.8) At Ernst & Young we are using a market risk premium (of the Lally model type) of 8%. I have read the Lally and Marsden (2002) paper and consider that this is a comprehensive and well-constructed piece of work. My reluctance to use it as a basis for a lower market risk premium number at this time, even if I was to be persuaded that a

2 I Alexander, C Mayer and H Woods, “Regulatory Structure and Risk: An International Comparison”, paper prepared for the World Bank, 30 January 1996.

3 historical average rate was the primary indicator of future rates, is that it has not as yet undergone the systematic peer review that is required of all academic papers.

14. In any event, the important issue is that there is a large standard error around any central estimate of market risk premium that is based on the analysis of past data. This creates problems in the interpretation of numbers that are at the end or even beyond some designated range. The quote below, which illustrates the situation, is taken from a seminal article by Fama and French

“The second problem is the imprecise estimates of the factor risk premiums… . The annualised average excess return on the Centre for Research in Security Prices (CRSP) value-weight market portfolio…is 5.16%; its standard error is 2.71%. Thus, if we use the historical market premium to estimate the expected premium, the traditional plus-and-minus two standard error interval ranges from less than zero to more than 10.0%.

“Our message is that uncertainty of this magnitude about risk premiums, coupled with the uncertainty about risk loadings, implies woefully imprecise estimates of the cost of equity”. 3

15. A similar result is apparent with the Lally and Marsden (2002) paper. The standard error around the mean “simplified nominal tax-adjusted market risk premium” is about .028, and so in the same spirit as Fama and French we can be 95% sure that the “true” expected market risk premium is between 1.3% and 12.7%.

16. In summary, there is still substantial uncertainty about what is the expected market risk premium, and large standard errors around historical mean values that makes the establishment of forward looking estimates problematic. Further, if we are to look internationally at historical market risk premia, one of the best sources of multi-country information is the work of Dimson, Marsh and Staunton4. The median market risk premium across their countries is about 7%. Lally’s own adjustments to this number gives a Lally- style market risk premium of 9.4%.

3 E F Fama and K R French, “Industry Costs of Equity”, Journal of Financial Economics 43 (1997) 153 – 193. 4 Their work appears in a number of places in different forms. See for example Triumph of the Optimists, Princeton University Press, 2001.

4 17. For the purposes that follow, I will use a range of market risk premia of 7.5% to 8.5%. This (relatively narrow) range is distributed around our firm’s current choice of estimated market risk premium, but allows for some uncertainty about the “true” estimate.

L and the debt premium

18. Lally and the Commission recommend an L value of 0.30. This is accepted as a reasonable starting point, although higher L values could be contemplated. I will return to this below as PowerCo currently has a value of L which is substantially greater than 0.30.

19. With L of 0.30 a p (premium) value of 1% is not unreasonable.

20. This gives resulting WACC values as shown in the following table.

Table – Estimated WACC values based on alternative estimates of asset betas and market risk premia

Market Risk Premium is 7.5% Asset Equity

Betas Betas k e WACC Low 0.4 0.571 8.17% 7.09% Medium 0.5 0.714 9.24% 7.84% High 0.6 0.857 10.31% 8.59%

Market Risk Premium is 8.5% Asset Equity

Betas Betas k e WACC Low 0.4 0.571 8.74% 7.49% Medium 0.5 0.714 9.96% 8.34% High 0.6 0.857 11.17% 9.19%

Optimisation Risk Adjustment if ODV is used

21. The Commerce Commission recommends an adjustment of 0.15% for ex ante “optimisation risk” if ODV is used. It is not clear where this number comes from, although it appears to have been motivated by the fact that these losses have not been much of an issue in the past (judged presumably by write-offs in lines companies’ accounts), and that while arguments have been made about the impact of changing technology on asset value, the Commerce Commission remains to be convinced that this is going to be a problem. I also struggle to

5 know what an appropriate adjustment should be. It would be desirable if the Commerce Commission were to outline a systematic approach to the evaluation of this issue. In the absence of an explanation as to how 0.15% has been calculated, I do not comment further.

Other Issues Affecting PowerCo that are relevant in the determination

22. The Lally paper estimates the equity beta of PowerCo at 0.96 and a consequent asset beta of 0.48, given that L is 0.50. However arguably PowerCo has a debt beta that is not zero. The asset beta of PowerCo is given by the following formula:

ba = b d L + be (1- L)

All terms on the right hand side need to be estimated. As indicated above, Lally sets ßd to zero.

It is true that estimating ßd is not simple, but equally it is arguable that ßd is not zero. In this opinion I provide an approach for the estimation of the debt beta.

A distinction needs to be made between a promised yield and an expected yield. Promised yields are what are observable, whereas it is an expected return that is estimated in the capital asset pricing model.

Assume in any period that a bond will default with probability pd. If the bond does default a payment is made to the owner of the bond which is equal to (1-?) times the price of the bond a year earlier. If that is the case it can be shown that the promised yield is as follows5:

Expytm+ lp Pytm = d (1- pd )

where Pytm is a promised yield and Expytm is an expected yield. Now of course, both ? and

pd have to be estimated, and (assuming that the resultant number is to be used in a CAPM- type calculation) we need to assume that no other factors than “yield spread” (the difference

6 between a risk free rate and an expected return) and “default premium” (the additional return attributable to default) enter the calculation of the promised yields.

PowerCo’s promised return on debt instruments is approximately 7.8%. Assume pd is between 1% and 3%, ? is in the range 10% to 20%, then the difference between promised and expected yields is between .2% and .8%. This would give an expected rate of return on debt of around 7.3%. As the riskless rate is approximately 5.8%, the debt premium on expected returns is 1.5% (and on promised returns it is 2%). An estimate of the debt beta would be about 0.26.

This means that empirically, PowerCo’s asset beta is about 0.10 higher than the estimate given in the Lally paper. Arguably it is therefore between 0.50 and 0.60, that is in the top- half of the range that I would recommend as appropriate for this analysis.

23. Further, PowerCo’s L is higher than 0.30. The L used by Lally to illustrate PowerCo’s asset beta is 0.50, although L is currently higher than this. Lally indicates that a change in L and p will have an effect on WACC, and given his equations (1) to (4) the impact is effectively restricted to the right-hand (i.e. debt) term in his WACC formulation. That is, it is:

(1-t c )(L1 p1 - L0 p0 )

where tc is the corporate tax rate and 0 indicates initial level and 1 the new level. If the new values of L and p are (say) 0.60 and 0.015, then the addition to the starting WACCs is .004 or 0.40%. Lally states “ whether this (0.40%) is a sufficiently large figure to be troubled with is debatable”. My view is that it must be included, and that 0.40% is large relative to his WACC range of 6% to 8%, and my range.

What should be a “threshold” WACC for the determination of excessive profits?

24. The question that PowerCo has asked me to address is what level of threshold should be set in the measurement of “excessive profits”. I know that PowerCo is arguing that “excessive”

5 This is a simple one period model where there is either default with probability pd or no default with probability 1-pd. Payoffs are (1-?)P or P(1+Pytm) respectively. P is the current price of the financial instrument. See W Sharpe, G Alexander and J F Bailey, Investments (Sixth Edition, Prentice Hall), p. 395 6 This is consistent with an ABN AMRO estimate of 0.18.

7 profits must be at a level somewhat in excess of WACC. PowerCo argues that this is WACC plus a margin. My opinion as to the appropriate threshold WACC is set out in the next paragraph.

25. As this is a targeted regime, then presumably the Commerce Commission would wish to enter into dialogue where there is some fairly strong evidence of possible rents accruing to the company. Given the uncertainty with the parameter estimates that enter into the CAPM in the first place, the minimum WACC that I would recommend in such a setting is 9%. This corresponds to a “high” (0.60) asset beta scenario with a market risk premium of 8.5%, which is a WACC point estimate of 9.19% in the Table above. Of course if leverage is higher (say 0.60), the 9.19% becomes 9.59%. And this excludes any allowance for ex ante optimisation risk. So 9% is therefore a relatively low threshold, and (if applied) could result in dialogue with a number of companies that would be reporting “excess profits” where those companies are arguably not capturing any rents. This number is based on the same assumptions and methods as set out in Lally. To the extent that those assumptions do not apply to individual lines companies, then a different WACC will be required.

26. Inevitably the notion of “excess profits” will become politicised. It has a perjorative ring about it, even if it is in a sense a purely definitional issue – just the return in excess of some Commerce Commission determined WACC. It seems that a higher threshold WACC is more desirable than a lower one, as setting a WACC that is “too low” may well reduce investment in the industry, relative to a higher value, even in a context where this WACC is only being used to measure “excess profits”.

27. And following the argument presented by Lally (see for example p. 47), an even higher rate would be used if a price-cap was imposed on any particular firm.

Summary

28. The main conclusions of this opinion are:

· The methodology employed by the Commerce Commission with regard to WACC is appropriate;

8 · The range of asset betas is too low, and a more appropriate range is 0.40 to 0.60;

· The expected market risk premium is too low, and a more appropriate range is 7.5% to 8.5%;

· A starting leverage ratio, L, of 0.30 and a risk premium, p, of 0.01 are appropriate although higher values could be contemplated;

· The resulting WACCs vary from 7.09% to 9.19%;

· Increased leverage to 0.60 would increase WACC by a further 0.40%;

· An appropriate threshold WACC for “excessive profits” calculation would be no less right 9%;

· It is unclear whether 0.15% is adequate to compensate for optimisation risk, and it is unclear how this number has been derived;

· A lower TI value would increase the equity cost of capital and hence increase WACC.

9 Evidence of Barry Upson

Chairman, Powerco Limited

EVIDENCE FOR COMMERCE COMMISSION

Prepared by B R Upson (Chairman – Powerco Limited)

Proposed Price Path

1. The profile of the distribution sector of the electricity industry can be determined from the 2002 Electricity Disclosure Accounts. The 29 companies that make up the sector have the following profile:

· Total volume distributed: 26,645.5 Gwh · Consumer connections: 1,778,455 ICPs · Network length: 143,908 kms · Total Line Charges: $1,315.3 ($’000 p.a.)

2. No information was available to determine the number and consumption levels of various classes of consumers such as heavy industrial, industrial, commercial, farming, domestic.

3. Consequently, an “average consumer” is a composite of the various classes of consumers and as such, probably does not match any particular class. However, domestic consumers would represent the largest number of ICPs although their average consumption would be well under that of the market average consumption.

4. An “average consumer” based on the above disclosure data has the following profile:

· Average customer consumption: 14,982 Kwh · Average line charge per consumer $740 p.a. · Average price per Kwh 4.94¢

5. It should be noted that typical domestic consumers have consumption in the 6,000 to 8,000 Kwh range p.a.

6. The weighted average line charge per consumer has fallen for the three years ended 31 March 2002 as follows:

2000 2001 2002 · $/ICP $745 $751 $740 · ¢/kWh 5.03¢ 4.99¢ 4.94¢

7. In effect, the sector has operated under a CPI – X regime where “X” has equalled CPI. This outcome is a constructive trend that the sector has achieved voluntarily under the light-handed regime. Powerco has maintained constant average prices for the past four years.

8. Table 1 (attached to this evidence) highlights the price path proposed by the Commission using “X” factors of 1%, 3% and 5% and compares the change

- 1 - compared with a base scenario where “X” equals zero. The effect of the price path change has been applied to operating costs and EBIT to determine the savings required or the reduction in EBIT that would occur if no cost savings were achieved.

9. The reduction in line charges for “X” factors of 1%, 3%, 5% (2003 dollars) are summarised as follows:

$ / ICP p.a. Year 1. Year 2. Year 3. Year 4. Year 5.

“X” = 1% $7 $15 $22 $29 $36 “X” = 3% $22 $44 $65 $85 $104 “X” = 5% $37 $72 $105 $137 $167

10. How and whether any reduced line charges are passed on by retailers to end consumers is uncertain. Heavy industrial and industrial consumers dominate the market by value and are likely to capture the bulk of any savings through direct negotiation. The reduction for domestic consumers is likely to be minimal or nil.

11. Table 1 also highlights that at levels of 3% and 5% some aggressive cost reductions are required to avoid excessive reductions to EBIT. The following summary of the Table highlights the impact.

Year 1. Year 2. Year 3. Year 4. Year 5. “X” = 1% Opex Reduction 2% 3% 5% 7% 9% EBIT Impact 1% 2% 2% 3% 4%

“X” = 3% Opex Reduction 12% 23% 34& 44% 54% EBIT Impact 6% 11% 17% 22% 27%

“X” = 5% Opex Reduction 21% 42% 61% 79% 96% EBIT Impact 14% 27% 39% 50% 61%

12. Table 1 assumes that transmission charges will follow a CPI minus 3% price path and that depreciation costs remain constant. The only item that line companies can directly control is operating costs (Opex). If the line price reductions (less the transmission cost movement) are not reflected in a reduction to Opex, then the impact will be fully reflected in a reduction to EBIT.

13. The Commission has not provided any current or historical cost comparisons or trends to enable a clear determination of whether these substantial cost reductions are achievable. Operating costs for New Zealand lines companies have been benchmarked as being in the lowest quartile (if not the lowest) in international comparisons. To achieve further reductions of over 25% by Year 5 is overly aggressive, if not impossible. An international comparison of

- 2 - operating costs is being prepared by UMS for presentation at the Commission Hearing to compare the New Zealand trend and position.

14. A shortfall in these cost savings will reduce EBIT for the sector. EBIT is the prime number in the numerator for the ROI calculation. The average ROI disclosed in the 2002 disclosure accounts of 6.0%1 is at the bottom end of the suggested WACC for the sector. A further reduction to EBIT will compound the cashflow consequences and put into jeopardy the ability of many companies to replace their assets on a continuing basis let alone make investments for increased capacity and supply security. This will result in a gradual rundown of the productive capacity for the sector

15. The major function of an electricity lines company is to maintain supply at an acceptable quality and price. To carry out this function, lines companies have direct control over the decision-making process for network maintenance and network replacement. These two large expense categories interact and cannot be treated in isolation to each other.

16. The disclosure accounts highlight the vast variations between networks for maintenance expenditure (included in direct costs) and network replacement expenditure (as reflected in the ODV of the assets). The 2002 disclosures for direct costs ranged from a low of $574 per kilometre of line to a high of $2,290 per kilometre, whilst the ODV investment ranged from $12,751 to $102,466 per kilometre of line demonstrating the vast diversity of the structure of networks in New Zealand.

17. How the Commission proposes to categorise lines companies into the three “X” factors has not been made clear. The disclosure data does not provide a clear picture to determine whether a company is operating efficiently or not (in either operating cost or capital efficiency), or whether its pricing is excessive or not. There are a vast number of non-financial issues that impact on the operating costs and subsequent pricing of lines companies. These factors include (but not exclusively) such items as: network condition, network age, network density, network design, network utilisation, geology of terrain, annual weather patterns, exposure to salt air, grid exit point locations, electricity loss factors, level of security required, extent of under-grounding, average load of customers, extent and timing of peak demands.

18. Based on information available from disclosure accounts, the grouping of companies into the proposed X factor categories will be extremely subjective and open to challenge.

19. It should be noted that following recent Government decisions substantial additional costs are also now being imposed on the lines sector e.g. application of utility ratings of assets by a range of local councils. Powerco alone is faced with rating demands exceeding $2m for the 2003/04 year compared with less than $25,000 for 2002. This increase will increase operating costs by over 7%

1 PricewaterhouseCoopers – 2002 Information Disclosure Compendium page 30

- 3 - p.a. This rating cost could escalate to $8m p.a. or $27/ICP in the foreseeable future.

20. The increase in anticipated uncontrollable costs across the sector will force all companies to breach their price path from Year 1. Such a situation raises serious questions about the practicalities of the proposed regime and how quickly the Commission will be able to respond to "approval" for these breaches.

21. If the proposed industry WACC is below the companies’ current WACC then it is highly unlikely that new connections for consumers and new embedded generation will be able to be funded by the lines companies. There is no incentive for a lines company to directly negotiate suitable new connection arrangements if the benefit is lost to all other consumers with no benefit attributable to shareholders. New connections will need to be funded directly by consumers themselves and would be capitalised on the balance sheet of the consumer at their cost of capital.

22. The lack of reinvestment to maintain capacity at present levels and to further improve quality and reduce outages will have serious consequences to the national economy, and the Governments stated focus on growth, and are not in the medium/long term interests of consumers.

23. The long-term sustainable benefit to consumers will be further eroded by the cost of implementing and monitoring the proposed regulatory regime. Such regimes overseas are known to be expensive and a regulatory Impact Study should be conducted into all aspects of this proposal before it is implemented.

Capital Markets

1. Powerco is now unique amongst the 29 electricity line companies in that it is the only company now included in the NZSE40 index and has made full use of capital markets for debt and equity raising in recent times. It should be noted that more than 17,000 New Zealand shareholders own the Company. Amongst Powerco’s shareholders are a number of Trusts and a local authority.

2. The extensive uncertainty contained in the proposed regime has lead market analysts and other commentators to look at worst case scenarios. Their interpretation of the effects of the proposed regime are not always correct but this position highlights how markets react to confusing statements and positions taken by Government agencies and other Statutory or Regulatory bodies.

3. Chart 1 (attached to this evidence) shows the effect on the Powerco share price from 1 September 2002 through to 25 February 2003. This chart highlights how the market has reacted to various reports associated with Commission announcements and analyst reports. This share price movement has resulted in a value loss to shareholders of approximately $135 million for this period.

- 4 - 4. Whilst the Commission may argue that the market “could” recover once a stable regulatory environment has been established, many shareholders have lost considerable value during the process. And, more importantly, while the Commission could argue that the share price will recover, as Chairman I would not be prepared to make such an assumption. Moreover, the Commission’s argument assumes a stable regulatory environment and, as I go on to say, I do not think that the current proposals meet such a standard.

5. The announcement of a breach of any of the thresholds will immediately put a company under close scrutiny by the market and will be seen as a negative situation pending the decision of the Commission on whether the breach is justifiable or not. This is an untenable situation as far as capital markets are concerned and will result in greater equity betas being assigned to the company.

6. The announcements each year of any “excessive” profits will further exacerbate the market. There will be no desire to wait until the end of the fifth year to see whether the company can justify any “excessive” profit or not. Such “excessive” profit will become a contingent liability in the accounts of the company as there is no certainty how the Commission will eventually treat this item.

7. Capital Markets make decisions based on forward-looking documents and projections. The proposed regime from the Commission is backward looking in that companies have to wait until the end of the fifth year (unless they have breached the price and/or quality thresholds) before the regulated profit level can be determined.

8. The Capital Markets do not accept the Commission’s stance that the regime is a threshold regime and that companies are under control only if they cannot justify their breach. The Capital Markets view the thresholds as the acceptable limits imposed by the Commission and would not expect companies to be in breach. That is the way that the Listing Rules operate for the NZ Stock Exchange where companies who breach the rules are heavily penalised.

Level of WACC

1. The equity beta factors proposed to calculate the industry WACC are below a factor of 1. This presumes that the equity risk for shareholders in electricity lines companies is less than the average market risk.

2. There are several factors to consider when assessing the validity of this assumption.

3. Electricity lines companies presently take on a disproportionate share of self- insurance against the effects of weather conditions, earthquakes and volcanic eruptions. This self-insurance is a risk to shareholders and should be reflected in equity betas to avoid these companies having to put large insurance cover policies in place to avert the risk. Under the proposed regulatory regime it is

- 5 - unlikely that shareholders would continue to assume this risk. Rather, increased cover would be sought from underwriters. Such increased premiums are an uncontrollable cost and would be passed onto consumers.

4. The Capital Markets have perceived a significant increase in regulatory risk and, as stated above, are demonstrating this by voting with their feet and leaving the sector. This increased regulatory risk also needs to be reflected in equity beta factors.

5. Powerco has a high, if not the highest, debt leverage in the industry. Following the recent acquisition of certain United Network assets, its debt leverage is above 60%. This increased leverage has increased financial risk arising from interest rate volatility and ability to maintain debt covenants. Determining the WACC once every four years could be detrimental to making investment decisions when the current cost of capital exceeds the WACC.

Governance Issues

1. The Powerco Board has closely monitored the evolution of the electricity regulatory regime over a number of years. In particular, it has kept abreast of the developments since the amendments to the Commerce Act 1986 in 2001.

2. During 2002, Powerco conducted two capital raisings, which required the issue of Investment Statements and Prospectuses. The first was issued on 26 April 2002 and the second on 18 October 2002. These documents, issued under the Securities Act 1978, required the Company to conduct a thorough due diligence on its activities and to advise the market of known risks.

3. The Company made comment on the proposed regulatory regime in the Investment Statement and Prospectus based on discussions papers issued by the Commission. In particular, the discussion paper issued by the Commission in March 2002 was used as a guide to the direction that the Regulatory regime was likely to take.

4. The draft proposal issued by the Commission on 23 December 2002 was materially different in design and direction compared with previous discussion papers, and this has been picked up by Market Analysts. This has caused confusion in the market place with Analysts being fearful of the Company’s ability to maintain its Credit Rating, debt covenants and fund future investment requirements and dividend payments. One Analyst2 has valued the Companies shares as low as $1 (from a previous high of $1.80 - $2.00) per share, which has caused major consternation in the market.

5. The continuous disclosure requirements of the NZSE Listing Rules (which came into force on 1 December 2002) have increased the difficulties faced by the Company. To date, the Company has deferred comment on the draft proposal as it could be misinterpreted between various stakeholders. Until a

2 UBS Warburg 20 February 2003.

- 6 - decision is made on the final regulatory framework, any comment from the Company may be subject to misinterpretation. This has placed the Company in a very difficult position with regards to making any comment on the validity or otherwise of its forecasts provided in the October 2002 Investment Statement and Prospectus.

6. The position in which the Commission has placed the Company as a result of the approach it adopted to establish a regulatory framework is unacceptable. The Company management and the Board have now deferred all investment decisions in New Zealand pending the outcome of the final decision at which time it will consider its ongoing New Zealand investment strategy.

7. Whilst, in the opinion of the Board, there is a regulatory regime in place that transfers all future benefits from productivity savings and investment gains to consumers and provides no additional (and more likely reduced) benefits to shareholders then future investment opportunities in New Zealand will remain on hold.

8. It is worthy to note that during the past decade, all of the foreign investors have left the sector and it is now entirely New Zealand owned. Many may see that as a positive, but it highlights the issue that international investors perceive the sector as one where all the benefits are transferred to consumers and no benefit is available for shareholders. This situation will have serious consequences on future capital raisings required by the sector to fund growth requirements and embedded generation requirements.

Conclusion

1. It is my view that the proposed regime lacks credibility in the market place. It contains a high level of uncertainty resulting in strong disincentives to future investment.

2. The challenge provided by setting high “X” factors would be regarded as being unobtainable and regarded as a disincentive by the sector rather than an incentive.

3. The management and staff of such companies will be de-motivated and, in the medium/long term, many experienced managers will be lost to the sector. Key managers will view the sector as second rate, being under the control of non- commercial bureaucrats with a regulatory design based on theoretical constructs applied to the real markets. This will further reduce the ability of the sector to achieve the desired productivity savings.

4. Innovation, historically focussed on asset management, will be transferred to the management of the regulatory regime – as greater returns are likely to be achieved with both legal and economic argument.

5. This spiral will escalate into the governance and further perpetuate the capital market issues.

- 7 - TABLE 1. - COMPARISON OF PROPOSED “X” FACTORS

Effect on Operating Cost Reduction & EBIT

CPI = 0.00% 2002 2003 2004 2005 2006 2007 2008 Actual Estimate Year 1 Year 2 Year 3 Year 4 Year 5 X = 0% Line Charge ¢/Kwh 4.94¢ 4.94¢ 4.94¢ 4.94¢ 4.94¢ 4.94¢ 4.94¢ Line Charge $/ICP $740 $740 $740 $740 $740 $740 $740 Transmission $/ICP $165 $165 $165 $165 $165 $165 $165 Operating Costs $/ICP $150 $150 $150 $150 $150 $150 $150 Depreciation $/ICP $109 $109 $109 $109 $109 $109 $109 EBIT $/ICP $316 $316 $316 $316 $316 $316 $316

X = 1% Line Charge ¢/Kwh 4.94¢ 4.94¢ 4.89¢ 4.84¢ 4.79¢ 4.74¢ 4.69¢ Line Charge $/ICP $740 $740 $732 $725 $718 $710 $703 Line Charge Reduction $/ICP $- $- $7 $15 $22 $29 $36 % - - 1% 2% 3% 4% 5% Transmission $/ICP $165 $165 $160 $155 $151 $146 $142 Operating Costs $/ICP $150 $150 $150 $150 $150 $150 $150 Reduction Required $/ICP $- $- $2 $5 $8 $10 $13 % - - 2% 3% 5% 7% 9% Depreciation $/ICP $109 $109 $109 $109 $109 $109 $109 EBIT $/ICP $316 $316 $313 $311 $308 $305 $303 EBIT impact with nil savings % - - 1% 2% 2% 3% 4%

X = 3% Line Charge ¢/Kwh 4.94¢ 4.94¢ 4.79¢ 4.64¢ 4.51¢ 4.37¢ 4.24¢ Line Charge $/ICP $740 $740 $717 $696 $675 $655 $635 Line Charge Reduction $/ICP $- $- $22 $44 $65 $85 $104 % - - 3% 6% 10% 13% 16% Transmission $/ICP $165 $165 $160 $155 $151 $146 $142 Operating Costs $/ICP $150 $150 $150 $150 $150 $150 $150 Reduction Required $/ICP $- $- $17 $34 $50 $66 $81 % - - 12% 23% 34% 44% 54% Depreciation $/ICP $109 $109 $109 $109 $109 $109 $109 EBIT $/ICP $316 $316 $298 $282 $266 $250 $235 EBIT impact with nil savings % - - 5% 11% 16% 21% 26%

X = 5% Line Charge ¢/Kwh 4.94¢ 4.94¢ 4.69¢ 4.46¢ 4.23¢ 4.02¢ 3.82¢ Line Charge $/ICP $740 $740 $703 $667 $634 $602 $572 Line Charge Reduction $/ICP $- $- $37 $72 $105 $137 $167 % - - 5% 11% 17% 23% 29% Transmission $/ICP $165 $165 $160 $155 $151 $146 $142 Operating Costs $/ICP $150 $150 $150 $150 $150 $150 $150 Reduction Required $/ICP $- $- $32 $62 $91 $118 $144 % - - 21% 42% 61% 79% 96% Depreciation $/ICP $109 $109 $109 $109 $109 $109 $109 EBIT $/ICP $316 $316 $284 $253 $225 $197 $172 EBIT impact with nil savings % - - 10% 20% 29% 37% 46%

Note: 1. 2002 data extracted from disclosure accounts. 2. 2003 data estimated based on 2002 data plus CPI. 3. X = 0% is base data assumed if there was no regulatory price path. 4. Transmission charges reflect an "X" factor of 3% in all cases. 5. The change of CPI has no effect on the % saving required on operating costs. 6. The change in CPI does effect the % reduction on EBIT as a result of leaving depreciation as a constant. 7. The change in operating cost and EBIT are mutually exclusive.

- 8 - CHART 1. - POWERCO SHARE PRICE COMPARED TO NZSE40

Share Price Index vs Events

105

100

95

90 Index 85

80

75

70

02/09/2002 09/09/2002 16/09/2002 23/09/2002 30/09/2002 07/10/2002 14/10/2002 21/10/2002 28/10/2002 04/11/2002 11/11/2002 18/11/2002 25/11/2002 02/12/2002 09/12/2002 16/12/2002 23/12/2002 30/12/2002 06/01/2003 13/01/2003 20/01/2003 27/01/2003 03/02/2003 10/02/2003 17/02/2003 24/02/2003 NZSE40 Index Powerco Share Price Index

5 Day Avg Price Key Date Event % Change Change (c/share)

Powerco Announcements 10-Sep-02 Powerco Set to Double Size - Acquisition Agreement (5.8) (3.2)% 11-Oct-02 Powerco achieves strong half year result (0.5) (0.3)% 15-Oct-02 Powerco announces $150 million “Jumbo” share offer 0.2 0.1 % 18-Oct-02 Powerco completes institutional component of "Jumbo" offer (1.3) (0.7)% 29-Oct-02 Powerco shareholders vote in favour of UnitedNetworks purchase and debt funding (7.5) (4.3)% 22-Nov-02 Powerco / Unl Integration Delivers Results - Announcement of entry to NZSE40 0.5 0.3 % 12-Dec-02 Powerco completes retail component of "Jumbo" offer (0.5) (0.3)% 23-Dec-02 Powerco In Gas Investment Discussions With Tasmanian Government - 0.0 % 10-Feb-03 Powerco completes integration of UnitedNetworks assets on time and under forecast 3.5 2.5 %

Commerce Commission / Government Announcements 02-Oct-02 Commission releases discussion paper on Asset Valuation (6.3) (3.5)% 06-Nov-02 Hon Pete Hodgson announces new governance and market arrangements for gas industry (4.5) (2.7)% 23-Dec-02 Commission releases first of two draft decision papers - 0.0 % 31-Jan-03 Commission releases 2nd draft, including decisions on implementation detail (8.0) (5.4)%

Analyst Reports 28-Nov-02 UBSW reduces price target from $1.85 - $1.70 based on potential gas regulation (4.0) (2.4)% 08-Jan-03 CSFB assess PWC as an "underperform" over next 12 mths with price target of $1.45 (3.5) (2.3)% 09-Jan-03 UBSW reduces price target from $1.70 - $1.45 based on 2nd ComCom draft 2.0 1.4 % 03-Feb-03 ABN review ComCom decision paper and value PWC at $1.61 (6.0) (4.1)% 03-Feb-03 UBSW reduces price target from $1.45 to $1.30 based on 2nd ComCom draft (6.0) (4.1)% 04-Feb-03 CSFB assess PWC as an "underperform" over next 12 mths with price target of $1.50 (2.5) (1.7)% 20-Feb-03 UBSW reduces price target from $1.30 - $1.00 based on 2nd ComCom draft na na

- 9 - Evidence of Kerrin Vautier

· Director, Deloitte Touche Tohmatsu (NZ) · Director, Fletcher Building Ltd · Director, Independent News and Media (NZ) Ltd · Senior Lecturer, Dept of Commercial Law, University of Auckland · External Monetary Policy Advisor to the Reserve Bank of New Zealand · Lay Member High Court of New Zealand

Kerrin M Vautier CMG Research Economist

RE: REGULATION OF ELECTRICITY LINES BUSINESSES COMMERCE COMMISSION CONFERENCE ON THE COMMISSION’S DRAFT DECISIONS (23 DECEMBER 2002 AND 31 JANUARY 2003)

10-14 March 2003 ______

At the end of January I was approached by counsel on behalf of Powerco, in my capacity as an expert, and invited to familiarize myself with the Commerce Commission’s evolving approach to the regulation of electricity lines businesses pursuant to Part 4A of the Commerce Act 1986, with a view to preparing a submission to the Commission’s Conference.

I accepted this invitation on the understanding that I was not in a position to commence my analysis until the last week of February and thus I would not be able to prepare a written report for the Commission by the due date of 28 February. As a result, this submission is confined to an outline of what I propose to present at the forthcoming Conference.

That presentation will focus on the following selection of issues:

1) The nature of ‘the problem’ and the regulatory response 2) Efficiency vs competition frameworks 3) Thresholds and incentives 4) Targeted control and outcomes 5) Assessing the risks of regulatory error 6) The ‘long-term benefit of consumers’ requirement

27 February 2003

1 Evidence of Alan Tregilgas

· Member of the Utility Regulators Forum · Ex-officio member of the Australian Competition and Consumer Commission (ACCC) · Current adviser to the Essential Services Commission of South Australia (ESCOSA) · Past adviser to the Queensland Competition Authority (QCA)

Statement of Evidence of Alan Tregilgas

This statement has been prepared in some haste and represents my preliminary views. I reserve the right to expand on and clarify any aspect of my statement.

1. Introduction

Perspective taken

In the time available, I have limited myself to examining the following Commerce Commission (hereafter “Commission”) documents relating to the regulation of electricity lines businesses: § Targeted Control Regime: Draft Decisions, 23 December 2002 (“the Draft Decisions Paper”); § Targeted Control Regime: Implementation Details, Draft Decisions, 31 January 2003 (“the Implementation Paper”); and § Discussion Paper, 31 March 2002.

I have also perused the report prepared by Martin Lally for the Commission, entitled The Weighted Average Cost of Capital for Electricity Lines Businesses, 31 January 2003 (“the Lally Report”).

I offer the attached comments on the above documents on the following basis: § the Australian regulatory experience and practice § the lessons drawn by regulators from Australian experience; and § my views as to evolving regulatory best practice in the Australian context.

I recognise that our experience in Australia does not involve the design of thresholds. Nevertheless, the Commission has recognised the relevance of the Australian regulatory experience, and my evidence concerns that.

My comments focus on the Commission’s draft decisions as they relate only to the price path and excess profit thresholds. I make no comment on the quality threshold proposed.

Nor do my comments relate to the Commission’s associated draft decisions on methodologies for the valuation of electricity lines businesses’ system fixed assets and information disclosure requirements.

My comments are not intended to suggest how the Commission should be doing its job, but instead to: § cast light on the rationale for, and lessons arising from, the evolving Australian regulatory approach; § elaborate on Australian experience with regard to issues and options under consideration by the Commission, and § provide an insider’s interpretation of decisions made by Australian regulators on matters similar to those under consideration by the Commission.

1

I do so as the (part-time) jurisdictional regulator of lines businesses in the Northern Territory, as a member of the Utility Regulators Forum and an ex-officio member of the Australian Competition and Consumer Commission (ACCC), and also as a current adviser to the Essential Services Commission of South Australia (ESCOSA) and a past adviser to the Queensland Competition Authority (QCA) for the purposes of the December 2001 pricing determination applying to that State’s lines businesses.

I am professionally qualified as an economist (I have a Masters degree in Economics). Prior to my current appointment in 1999, I worked as an economist and policy adviser in a number of Treasury Departments (including over 10 years in the Australian Treasury in Canberra) and, more recently, for four years as a Directors of Standard & Poor’s Australia responsible for sovereign and utility credit ratings in the Asia-Pacific region.

My expertise is as a practicing regulator. In this regard, I do not purport to be an expert in relation to either: § the legal interpretation of competition law (whether Australian or NZ law); or § the theoretical or empirical underpinning of WACC estimates.

I am also aware that the Commission has been conducting an extensive process of consultation, which has now reached a final stage with a focus on implementation details. I have not been a party to the earlier stages of consultation and so am not privy to the submissions made and considerations published outside those documented in the above Commission papers.

As the Commission expects to complete its consultation on initial thresholds by the end of March 2003, and intends for the finalised thresholds to have effect from 1 April 2003, the Commission may be interested only in hearing arguments about implementation details rather than high-level design matters. My focus, nevertheless, is on high-level design matters. This focus still appears welcome in view of the questions explicitly posed to interested parties in both the Draft Decisions Paper and the Implementation Paper.

2

2. Price Path Threshold

Draft decision

The Commission proposes a price path threshold of the following form: commencing 1 April 2004, and annually thereafter, any large electricity lines business whose weighted-average price changes at an annual rate exceeding the change in the CPI less an annual rate of X% would breach this threshold.

As stated in the Draft Decisions Paper: “The purpose of the price path threshold is to ensure efficiency gains are shared with consumers and limit the ability of lines businesses to earn excessive profits, while preserving their incentives to pursue profitable efficiency improvements.” (para. 82)

Absence of business-specific P0 adjustments

In the Implementation Paper, the Commission stated that: “ In price control regimes, regulators typically account for differences in cost efficiency and profitability by making P0 adjustments for each of the businesses. The Commission is of the view that it is not appropriate at the thresholds stage of the targeted control regime to make business-specific P0 adjustments.” (para. 9)

In response, my comments are as follows:

What is being proposed is the reverse of the approach taken in Australia, where: § excess profits are eliminated at the commencement of a regulatory period (rather than at the end), by a P0 adjustment; and § each lines business is assessed annually over the regulatory period against the price path threshold set to provide ongoing efficiency incentives.

The price paths are set in Australia so that any excess profit made during a regulatory control period should only arise because of efficiency gains not misuse of market power. By eliminating excess profits initially, so-called excessive profits are allowed to arise (as they must be due to efficiency, not past exploitation of market power).

There is general acceptance in Australia that, if incentive regulation is to be effective, any profit adjustment involved in the application of the building block approach in setting initial tariffs should be separable from – and undertaken prior to – setting of the ongoing parameters of price control formulas. A good deal of caution is required if – as the Commission proposes – a different regulatory sequence is to be followed.

Setting of X

In the Implementation Paper, the Commission stated that it had considered evidence from international experience as well as from New Zealand when making its draft decisions on the X factors. In particular, the Commission noted that: “There appears to be a broad range of decisions on price caps from various regulators. X factors generally range from 1% to 3%. It also appears that, despite the relatively large P0 adjustments, regulated entities have been able to make productivity gains that have allowed them to remain constrained by the price cap and continue to make reasonable returns on investment. … The Commission considers that a minimu m X factor of 1% and maximum X factor of 5% is appropriate for the purpose of the price path threshold as: 3

… § cumulative reductions in prices of up to 22.4% in Victoria Australia, and 42.5% in the UK, have been set for current regulatory periods. These reductions are equivalent to X factors of 5% and 8% respectively and add to real price reductions achieved in previous regulatory periods; and § the Commission is not proposing large initial price reductions that some overseas regulators have required.” (paras. 23,27)

In response to these considerations, my views are as follows:

In theory, Australian regulators start out by separating the setting of P0 from the establishment of X. A P0 adjustment is made to eliminate existing excessive profits. The value of X is then used to provide ongoing efficiency incentives.

In practice, the precise allocation of roles between the P0 adjustment and X has depended on:

§ the extent of any P0 adjustment;

§ the extent to which a lower P0 adjustment is made in exchange for a higher X; and § the extent to which adjustments are made to O&M costs used in applying the building block approach to reflect efficient business costs.

The X factors identified in Victoria and Queensland, for example, reflect these issues as much as ‘efficiency’ or ‘productivity’ considerations per se.

The concern in Australia has often been just as much about: § moderating price shocks initially, where price increases may be warranted following a period of below-cost pricing under government ownership; and/or § offsetting the scope for a price rebound in the context of the price reset at the end of the regulatory period.

X factors drawn from the Australian experience often therefore are only very loosely related to productivity improvements in the utilities sector relative to economy-wide gains.

Uncontrollable costs

In the Draft Decisions Paper, the Commission stated that it: “…does not intend to identify, ex ante, any “pass through” costs in relation to the price path threshold. However, if a lines business were to breach the price path threshold, the Commission would consider any mitigating evidence of significant movements in uncontrollable costs, such as transmission charges (in the case of distribution businesses) and local authority rates.” (para. 27)

In response, my comments are as follows:

This is significantly harsher than the arrangements generally allowed in the Australian context, involving pass-throughs of nominated categories of external and unmanageable cost increases. There is a substantial amount of literature by Australian regulators regarding bases for pass-throughs.

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Meaning of “sharing” of efficiency gains

The Draft Decisions Paper does not document the extent to which the X factors chosen share the benefits of efficiency gains between suppliers and consumers, in line with section 57E(c)).

My comments are as follows:

It is not clear to what extent the proposed X factors would foster such a level of sharing.

In Australia, sharing of efficiency gains has as much to do with the retention of efficiency gains achieved in addition to those factored-in to the price path. In this latter respect, price paths adopted in Australia generally allow for the carryover of certain gains. In some instances, the price paths adopted ensure that a business retains the full benefit of each year’s efficiency gains for a period equal to the length of the regulatory period (five years) (this is the approach in Queensland).

In these respects, I would reiterate the views the Commission expressed in the Discussion Paper that: “The word ‘share’ suggests to the Commission that businesses need not be required to pass on the complete amount of any efficiency gains to consumers. The sharing phrase in the Purpose Statement does not give any explicit guidance concerning appropriate levels of sharing, or over what timeframe sharing should occur. While allowing businesses to retain gains for longer preserve incentives to make efficiency gains, consumers will have to wait before they receive benefits from such gains.” (para 6.29)

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3. Excess Profit Threshold

Draft decision

Of particular interest from the Australian perspective is the Commission’s desire to implement a profits threshold against which each lines business will be assessed in addition and subsequent to a price path threshold against which these businesses will be assessed annually over that period.

A lines business would breach the excess profit threshold if, on a present value basis, its profits earned between 1 April 2003 to 31 March 2008 were to exceed a specified WACC- based rate of return on investment.

The Commission proposes to use a WACC of between 6% and 8% for the profit threshold.

The “Reasons for Excess Profit Threshold” in the Draft Decisions Paper were simply stated – without any further elaboration or justification – as follows: “The Commission considers the excess profit threshold is needed to identify any excess profits that have not been limited, or efficiency gains that have not been adequately shared, through the effect of the price path threshold alone. At this stage, the Commission considers the excess profit threshold may be redundant after 2008, and may be dropped. Excess profits are to be measured over five years because single period profit measures can be volatile. The Commission considers five years to be a reasonable period over which to measure profits, to smooth out the effect of annual volatility.” (paras. 93-95)

Possible overlap in the thresholds

The Commission has argued that: “… it may be in the interests of consumers to strengthen a price path with profit and/or sharing thresholds. Combined, these thresholds would provide a shorter timeframe over which any businesses earning profits in excess of WACC would have to share these with consumers. Where a business makes efficiency gains that take profits in excess of WACC, there sharing threshold would force the business to pass the gain to consumers in the form of lower prices or higher quality ‘n’ years after making the gain. The profit threshold would result in even faster sharing of profits in excess of WACC that were not the result of efficiency gains or risky investments. A price path would achieve these results, but over a longer timeframe. On the other hand, the faster the rate of sharing efficiency gains with consumers, the weaker the incentive for businesses to make efficiency gains. Businesses may perceive there is a risk the Commission would not accept claims of efficiency gains, which must be submitted to justify returns in excess of WACC. The Commission would be open to considering such gains, with the onus being on businesses to prove to the Commission that profits exceeding WACC plus a margin result from efficiency gains and are not simply excess profits.” (Discussion Paper, paras. 8.62-8.63)

In response, my comments are as follows:

First, in the Australian context, an ex post profits threshold would be considered close to adopting a de facto rate of return regulation approach. As the Commission itself acknowledged in the Discussion Paper: “…the purpose of rate-of-return regulation is to eliminate excessive profits by equating the allowable revenues of the regulated entity with its actual costs. However, by eliminating any prospect of future excessive profits, incentives on the regulated business to improve efficiency, by for example reducing

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costs, are removed. Under certain conditions, rate-of-return regulation can also encourage unnecessary and inefficient investment. While rate-of-return regulation may be consistent with section 57E(a), it is less consistent with sections 57E(b) and 57E(c). On balance, the Commission considers that rate-of- return regulation is the least consistent with the Purpose Statement.” (para. 10.11)

Lally may have a point when he suggests that: “The profit threshold proposed by the Commission involves a limited suggestion of a retrospective recouping of excess profits in the event of a price cap being imposed (Commerce Commission, 2002b, paragraph 78).” [footnote 9]

Section 57E(a) requires that businesses be ‘limited’ in their ability to extract excessive profits.

The Australian approach supports the view expressed earlier by the Commission itself in the Discussion Paper (but now apparently downplayed in the draft decisions) that: “… ‘limited’ implies a restriction or reduction, rather than a complete elimination of all excessive profits” (para 6.17) “Given profits are a residual, they may fluctuate significantly from year to year. Accordingly, the Commission considers whether or not a business’s profits are ‘excessive’ needs to be judged over a longer timeframe, such as three to five years.” (para 6.20) “…In calculating WACC, [the Commission] will also be cognisant that: § the process of estimating WACC is not straightforward. …; § the language of the Purpose Statement implies that a profit in any particular time period that exceeds an estimate of WACC may be justified. Subsection 57E(b) refers to ensuring that businesses ‘face strong incentives to improve efficiency’. The prospect of making above-normal profits can motivate businesses to generate efficiency gains. This is consistent with behaviour in competitive markets, where more efficient businesses earn extra profits from their innovations until competitors catch up or new businesses enter the market. Making excessive profits is also consistent with the use of the phrase ‘limited in their ability to’ (so long as excessive profits are justified and limited over time); and § there will be uncertainty surrounding expected returns on all investments made by businesses. The expected return is a combination of different possible returns with various probabilities of occurrence. If regulatory activity adversely affects returns, incentives to make similar investments in the future may be dampened.” (para 6.21)

Section 57E(c) requires suppliers to share the benefits of efficiency gains with consumers, including through lower prices. It is not clear whether the proposed WACC-based profit threshold would foster such a level of sharing of efficiency gains. As the Commission itself acknowledged earlier in the Discussion Paper: “In the Commission’s view, the emphasis on the long-term benefit of consumers in the Purpose Statement weighs the trade-off towards allowing businesses to retain a proportion of any efficiency gains they achieve for a sufficient period. It is important businesses have an incentive to innovate and invest over time sufficient that the long-term benefit of consumers in achieved. If businesses cannot retain a proportion of profits resulting from efficiency gains for a sufficient period, there is a risk they would not make optimal investment and innovations over time, which would not be in the best long-term interests of consumers.” (para. 6.36)

There is a substantial amount of literature by Australian regulators regarding possible bases for the carry-over of efficiency gains in the design of price paths.

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No margin on top of WACC

The Commission proposes to use a WACC of between 6% and 8% for the profit threshold.

In doing so (and without comment), the Commission has dropped the proposal made in its Discussion Paper of basing the excess profit threshold on a margin on top of the WACC.

My comments on this are as follows:

In the Discussion Paper, the Commission suggested that: “…it would be desirable to allow a margin over WACC: § to identify only those businesses with returns that have materially exceeded WACC; § because the estimation of WACC can be imprecise; and § to manage the regulatory cost of assessing efficiency gains by allowing increased profits up to the margin, thereby eliminating the need for the Commission to assess all efficiency gains, many of which may be small, yet complex and costly to assess.” (para. 8.41)

There is no further mention of this approach in the Draft Decisions Paper.

The logic of the Australian approach is that such a margin is necessary to accommodate excess profits arising on account of efficiency improvements exceeding those in the X factor.

A return in excess of WACC may be justified (and not excessive) if it reflects efficiency gains or a return on risky investments.

Without this certainty, the incentive for the pursuit of efficiencies is dampened considerably, notwithstanding the Commission’s indication that the source of any excessive profits will be the primary task of the post-breach investigation. At the very least, there should be an up- front assurance (akin to the Australian practice) that any improvement in profitability over the course of the regulatory period will not be appropriated.

Incentives for prudent investment

The Commission seems to put its faith in non-price mechanisms to ensure prudent investment.

In addition to the price path threshold which the Commission asserts should provide such incentives: “The Commission intends to explore and develop other mechanisms to ensure all lines businesses have strong incentives to make prudent capital investments, including, for example: § enhancing the information disclosure requirements related to asset management planning (such as, by requiring periodic audits of the capital expenditure forecasts contained in those plans); and § scrutinising capital expenditure ex post, as part of any post-breach investigation or declaration of control.” (Draft Decisions Paper, para. 123)

In response, my comments are as follows:

This seems to be akin to the intrusive and costly intervention that the NZ approach seeks to avoid. Such mechanisms are generally avoided wherever possible in the Australian context.

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As the Discussion Paper itself recognised: “…there appears to be general acceptance [in economic literature] that the prospects of higher profits motivates investment and innovation. … In the context of regulation, there can be trade-offs between the three efficiency dimensions [allocative efficiency, productive efficiency and dynamic efficiency]. For example, a certain intervention (e.g. a price cut) may benefit consumers in the short-term. But a price cut may affect the incentives on the regulated firm to invest in innovative technology. If such investments are foregone, the regulation could impose longer-term detriments to consumers. In making judgments about the costs and benefits of an intervention, the Commission will be guided by the specific outcomes to be achieved and the emphasis of the Purpose Statement on the ‘long-term benefit of consumers.’ ” (paras. 6.9-6.10)

In this context, there is growing regulatory recognition in Australia about the (overlooked) importance of incentives for efficient investment being retained, with the consequent productive and dynamic efficiencies such investment engenders.

The Productivity Commission documented the concerns increasingly accepted in Australian regulatory circles that excessive limitation of profits can be at a cost to on-going investment in infrastructure: “…it is important that regulators are not overly ambitious in their attempts to remove monopoly rent. Contrary to the suggestions of some participants, this does not mean endorsement for unfettered monopoly behaviour by service providers. Rather, it means that access regulation must recognise the potential costs of a ‘surgical’ approach to rent removal and encourage regulators to focus on more modest objectives of reducing demonstrably large rents resulting from inefficient pricing or denial of access.” Given that precision is not possible [in regulators’ estimates of efficient costs], access arrangements should encourage regulators to lean more towards facilitating investment than short term consumption of services when setting terms and conditions … …given the asymmetry in the costs of under and over-compensation of facility owners, together with the informational uncertainties facing regulators, there is a strong case in principles to ‘err’ on the side of investors.”

Truncation of returns (and regulatory risk)

The Commission does not propose to incorporate any specific allowance for what it terms “asymmetric risks”. “The Commission has considered whether the WACC threshold should incorporate a specific margin in respect of asymmetric cash flow risks that lines businesses may face. In principle, such risks are not systematic risks and are not incorporated in the standard WACC derived using CAPM. The principal asymmetric risk faced by lines businesses is asset stranding. Lines business assets typically have long lives and many have little alternative uses. Moreover, it is common practice for lines businesses to recover depreciation over periods commensurate with the assets’ long technical lives. However, the Commission considers the risk of asset stranding is not large in this sector… Recent disclosures by lines businesses indicate that economic value write-downs to date have been trivial. …In short, the Commission does not propose to make any specific allowance in the WACC threshold for asset stranding risk. (Implementation Paper, paras. 133-138)

My comments are as follows:

Asymmetric risks may encompass more than just the risk of stranded assets.

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The Productivity Commission has argued as follows, and this is being taken up variously by Australian regulators [ESCOSA re greenfield railways, the ACCC re greenfield gas projects, as well as ESCV]: “The Commission has come to the view that special [regulatory] provisions will be needed if new investment is not to suffer from an inherent regulatory tendency to truncate the up-side potential of an investment, while allowing investors to bear all the downside risks. … The Commission’s recent inquiries have revealed a need to re-balance the emphasis in infrastructure regulation away from achieving immediate gains for users and consumers from existing assets – much of them government owned or previously government owned – to a regulatory framework that will also facilitate efficient investment in new facilities. In this way, pro-competition regulation is more likely to ensure that Australia has modern infrastructure which is developed and used efficiently, with long-term benefits to the Australian community.”

Effectively, either a margin can be added to the WACC or the asset beta can be adjusted to account for such considerations. Several Australian regulators have canvassed these options.

Also of particular note is the Australian Government’s decision – in response to the Productivity Commission’s report – to include the following pricing principles in Part IIIA of the Trade Practices Act 1974: “The Australian Competition and Consumer Commission (ACCC) must have regard to the following principles: (a) that regulated access prices should: (i) be set so as to generate expected revenue for a regulated service or services that is at least sufficient to meet the efficient costs of providing access to the regulated service or services; and (ii) include a return on investment commensurate with the regulatory and commercial risks involved …”

These pricing principles will codify the requirement for: § expected revenue to be at least sufficient to meet efficient costs of providing the regulated services; and § the allowed return on investment is to include allowances for the regulatory as well as commercial risks involved.

These developments have important implications for setting any profits threshold.

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Scope for uncertainty

The Commission is of a view that its proposals involve limiting discretion and therefore increasing certainty. “Another aspect in which thresholds could vary is the degree of discretion [the Commission has] in determining whether a business breaches a threshold. While limited discretion for the Commission would improve certainty for businesses, an overly mechanistic approach could provide perverse incentives… At the other end of the spectrum, whether or not a business breaches a threshold could be left entirely to the Commission’s judgment. While such an approach would allow us to deal with unforeseen circumstances, it would increase uncertainty, which may deer businesses from making efficiency gains or form investing in this sector.” (Discussion Paper, paras. 7.13-7.15)

The Commission notes that: “…the thresholds are intended to provide incentives to companies to modify their behavior so they do not breach the thresholds. Thus, while only a few businesses are likely to be subject to a declaration of control, the threshold regime, and the associated threat of regulation, will affect all large electricity lines businesses.” (para 7.22)

My comments are as follows:

In the context of objective versus subjective thresholds, the Commission importantly acknowledged that: “….uncertainty … may deter businesses from making efficiency gains or from investing in this sector.” (Discussion Paper, para 7.15)

There is a growing literature in Australia on regulatory risks (e.g., the NECG paper, but also ESCOSA).

The uncharted waters represented by the procedures to be adopted once the thresholds are breached – and the lack of objectivity likely to apply in the investigation process – are genuine sources of regulatory risk. Such risk will only be minimised if: § thresholds are set at levels that ensure the breach of such thresholds will be the exception rather than the rule; and § certainty exists regarding the tests to be applied in the investigation stage.

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Evidence of UMS Group

Utility Benchmarking Consultancy

The UMS Group’s submission, which has been jointly commissioned by Powerco will be submitted by UMS in their own right. Evidence of Steven Boulton

· Chief Executive, Powerco Limited

Evidence of Steven Boulton (Chief Executive, Powerco Limited) in response to Commerce Commission draft decisions of 23 December 2002 and 31 January

Introduction 1. This document addresses the following issues:

(a) the proposed regime is detrimental to investment;

(b) the proposed regime is detrimental to improving productivity and reducing waste and expenses;

(c) the proposed regime is less certain and will increase cost of capital; and

(d) the differences between electricity distributors is substantial such that an “apples to apples” comparison is not possible using a simplistic measure – a more advanced approach will be needed.

Detrimental to investment 2. The proposed regime will be detrimental to investment in a sector that is deemed by the general public as an essential infrastructure – a part of life. This is because investment in Powerco’s electricity distribution network and re-investment in its existing network (e.g., refurbishment or upgrade of part of its network) requires Powerco to commit investors’ funds. Given Powerco’s actual cost of capital is higher than the upper limit of the Commission’s (theoretically) proposed WACC range (i.e., 8%), additions to Powerco’s network and re-investment in its existing network will not proceed or will be delayed or scaled back (as the return on the investment or re-investment is less than Powerco’s cost of capital). This will be the case, notwithstanding that it does not automatically follow that if Powerco breaches the Commission’s proposed thresholds it will be subject to a declaration of control. Powerco (and its providers of capital) cannot assume that it will prevail in any investigation by the Commission (and therefore not be subjected to control) if its rate of return is at least equal to its “real” cost of capital

3. As the supply of gas from Maui runs out and/or “dry years” occur the proposed regime will exacerbate the “generation gap”. This is because, Powerco (whose footprint is suited to wind power) will not invest in the additions and improvements to its network to connect embedded generation, as the return on Powerco’s investment is less than its cost of capital. Similarly, Powerco will not itself (or as a joint venture partner) invest in renewable generation unless the regime guarantees that the profits from this will not be regulated or counted for the purpose of assessing whether Powerco is earning “excessive profits”.

4. The proposed regime will increase the set up costs of new (or expanding) industrial consumers (e.g., a foundry) and therefore deter new industrial consumers from setting up or existing industrial consumers from expanding. For the reasons set out above, Powerco will not be investing, consequently, the consumer will have to construct and maintain the works necessary to connect to Powerco’s network. The consumer’s cost of capital is higher than Powerco’s. As a result, what was a commercially viable project may no longer be and therefore will not proceed. This outcome would obviously negate the Government’s focus on growth and national economic development.

Detrimental to improving productivity and reducing waste and expenses 5. First, only approximately 20% of Powerco’s revenue could be categorized as controllable costs. Therefore, to achieve a 5% reduction in Powerco’s weighted average price (assuming CPI = 0) means that Powerco needs to reduce its controllable costs by a substantial amount each year (unless its providers of capital are prepared to accept lower returns). Over 5 years this equates to a very substantial reduction in Powerco’s controllable costs. Such a reduction is virtually impossible to achieve and therefore de-motivates management and staff - as opposed to incentivising management to improve productivity and reduce waste and expenses as a manageable and achievable task.

6. Secondly, as the Commission’s proposed profit threshold does not expressly provide for Powerco to keep the upside profits from efficiency gains, there is no incentive for management to improve productivity and reduce waste and expenses.

7. Under the Commission’s proposed regime, efficient ELB's who are not making monopoly rents (but whose returns equal their cost of capital), will breach the profit threshold if they make further efficiency gains. This is because the Commission’s proposed WACC range (i.e., 6 – 8%) is significantly lower than ELB’s cost of capital and the Commission has taken too narrow an asset base.

Less certainty will increase cost of capital 8. The proposed regime is a far less certain environment than the current light handed regime or the CPI-X price control regime in force in the UK or Australia. This is because the proposed regime contains an ex post profit threshold on an artificially low WACC. There is no guarantee that companies who breach this threshold will not suffer retrospective claw backs of their profits. There is no way in which legitimately earned profits due to efficiency can be distinguished from "excessive profits" and no mechanism by which the providers of capital can be reassured that they will receive their expected return.

9. The cost of capital in the Commission's proposed threshold regime will be higher than it has been under the current light handed regime and higher than it is in overseas CPI-X regimes. It is a debateable point whether this should be reflected in the asset beta or is simply the result of constraining firms' profits to a WACC derived through the capital asset pricing model but it is already proving to be a major concern to the lenders of both debt and equity to Powerco and must be reflected in any profit threshold. The ex post profit threshold should be dropped altogether since it is the cause of the uncertainty which has this effect on financing costs.

10. The Commission’s proposed WACC is the mid-point of distribution of company WACC’s – with large variation in actual WACC’s. The Commission's profit threshold will be treated as a “control” by lines businesses who will seek to avoid breaching it just as the Commission has indicated it expects them to. In so doing the threshold prevents any companies from exceeding the midpoint of the distribution. This midpoint is in effect the cap.

11. The Commission has suggested (Paragraph 77 of the January Decision paper) that the quality threshold would be breached if companies show a statistically significant deviation from a predetermined limit and that statistical significance would be assessed using a one-sided test with a type 1 error probability 5 of 10%, based on a statistically adequate model. Any threshold should be of this form - something at the upper range of the distribution which only catches outliers - not something that by definition will catch 50% of companies.

12. The Commission has not specified any foundation principles or criteria for the investment community to understand the possible impact if a company breaches any threshold. Investors would be seeking confidence about the likelihood, or otherwise, of a successful case put forward by company management to the Commission following a breach. The only “principle” espoused by the Commission thus far has been that “customers expect continued improvement in quality” No detail regarding the principle has been provided. The principle is by itself asymmetric in nature and does not follow any normal distribution – variation around a central point which may reflect the concept of sharing. Based on the analysis of the draft Commission paper the shareholders also seem to have an asymmetric profile – they carry all the downside risk and receive no upside – a breach in itself of the “sharing” concept.

Differences between electricity distributors is substantial- eg Infrastructure, Demographic Variables & Electrical Characteristics Affecting Asset Investment, Costs and Prices for Electricity Distribution Businesses

1. There are many factors that influence the level of investment required in network assets and the operating costs associated with providing and maintaining supply to a given customer or consumer base. Even if the amount of infrastructure investment and the level of operating costs for a given distribution business were such that the business was operating at optimal efficiency, the combined costs and therefore efficient prices of that company may be significantly different to that of a similar company but operating across a different geographical region with or without a different mix of consumer types and locations.

2. In larger markets, such as those that exist in the UK, USA and parts of Australia distribution companies typically operate over larger geographic areas such that the diversity of terrain, customer types etc. evens out and overall the effects of the various factors tends to be nullified. In overseas in some cases there are at least enough similar type companies to be banded together for comparison purposes. Alternatively each company is treated differently by the regulator and allowances are made for the various differentials

3. In New Zealand there is a wide range of these variables due mainly to the fact that the geographic terrain varies widely over a comparatively small land area and the settlement varies with over 50% of the population confined to four main centres.

4. With a large number of electricity distribution businesses serving a relatively small land area and customer base there is much more diversity in the costs influencing factors than is typically found overseas. The regulatory regime needs to take these factors into consideration and if absolute representations of costs, prices, reliability etc are to be used a normalisation correction needs to be made in order to make comparisons on a level playing field.

5. This issue is of particular concern to Powerco since, although Powerco is now the second largest electricity line company it is essentially a provincial operator. This has been exacerbated following the recent split up of UNL, where Vector purchased the high-density urban network areas and Powerco and Hawkes Bay inherited the provincial and rural lower density areas.

Consumer Density

1. The consumer density (number of consumers per kilometre of line) influences the level of investment required in assets to supply those consumers and also affects the operational costs. Higher density areas can be supplied at a lower operating cost per consumer, as although higher capacity assets are required in higher density areas the utilisation of those assets is higher due to the greater load diversity. The operational (direct) costs per consumer is also higher in less dense areas due to the longer distances to be covered and the numbers of operation personnel required to cover the larger geographic areas.

2. The indirect (administrative) type average costs also tend to be higher since these are quite lumpy in nature (e.g. the annual cost to operate a call centre to service 250,000 consumers would be only marginally higher than one to serve 50,000 consumers, so the cost per consumer for the latter would be almost five times).

3. The reliability indices relating to duration and frequency should also be lower in the higher density areas. This is due firstly to the smaller distances to cover and therefore shorter restoration times. Also high-density areas tend to have more sources of alternative supply as opposed to the radial nature of lower density areas. This means that that both the number of faults and the outage times are inherently lower in high-density areas. It also means that the average investment and operating cost to provide lower density areas with a similar quality of supply is much higher. 4. Regulatory regimes need to take these factors into account and in particular the more significant price v quality trade-off proposition for consumers in the lightly loaded rural and semi-urban networks of provincial operators.

5. Powerco although second in size is 12th in terms of consumer density due to the provincial nature of its customer base and geographic location.

Customer Density 2002

40.0 35.0 30.0 25.0 20.0 15.0 10.0 5.0 - Consumers per System Length km

Company

Load Density

1. The load density (energy consumption kWh per consumer) constrains the investment efficiency since the cost to provide network capacity is largely driven by the maximum demand on the network not the energy flowing through it. Networks servicing low load density consumers have lower load factors i.e. for a given volume of energy (kWh) there is a higher maximum demand (kW) to supply requiring relatively more average asset investment.

2. An additional problem for provincial companies under price regulation can occur when the regulator sets a price path. Provincial companies are at a relative disadvantage to those with higher load densities where growth benefit is available. This is because supply costs are either fixed or dependant on capacity (kW or kVA) and revenues have a higher correlation with volume (kWh) due to the repackaging of costs in the line pricing methodology.

3. Powerco is 25th in the ranking of load density due to the rural nature of many of its provincial supply areas.

Load Density 2002

30,000 25,000 20,000 15,000 10,000 kWh per ICP 5,000 -

Company

Capital Efficiency

1. Asset capital investment can be measures either by asset value per line length or per consumer served. The per km measure is not very suitable for making comparisons since the high density networks will tend to higher investment value in lower length networks and so appear to be less efficient. Using number of consumers as the denominator levels the comparison, as lower density networks would expect to have inherently lower capital efficiency. The more efficient companies are those with lower capital invested per consumer.

Enterprise Service Cost

1. If input costs are to be used to determine factors in a regulatory regime, such as that proposed by the Commission in determining the X-factor bands, it is not sufficient to consider operating costs alone. There is an interdependency between the costs associated with asset capital investment and operating costs. Businesses that under-invest in capital would tend to have higher operating costs if they were to provide similar levels of service and quality. Conversely some companies may over invest in assets with lower operating costs. The most efficient businesses will tend towards an optimum combination of capital investment and operating costs.

2. In order to gauge the relative position of lines businesses in regard to enterprise service costs one can assume an average asset life (say 50 years) with a consistent replacement equating to 2% of the ODV value per annum. This added to the annual total operating cost per consumer gives a reasonable proxy for enterprise service cost.

Total Cost per Consumer - 2002

500 450 400 350 300 250 200 150 100 50

Total cost per Consumer $/ICP - Vector Powerco Westpower Top Energy Scanpower Centralines Northpower Otago Power Alpine Energy WEL Networks Buller Electricity Counties Power Network Waitaki Waipa Networks United Networks Nelson Electricity Network Tasman Eastland Network Dunedin Electricity Marlborough Lines Orion New Zealand Electricity Ashburton Horowhenua Energy The Lines Company Electricity Invercargill The Power Company Hawkes Bay Network MainPower New Zealand Horizon Energy Distribution