Note This attachment forms part of the AER's final decision on Ergon Energy's 2015–20 distribution determination. It should be read with other parts of the final decision. The final decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory base Attachment 3 – Rate of return Attachment 4 – of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
the most recent annual benchmarking report that has been published under clause 6.27 and the benchmark operating expenditure that would be incurred by an efficient distribution network service provider over the relevant regulatory control period the actual and expected operating expenditure of the distribution network service provider during any preceding regulatory control periods the extent to which the operating expenditure forecast includes expenditure to address the concerns of electricity consumers as identified by the distribution network service provider in the course of its engagement with electricity consumers the relative prices of operating and capital inputs the substitution possibilities between operating and capital expenditure whether the operating expenditure forecast is consistent with any incentive scheme or schemes that to the distribution network service provider under clauses 6.5.8 or 6.6.2 to 6.6.4 the extent the operating expenditure forecast is referable to arrangements with a person other than the distribution network service provider that, in our opinion, do not reflect arm’s length terms whether the operating expenditure forecast includes an amount relating to a project that should more appropriately be included as a contingent project under clause 6.6A.1(b) the extent to which the distribution network service provider has considered and made provision for efficient and prudent non-network alternatives any relevant project assessment conclusions report published under 5.17.4(o),(p) or (s) any other factor we consider relevant and which we have notified the distribution network service provider in writing, prior to the submission of its revised regulatory proposal under clause 6.10.3, is an operating expenditure factor. Consistent with our Guideline, we have used benchmarking to a greater extent than we did in regulatory determinations prior to the AEMC's 2012 rule changes. To that end, there are two additional operating expenditure factors that we have taken into account under the last opex factor above: our benchmarking data sets including, but not necessarily limited to: data contained in any economic benchmarking RIN, category analysis RIN, reset RIN or annual reporting RIN any relevant data from international sources data sets that support econometric modelling and other assessment techniques consistent with the approach set out in the Guideline as updated from time to time.
growth 0.63 0.69 0.77 0.77 0.77 0.77 Output growth 1.62 1.44 1.36 1.21 1.18 1.34 Productivity growth 0.00 0.75 0.75 0.75 0.75 0.75 Overall rate of change 2.26 1.38 1.37 1.22 1.19 1.35 AER Price growth 0.35 0.34 0.26 0.38 0.47 0.57 Output growth 1.26 1.19 1.48 1.30 1.62 1.35 Productivity growth – – – – – – Overall rate of change 1.60 1.53 1.74 1.69 2.10 1.92 Source: Ergon Energy revised proposal, Response to information request 87, Ergon Energy's opex model and AER analysis. Preliminary position For our preliminary decision, we did not adopt Ergon Energy's forecast change in price, output and productivity in our forecast rate of change and thus our alternative estimate of opex. Our preliminary position for each rate of change component is outlined below Price growth: for labour price growth we adopted an average of Deloitte Access Economics' (DAE) and Energex's consultant PricewaterhouseCoopers' wage price index (WPI) forecast for the Queensland electricity, gas, water and waste services (EGWWS) industries. For non-labour we adopted the forecast change in the CPI. We applied Economic Insights' benchmark weightings for labour and non-labour. Output growth: we applied the weighted average forecast change in customer numbers, circuit length and ratcheted maximum demand from Ergon Energy's reset RIN. We based the weights of each of these outputs on Economic Insights' opex cost function analysis. Productivity growth: we applied a zero per cent productivity growth estimate. We based this estimate on our considerations of recent productivity trends and whether this would be applicable to the forecast period. This was also consistent with Economic Insights' recommendations. Refer to section B.4 of attachment 7 in our preliminary decision for a detailed explanation of our considerations. Revised proposal and submissions We have maintained the methodology we used in our preliminary decision regarding the forecast rate of change. Ergon Energy raised concerns regarding the price growth and output growth components of our rate of change forecasting approach. Ergon Energy also did not understand why we did not adopt its rate of change estimate given the small differences in the outcome.