Application by Ergon Energy Corporation Limited

(Customer Service Costs) (No 2) [2010] ACompT 10


Application by Ergon Energy Corporation Limited (Customer Service Costs) (No 2) [2010] ACompT 10

Review from:

Australian Energy Regulator



(ACN 087 646 062)

File number:

3 of 2010




Date of delivery of reasons:

24 December 2010

Date of hearing:

15, 16, 17, 19 and 22 November 2010




No catchwords

Number of paragraphs:


Counsel for Ergon Energy Corporation Limited:

Mr P O’Shea SC with Mr Bradley

Solicitor for Ergon Energy Corporation Limited:

Minter Ellison Lawyers

Counsel for Australian Energy Regulator:

Mr P Hanks QC with Mr Gray, Mr T Clarke and

Mr L Merrick

Solicitor for Australian Energy Regulator:

Corrs Chambers Westgarth


FILE NO 3 of 2010





(ACN 087 646 062)





24 DECEMBER 2010





1    These reasons deal with customer service costs. The expressions employed in these reasons are the same as employed in earlier decisions the subject of the current review.

2    The issue before the Tribunal is whether the AER’s decision not to accept Ergon Energy’s forecast customer service costs allocated to standard control services involved a ground of review in terms of s 71C of the NEL.


3    Ergon Energy incurs operating expenditure (‘opex’) on a variety of activities for its customers that is ancillary to the provision of Ergon Energy's broader network, connection and metering services (‘customer service costs’).

4    Customer service costs include:

    cold water report (where Ergon Energy rather than the customer is at fault);

    check inspections (except where Ergon Energy needs to do a re-test);

    revenue protection;

    customer support;

    managing compliance with electrical safety legislation; and

    customer advisory services.

5    Customer service costs specifically excludes retail and call centre activities, which are treated as overheads.

6    Some of Ergon Energy’s customer service costs are classified by the AER as standard control services (‘SCS’) and some as alternative control services (‘ACS’). Other services are classified as unregulated.

7    In its regulatory proposal for the 2010-15 regulatory control period (‘Proposal’), Ergon Energy was required to provide a building block proposal, which included the total forecast opex for the regulatory control period which it considered was required in order to achieve the opex objectives (cl 6.5.6(a) of the Rules), namely:

(a)    to meet or manage the expected demand for SCS over that period;

(b)    to comply with all applicable regulatory obligations or requirements associated with the provision of SCS;

(c)    to maintain the quality, reliability and security of supply of SCS; and

(d)    to maintain the reliability, safety and security of the distribution system through the supply of SCS.

8    Clause 6.5.6(b) of the Rules requires that a DNSP’s forecast for operating expenditure “be for expenditure that is properly allocated to standard control services in accordance with the principles and policies set out in the Cost Allocation Method for the Distribution Network Service Provider”.

9    In the Cost Allocation Method (‘CAM’), Ergon Energy’s costs are allocated between the distribution service categories: SCS, ACS and unregulated activities. This is done on the basis of account codes for the “Activities” in the Ergon Energy Group's Chart of Accounts.

10    Clause 6.5.6(c) of the Rules sets out the opex expenditure criteria and states:

The AER must accept the forecast of required operating expenditure of a Distribution Network Service Provider that is included in a building block proposal if the AER is satisfied that the total of the forecast operating expenditure for the regulatory control period reasonably reflects:

(1)    the efficient costs of achieving the operating expenditure objectives; and

(2)    the costs that a prudent operator in the circumstances of the relevant Distribution Network Service Provider would require to achieve the operating expenditure objectives; and

(3)    a realistic expectation of the demand forecast and cost inputs required to achieve the operating expenditure objectives.

11    Clause 6.5.6(d) of the Rules identifies when the AER must not accept a DNSP’s opex forecast. The clause states:

If the AER is not satisfied as referred to in paragraph (c), it must not accept the forecast of required operating expenditure of a Distribution Network Service Provider that is included in a building block proposal.

12    Under cl 6.5.6(e) of the Rules, in deciding whether to accept a DNSP’s opex forecast for a regulatory control period, the AER is required to have regard to the following opex factors:

(a)    the information included in or accompanying the building block proposal;

(b)    submissions received in the course of consulting on the building block proposal;

(c)    analysis undertaken by or for the AER and published before the distribution determination is made in its final form;

(d)    benchmark operating expenditure that would be incurred by an efficient Distribution Network Service Provider over the regulatory control period;

(e)    the DNSP’s actual and expected operating expenditure during preceding regulatory control periods;

(f)    the relative prices of operating and capital inputs;

(g)    the substitution possibilities between operating and capital expenditure;

(h)    whether the total labour costs included in the capital and operating expenditure forecasts for the regulatory control period are consistent with the incentives provided by the applicable service target performance incentive scheme in respect of the regulatory control period;

(i)    the extent the forecast of required operating expenditure of the Distribution Network Service Provider is referable to arrangements with a person other than the provider that, in the opinion of the AER, do not reflect arm’s length terms;

(j)    the extent the Distribution Network Service Provider has considered, and made provision for, efficient non-network alternatives.

Ergon Energy’s Regulatory Proposal and AER consideration

13    In the Proposal, Ergon Energy forecast the following for its SCS Customer Service opex for the next regulatory period in millions of dollars, including overheads and escalation, stated in real 2009-10 dollar values:






5 year total

Average of 5 year total








14    A diagram and accompanying text in the Proposal indicate that the figures in the Proposal were forecast in the Finance budget using 2007-08 expenditure as a base, removing any abnormalities, and identifying scope changes and work load growth. In the Proposal, Ergon Energy also referred to document AR272c, stating that it “was used to inform the Finance budget forecasts”.

15    AR272c was an internal Ergon Energy document. Table 6 of AR272c contained the following figures for “Customer Care Forecast by Activity”, separated into SCS and ACS ($m):









SCS Total









ACS Total









16    Shortly after submitting the Proposal, Ergon Energy submitted spreadsheet PL561c. In the Standard Control Operating Costs in “Rin Format” tab of PL561c, the following projections were recorded for Meter Reading and Customer Services:








Meter Reading








Customer Services








17    The AER engaged Parsons Brinckerhoff Australia Pty Limited (‘PB’) to provide an independent view on the prudence and efficiency of Ergon Energy's proposed expenditures in the Proposal and to review the service standards proposed to be delivered for those expenditures.

18    PB sent the following question (PB.ERG.VP.94) to Ergon Energy regarding its customer services opex:

Can Ergon Energy please clarify how the unregulated and alternative control services associated with the customer services (including metering) cost categories have been handled, specifically can Ergon Energy please reconcile the $10.56m SCS direct costs for these two areas in 2010/11 of Table 6 of AR272c with the summated figure of $20.45m from cells D12:D13 in the 'RIN format' tab of spreadsheet PL561c?

19    On 9 September 2009, Ergon Energy replied:

Ergon Energy advises that the document AR272c was provided as background information not as a source document for the forecasts.

In preparing its Regulatory Proposal, Ergon Energy endeavoured wherever possible to make use of data that was available as part of its everyday operations i.e. "business as usual". In adopting this approach Ergon undertook several exercises to ensure that "business as usual" data was not significantly different to forecasts prepared from a bottom-up approach (i.e. a 'sanity-checking' exercise). The AR272c document was the result of one of these exercises. Ergon Energy looked at the variation at the bottom line only, and did not consider the breakdown into service classification, choosing to use the forecast and breakdown from the budget forecast instead.

Ergon Energy urges caution in assuming that all of the detail in AR272c is completely accurate. Ergon Energy can warrant that the analysis in AR272c is reasonable in reaching the AER forecast in Table 8 and for reviewing the business-as-usual process for budget forecasts, but not the underlying detail when it comes to allocating the costs to Standard and Alternative Control Services. This is because the allocation is subjective.

As an example, in Appendix A of AR272c there are three standard job tasks listed:

QCEMRB Meter Reading – CustMeter Read;

QNOMRB Meter Reading – CustMeter Read; and

QSOMRB Meter Reading – CustMeter Read.

Examination of these activity [sic] reveals that the first two, QCEMRB and QNOMRB, have been classified as Alternative Control Services (ACS) and QSOMRB has been classified as Standard Control Services (SCS).

All three should be classified as SCS, which if they were, would result in the following shift in costs from ACS to SCS with no change in the aggregate amount.

        SCS        ACS        Total

Table 6        10.56        13.68        24.24    

Reviewed    14.49        9.74        24.23

        3.93        -3.94

Please come back to us if you require anything further on this topic.

20    In about October 2009, PB prepared a report on the Proposal for the AER (‘PB 2009’).

21    PB 2009 stated that the difference between the costs sourced from AR272c and those in PL561c strongly suggested that Ergon Energy had included a proportion of its ACS or unregulated activities in its forecast allowance for SCS.

AER draft decision

22    On or about 25 November 2009, the AER made a draft distribution determination in relation to Ergon Energy and Energex Limited (Draft Determination) in accordance with s 6.10.1 of the Rules.

23    In the Draft Determination, the AER endorsed the analysis in PB 2009:

PB found that there was an overlap of key activities of standard and alternative control services in relation to metering and customer care activities.

The AER has not been able to verify that alternative control service costs have not been incorporated into Ergon Energy's modelling of other operating costs for standard control services. Accordingly, the AER considers that the metering and customer care opex forecast should be amended to remove alternative control services costs.

24    In Appendix J to the Draft Determination, the AER expressed its view in this way:

The AER reviewed Ergon Energy's forecast of its metering and customer services opex. The AER followed up on PB's concern that … there was a double count of meter reading and customer care costs in its opex forecast. PB stated that this had also been accounted for as part of Ergon Energy's alternative control services costs.

Ergon Energy was asked to clarify the forecast with reference to source material, but was unable to satisfactorily demonstrate that the opex forecast did not include any alternative control services costs for metering and customer service opex.

The AER has not been able to verify that alternative control service costs have not been incorporated into Ergon Energy's modelling of standard control services opex. Accordingly, the AER considers that the opex forecast should be amended to remove the alternative control services costs identified by PB.

25    In the Draft Determination the AER made an adjustment of $50 million to Ergon Energy's Customer Service opex for the next regulatory period to “remove the double count of alternative control services and unregulated services (customer service component) costs”.

Ergon Energy’s Revised Regulatory Proposal and AER consideration

26    In a report for Ergon Energy, Huegin Consulting Group reviewed the documentation and concluded that “there is a lack of compelling evidence that Alternative Control Services have been included in Ergon Energy's forecast and that the inability to prove that they haven’t been included is not a reasonable justification for rejecting Ergon Energy’s forecast.”

27    On or about 14 January 2010, Ergon Energy submitted a revised regulatory proposal to the AER (‘Revised Regulatory Proposal’).

28    In the Revised Regulatory Proposal, Ergon Energy referred to the information it supplied to the AER in the email dated 9 September 2009 and noted:

Ergon Energy advised the AER that whilst the total Customer Services and Meter Reading operating expenditure forecast presented in Document AR272c was used to verify the budget forecasts, the subtotals for the Alternative and Standard Control Services allocation in the same document were immaterial.

The actual forecast model Document PL561c used in the June 2009 Regulatory Proposal correctly removes Alternative Control Services from the forecast figures in accordance with Ergon Energy's Cost Allocation Method approved by the AER.

29    On 9 February 2010, PB sought clarification from Ergon Energy regarding the reconciliation of AR272c with PL561c:

Can Ergon Energy provide an addendum to Document AR272c correcting and clarifying the presentation and division of expenditures and activities between Standard and Alternative Control Services? PB notes that even with the transfer of activities QCEMRB and QNOMRB to SCS – this still leaves a discrepancy of approximately $36m in the comparison of aggregate direct costs (i.e. $104m from PL561c minus 5 x $13.7m).

30    On 1 March 2010, Ergon Energy replied to this question:

Ergon Energy does not expect the total direct costs in PL561c and AR272c to reconcile exactly due to:

(a)    The assumptions in AR272c regarding the mapping of historical expenditure categories to the recently introduced Standard and Alternative Control Services Classification categories;

(b)    Differences in the effect of Shared Costs (Overheads) between the two documents – with AR272c assuming a nominal historical Shared Costs (Overheads) rate and PL561c utilising the forecast Shared Costs (Overheads) rate in accordance with the Cost Allocation Methodology; and

(c)    Differences in dollar years (AR272c figures in $2007-08 nominal, PL561c figures are in $2009-10 real).

Further the $36m “discrepancy” referred to in PB.ERG.RRP.01 is a result of multiplying one year of the AR272c forecast by five [excerpt from question: "this still leaves a discrepancy of approximately $36m in the comparison of aggregate direct costs (i.e. $104m from PL561c minus 5 x $13.7m)"] – this does not account for the escalation of costs inherent in the Ergon Energy forecast that addresses anticipated customer churn, GSL breaches, etc.

Notwithstanding, Ergon Energy accepts that the division of expenditures in AR272c contained errors in the categorisation of costs as either Standard or Alternative Control Services. Ergon Energy provided examples of two major classification errors (Standard Control Services meter reading activities QCEMRB and QNOMRB). Ergon Energy has since identified a number of other activities that should have been included in Standard Control Services, specifically Q1011, elements of Q212, Q216, Q311 and Q512.

31    Ergon Energy stated that correction of these errors would have resulted in an adjustment to the “SCS Total” line of Table 6 in AR272c for the years 2010-11 to 2014-15 of $87,143,302 in 2009/10 dollars and that:

The remaining difference between this figure and the $104m of direct costs in PL561c is (in Ergon Energy's opinion) insignificant enough to be considered as being within the inherent range of error related to comparison of historical data with forecast data, where the classification of services for the forecast data has been retrospectively applied to historical data recorded using a different classification scheme. This error is compounded by the fact that historical data includes activities and tasks that in several instances have recorded costs which include an element of both classifications (Standard and Alternative) with no means of allocation to the respective service classification category. Ergon Energy also reiterates that the figures in AR272c were utilised as a check of reasonableness of the actual forecast (PL561c) with the understanding that the errors described above were inherent in the assumptions made in AR272c.

Ergon Energy draws further confidence of the validity of the customer service and meter reading forecast costs provided in the Revised Regulatory Proposal from:

a.    The fact that the forecast meter reading expenditure lies within the reasonable range when compared to the NSW DNSP meter reading costs as published in the NSW determination;

b.    The fact that the forecast customer services expenditure lies within the reasonable range when compared to the NSW DNSP customer service costs as published in the NSW determination; and

c.    The fact that the split of Standard and Alternative Control Services costs in PL561c is more reflective of the actual work effort in those two respective service areas.

32    On 22 April 2010, Ergon Energy sent an email to the AER seeking clarification as to the ‘double count’ of ACS referred to in the Draft Determination:

In the adjustments for Standard Control Services – Customer Services it states “Remove double count of Alternative Control Services – customer service [sic] component only” and “reduce the customer services opex forecast by 32.6% (that is, to $68.3M).     

Is it a case of a “double count” or an incorrect split of the forecast between SCS and ACS?

33    On the same day, the AER sent an email to Ergon Energy stating that “we see it as a case of ‘double count’”.

34    On 23 April 2010 (two weeks prior to the AER publishing its final determination and decision), Ergon Energy emailed the AER “seeking clarification … in relation to the AER's comment that Ergon Energy has double-counted Alternative Control Services costs for Customer Services”.

Ergon Energy is concerned that the AER's position on double counting is a result of PB's inability to reconcile AR272c and PL561c. However, has [sic] stated in our responses to the AER and their consultants, AR272c was provided as background information only and was not used to prepare the forecasts. Further, Ergon Energy does not expect the two documents to reconcile for the reasons provided in our response to PB.ERG.RRP.01.

For the removal of doubt – Ergon Energy prepared its Customer Service forecast based on its budget costs of delivering Customer Service activities that are both Standard Control Service and Alternative Control Service activities. In total, as per Ergon Energy's Revised Regulatory Proposal, Ergon Energy's proposed forecast is $144.84 M ($2009-10). Then Ergon Energy 'split' the activities between SCS and ACS. Only the SCS costs have been forecast in the SCS category of Customer Service – forecast to be $101.79 M ($2009-10). Only the ACS costs have been forecast in the ACS category of Fee-Based and Quoted Services – forecast to be $43.05 M ($2009-10). When added together, they amount to the total starting budget of $144.84 M ($2009-10).

35    The AER responded to Ergon Energy’s email of 23 April 2010 on 29 April 2010. In its response, the AER stated:

We have previously reviewed all of the information provided in your email and in response to your email we have reviewed the material again.

The AER’s reasoning in relation to its conclusion on customer services will be set out in our decision.

36    PB prepared a further report for the AER (‘PB 2010’).

37    PB 2010 stated:

PB's key recommendation to the AER as part of its original review was informed by the significant difference between the direct costs input into Ergon Energy's forecast model PL561c of $104.1m (07/08 real) and the Standard Control Service (SCS) costs in AR272c of $52.9m (07/08 real).

38    PB 2010 stated that PB was satisfied as to Ergon Energy's proposed corrections, transferring forecast costs from ACS to SCS in seven categories. This then meant that 79.6% ($82.9 million of $104.1 million) of the expenditure was supported by the corrected AR272c, in contrast to the 50.8% that was supported prior to the corrections.

39    PB 2010 also noted that “given the nature of meter reading activities and the likely accuracy of historical costs in this category, it is likely that significant ACS has not been included in the meter reading category.” PB concluded that “based on the historical and forecast trending data, plus the comparative benchmarking information included within Ergon Energy’s revised proposal, it is likely that Ergon Energy’s overstatement of direct costs is attributed to the customer services category rather than the meter reading category, and therefore recommends that its revised adjustment is applicable to this category only.”

40    PB also responded to various contentions by Ergon Energy that it is unnecessary to set out. The AER followed up by seeking further clarification and confirmation of PB’s conclusions. PB responded in some detail.

41    There was a late exchange of emails between Ergon Energy and the AER (some eight weeks after Ergon Energy’s 1 March 2010 response to PB). This exchange adds nothing significant to earlier correspondence.

AER Final Determination

42    On or about 6 May 2010, the AER made its distribution determination in respect of Ergon Energy and Energex Limited (‘Final Determination’), and issued its final decision in respect of the Proposal, the Revised Regulatory Proposal and the regulatory proposals by Energex for the regulatory control period.

43    In the final decision, the AER adopted the $33 million reduction that had been recommended by PB in PB 2010, making the following observations:

(a)    The opex forecasts provided by Ergon Energy must be unambiguously related to either SCS or ACS. The information provided by Ergon Energy in the Proposal was not unambiguous.

(b)    Ergon Energy stated that AR272c informed its budget forecasts, yet the forecast for Standard Control Metering and Customer Service Opex was approximately 50% less than that shown in the opex forecasts. This led to the AER's adjustment in the draft determination.

(c)    Ergon Energy claimed that sources of error in the information relied on by the AER derive from non-comparable dollar terms, the impact of shared costs (overheads) and service classification not being undertaken in accordance with the approved CAM. PL561c was in 2007-08 dollars and did not include overheads. Ergon Energy indicated that AR272c was in 2007-08 nominal terms and it was stated in AR272c that some overheads were excluded. The AER interpreted $2007-08 nominal terms to mean $2007-08 real. Therefore, PB's assumption that AR272c excluded overheads and was in 2007-08 terms was reasonable and conservative.

(d)    Ergon Energy corrected the 'modelling errors' to remove the alternative control meter reading costs from the proposed standard control opex forecast. On this basis, the AER was satisfied that Ergon Energy's revised forecast in relation to metering costs did not include any costs related to ACS.

(e)    With respect to Customer Service Costs, there was still some ambiguity about the costs that should be attributed to SCS. Ergon Energy corrected the allocation of seven specific activities and justified its inability to further reconcile differences between the opex forecast model in PL561c and AR272c on the basis of non-comparable dollar terms, the impact of shared costs (overheads) and service classification not being undertaken in accordance with the approved CAM.

(f)    The remaining difference of approximately $21 million was not insignificant and should be able to be explained. Ergon Energy's inability to explain this difference meant that the AER did not consider that Ergon Energy's claim that the opex forecast only incorporated SCS had been substantiated.

(g)    Document AR272c was not developed for regulatory purposes and, accordingly, an exact reconciliation between AR272c and PL561c may not be possible. However, because AR272c was used to inform Ergon Energy's opex forecasts, the AER considered that Ergon Energy should have reconciled the data to a greater extent than it in fact did. Consequently, Ergon Energy had not sufficiently demonstrated that its forecast Customer Service opex solely related to SCS.

(h)    PB's recommended reduction of 20% (amounting to $33 million) in the context of Ergon Energy's Customer Services opex forecasts should be adopted on the basis that only 80% of the direct costs were clearly supported by the information supplied by Ergon Energy. The reduction would ensure that any ACS costs that were included in the opex forecast would be excluded from the SCS opex allowance.

Grounds for review

44    Ergon Energy alleged that the AER had made an error of fact in its Final Determination in that there was no ambiguity: the correct figures were those in document PL561c and the Proposal, which were in accordance with the CAM. The figures in document AR272c were not a forecast on which Ergon Energy’s forecast customer service opex was based.

45    Effectively, Ergon Energy argued that because of its admitted flawed allocation of expenditure between SCS and ACS, AR272c should have been ignored by the AER. It said that a reconciliation between the two documents was not reasonably possible because it would have required a manual examination of up to 12,348 individual jobs allocated to job codes, with decisions being needed about classification as SCS or ACS.

46    Ergon Energy also alleged error in the exercise of the AER’s discretion in refusing to accept Ergon Energy’s forecasts, and unreasonableness in that decision. However, the Tribunal considers that no additional matters for consideration come into play by consideration of those additional grounds. The essential issue is whether the AER misinterpreted material provided to it by Ergon Energy and made errors of fact in reaching its conclusions.

Tribunal consideration

47    It became apparent during the hearing that there was a fundamental disagreement between Ergon Energy and the AER over the use that could be made of the document AR272c. Ergon Energy sought to walk away from that document, at least insofar as it could be used to reach any conclusions about the forecast for customer service opex in its Proposal and Revised Regulatory Proposal.

48    The AER considered that, the document having been provided to it, the implications of the discrepancies between that document and the forecasts needed to be explored. That can hardly be disputed. The question is whether, after a thorough investigation, the AER should have decided that AR272c provided no basis for refusing to accept Ergon Energy’s forecasts.

49    The Tribunal has concluded that the AER was correct in its ultimate assessment of the use it could make of the document, and that its Final Determination does not reveal error.

50    While aspects of the relationship between the documents remain murky, the AER’s process of assessment is quite clear.

51    Ergon Energy relied on Waterways Authority v Fitzgibbon (2005) 221 ALR 402 at 429 (Hayne J) and the Tribunal’s reasoning in Application by EnergyAustralia [2009] AComptT 7 at [16]. Ergon Energy contended that those authorities supported the following proposition:

The absence of any reasoning considering these matters reveals that the process of decision-making was in error.

52    The facts in Waterways were unlike the facts in the present case. In Waterways, as Hayne J noted at [131], there was no reasoning to support the primary Judge’s conclusion. In the present case, the AER provided detailed reasons which indicate careful consideration of the matters raised, and the information presented, by Ergon Energy.

53    Further, the Tribunal’s statement in EnergyAustralia at [16] does not support the proposition put forward by Ergon Energy. There, the Tribunal stated:

... the absence of an explanation for, and reasoning in support of, a conclusion reached by a decision-maker may reveal that the process of fact finding or decision making was in error ... A decision maker like the AER is required to deal with the substantial points raised, make findings on material questions of fact, refer to the material upon which findings are based, and provide an intelligible explanation of the process of reasoning leading to the ultimate conclusion.

(emphasis added)

54    The Final Determination addressed, in a thorough manner, the issues raised by Ergon Energy. The reasoning which supported the Final Determination was set out clearly. The Final Determination accords with the approach required by the Tribunal in EnergyAustralia.

55    Turning then to the AER’s process of assessment.

56    First, AR272c was provided to the AER along with Ergon Energy’s Proposal as a document that informed the Finance budget forecast and therefore the figures in the Proposal. Nothing depends on the word “informed”. The document was clearly an input to the process. That is clear from the Proposal itself.

57    Moreover, the document purported to provide a breakdown of customer opex into its SCS and ACS elements. The SCS component was vastly different, and lower than, the SCS component that constituted the forecast in the Proposal

58    On first being asked about the discrepancy by the AER’s expert, PB, Ergon Energy found errors in the document that went a small way (about $3.9 million) towards reconciling it with the Proposal’s forecasts. Ergon Energy did not at that stage, prior to the Draft Decision, claim that reconciliation was impossible or inappropriate. Rather, Ergon Energy “warrant[ed] that the analysis in AR272c [was] reasonable in reaching the [Proposal] forecast, while “urg[ing] caution in assuming that all of the detail in AR272c is completely accurate.” Ergon Energy said merely that the allocation between SCS and ACS was subjective.

59    Certainly, this response would not have justified the AER in deciding that it should have no further regard to AR272c.

60    Following the Draft Decision and provision of its Revised Proposal, Ergon Energy was asked further questions by PB on behalf of the AER. Ergon Energy stated that it did not expect the figures in the two documents to reconcile exactly, for reasons that it set out, acknowledged (again) that there were errors in the categorisation of expenditures in AR272c as either SCS or ACS, and identified further errors. Correction of these errors adjusted the AR272c figure upwards to around $87 million, compared to Ergon Energy’s proposed $104 million. Ergon Energy stated that the remaining discrepancy was insignificant enough to be considered as being within the inherent range of error related to comparison of historical data with forecast data.

61    That may not be as surprising a statement as first appears if it is interpreted as a view that the remaining discrepancy must have been made up of a large number of errors similar in nature to the ones Ergon Energy had found – too many to track down.

62    Nevertheless, it is apparent that even at this stage, Ergon Energy was not disavowing the use of AR272c, and indeed was continuing to make adjustments for errors of classification. Indeed, Ergon Energy “also reiterate[d] that the figures in AR272c were utilised as a check of reasonableness of the actual forecast (PL561c) with the understanding that the errors described above were inherent in the assumptions made in AR272c.”

63    Once again, the AER could hardly have been persuaded by Ergon Energy’s response not to keep up its scrutiny of the difference in the figures presented to it.

64    The materials before the Tribunal show clearly that PB assiduously probed Ergon Energy and that the AER carefully assessed PB’s reports, asking further questions in satisfying itself that it should adopt PB’s conclusions. At no stage did Ergon Energy clearly make the argument that it was not reasonably possible to undertake the reconciliation that was repeatedly asked for. While it said that it did not expect the documents to reconcile exactly, it never argued that they could not in principle, in the light of the differences in their origins, be reconciled to a reasonable degree. Ergon Energy continued to rely on AR272c.

65    The Tribunal considers that Ergon Energy was required to provide sufficient information to the AER to satisfy the AER that Ergon Energy’s operating expenditure proposal reasonably reflected the operating expenditure criteria (as set out in cl 6.5.6(c) of the Rules). It did not do so.

66    The question remains whether the AER was nevertheless in error in making the adjustment that it did to Ergon Energy’s proposed expenditure.

67    The basis for that adjustment is found in PB 2010. The figures in AR272c related to the sum of meter reading and customer service expenditure. In the absence of further explanation from Ergon Energy and in light of the discrepancy remaining after Ergon Energy had reconciled the two sets of figures as far as it did, PB concluded that 79.6 per cent of the total amount for meter reading and customer service in the Revised Proposal should be allowed. It further concluded on the basis of “historical and forecast trending data available in relation to meter reading” that all of the discrepancy was due to customer service costs.

68    While not accepting the basis of this conclusion, Ergon Energy accepted, during the hearing, the AER’s explanation of its calculation of a $33 million reduction in Ergon Energy’s customer service opex allowance.

69    Ergon Energy submitted to the Tribunal that the AER’s reasoning in making this reduction amounted to a thorough rejection of AR272c. The Tribunal considers that PB was entitled to reach the view that it did, based on its expertise and the information before it. The AER fell into no error in relying upon PB.

70    Consequently, the Tribunal finds no error on the part of the AER in relation to customer service costs. Pursuant to s 71P of the NEL and for the reasons set out above, the Tribunal affirms the AER’s decision not to accept Ergon Energy’s customer service costs. In so deciding, the Tribunal had regard to the capex and opex factors, the capex and opex criteria, including the capex and opex objectives.

71    The Tribunal directs that the parties confer and provide minutes of the appropriate determination to be made in light of the above reasons no later than 4:00pm on Monday 31 January 2011.

I certify that the preceding seventy-one (71) numbered paragraphs are a true copy of the Reasons for Decision herein of the Honourable Justice Middleton (Deputy President), RC Davey and RF Shogren.


Dated:    23 December 2010