POWERCO INFORMATION DISCLOSURE FOLLOWING NOTICE TO SUPPLY INFORMATION TO THE COMMERCE COMMISSION SECTION 53ZD OF THE COMMERCE ACT 1986

POWERCO INFORMATION DISCLOSURE FOLLOWING NOTICE TO SUPPLY INFORMATION TO THE COMMERCE COMMISSION SECTION 53ZD OF THE COMMERCE ACT 1986 ASSET ADJUSTM...
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INFORMATION DISCLOSURE FOLLOWING NOTICE TO SUPPLY INFORMATION TO THE COMMERCE COMMISSION SECTION 53ZD OF THE COMMERCE ACT 1986

ASSET ADJUSTMENT PROCESS

9 May 2011

Introduction 1.

The information requested in the Notice to Supply Information to the Commerce Commission Section 53Z of the Commerce Act 1986 to support adjustments to Powerco‟s regulatory asset base is provided in Table 1, Table 2 and in the appendices.

2.

The total asset adjustment is $63.1 million. This is a 6.62% increase in the 2004 ODV.

Background 3.

The Electricity Information Disclosure Requirements 2004 (the Requirements) came into force on 8 May 2004, pursuant to Section 57T of the Commerce Act 1986. These Requirements specified the need for Electricity Distribution Businesses (EDBs) to disclose a Valuation Report, prepared using the Optimised Deprival Value (ODV) method as set out in the Commerce Commission‟s (the Commission) ODV Handbook of 30 August 2004. Powerco published its ODV valuation report, as at 31 March 2004, on 23 December 2004. The report was prepared in accordance with the requirements of the Commission‟s Handbook for optimised deprival valuation of system fixed assets for electricity lines businesses, August 2004. The ODV value was reported as $905.5m.

4.

While this report was prepared using the best information available at the time, subsequent work carried out by Powerco has identified that assets of material value were in existence at the valuation date, but were either omitted or recorded incorrectly. In 2009 significant work went into correcting the asset registers on which Powerco‟s electricity network was valued at ODV in December 2004 making use of new information, availability of better software tools and improvements in available data. This resulted in the DRC, as at 31 March 2004 being revised to $953.6m.

5.

In addition to this, the Input Methodologies Determination Applicable to Electricity Distribution Services Pursuant to Part 4 of the Commerce Act 1986, published 22 December 2010, revised the ranges of the business district, rocky ground and rugged terrain multipliers that could be applied. The work to identify the further corrections to the 2004 ODV has now been completed and is presented along with the effects of the new multiplier ranges in the tables below and supporting appendices to this document. Where the changes in valuation of assets builds on the work done to amend figures in 2009, the difference in value from both the 2009 re-valuation and the original 2004 ODV valuation are included for clarity.

6.

Where feasible, detail on the calculations has been included to allow the reader to verify the arithmetical accuracy. In some cases, this is not possible due to the complexity of the methodology. However, the arithmetical accuracy of the asset adjustment calculations has been audited.

7.

In some cases one type of asset has its value modified, excluded and/or included, or a multiplier has been re-applied and modified. For ease of reading, the overall impact is combined for each asset type.

2

Table 1: Asset Adjustment Process Table 1 summarises the asset value adjustments, consistent with the requirement in Schedule C(2)(c). The figures correspond to Schedule A4 of Powerco‟s Starting Price Adjustment Information Disclosure.

Correction Traffic Management Allowance Correcting road levels Cable in Carriageway Allowance Streetlight Point of Connection Voltage Regulators Distribution Transformers Link Pillars Distribution Substations High Voltage Service Lines Multipliers: Business District Rocky Ground Rugged areas Remote Optimisation Distribution System Subtransmission System

Category Correcting asset register errors Correcting asset register errors Correcting asset register errors

$'000

Correcting asset register errors Correcting asset register errors Correcting asset register errors Correcting asset register errors Correcting asset register errors

Value modified Value modified Included Value modified, included and excluded Value modified Value modified and excluded Value modified Included

1,792 700 2,098 972 2,336 -5,530 -494 1,016

Re-apply existing multiplier Re-apply existing multiplier Re-apply a modified multiplier Re-apply existing multiplier

Value modified Value modified Value modified Value modified

15,520 23,310 19,090 221

Optimisation Optimisation

Included Included

231 1,853 63,115

Table 1

Table 2: Summary of Minimum Information Requirements for Adjustments to Assets All the assets described in Table 2 entered the asset base prior to 1 April 2004. Therefore the value given in Table 2 is calculated by applying the Electricity Information Disclosure Requirements 2004, consistent with the requirement in Schedule C. Category of Adjustment Correct Asset Register Errors

EDB IM cl. ref 2.2.1(2)(a)

Designated asset type Value modified

Information Required Traffic Management Allowances (Appendix A) Assets Covered  278.6km cable that had an incorrect traffic management allowance applied in the 2004 ODV valuation (251km with the wrong traffic level applied and 27.6km laid in the carriageway of level 2 roads). Type of error: Estimation of category now known to be incorrect. Correcting road levels  Data from the RAMM dataset, Transit New Zealand and Local Authorities has corrected the traffic level of 251km of lines and cable.  Table 3 and Table 4 of Appendix A detail the corrected quantities applicable to each traffic management allowance. The total increase in Depreciated Replacement Cost (DRC) is $1,792,440. Cable in Carriageway Allowances  In 2004 Powerco did not have data to be able to apply the “Level 2 temporary traffic management requirements with excavation in the carriageway” to any cables. The availability of better data has allowed Powerco establish that 251km of cable should have had this allowance applied in 2004.  The allowance is $40,000 per km. Applying this to 27.63km of cable results in an increased in DRC of $699,9341.  The total Traffic Management Allowance in 2004 ODV before applying these changes was $5,657,078.2  Total uplift to the 2004 ODV as a result of these two changes is $2,492,373.

1 2

The DRC is calculated from the RC by applying the standard asset lives, inline with the Information Disclosure Requirements 2004. This figure is following corrections in 2009.

2

Correct Asset Register Errors

2.2.1(2)(b)

Included

Street Light Point of Connection (Appendix B) Assets Covered  Assets used to supply electricity to the point of connection with street lights, both for overhead and underground supply.  Underground feed: Connections to 17,583 lights. Overhead feed: Connections to 12,032 lights. ODV Value  No allowance was included for connection assets at the point of supply to streetlights in Powerco‟s 2004 ODV.  The streetlight point of connection valuation was conducted using the MEA approach, in line with ODV guidance.  Replacement costs for overhead and underground connections have been determined in 2010 dollars and deflated to 2004 dollars for application in the 2004 ODV.  Underground feed cost per unit is $263.60. This results in a DRC of $1,854,022.  Overhead feed cost per unit is $50.70. This results in a DRC of $243,865.  The total uplift is $2,097,887 DRC.

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified, included and excluded

Voltage Regulators (Appendix C) Assets Covered  46 voltage regulators. 54 were identified in the 2004 ODV, but following field checking and improvements in data undertaken to better ascertain replacement costs, 9 of these were found to be duplicates in the Western Region and one extra was found in the Eastern Region. Type of error in 46 voltage regulators: Estimation of category & quantity now known to be incorrect. ODV Value  The 2004 ODV value of 54 voltage regulators was $1,847,850 (RC). The table on p24 provides information on the 2004 ODV value and the modified value.  In the 2004 ODV voltage regulators were allocated a non-standard replacement cost. They were assigned the same type and therefore replacement cost. Field checks identified a number of different types and hence new replacement values were calculated in accordance with section 2.2.1(2)(b) of the input methodologies.  Total uplift in ODV of all the changes is $971,697. More detailed information on the calculations is provided in Appendix C. 3

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified

Distribution Transformers (Appendix D) Assets Covered  All distribution transformers for which a date of installation was estimated in the GIS system at the time of the compilation of the 2004 ODV. Type of error: Estimation of age now known to be incorrect. ODV Value  The 2004 ODV and subsequent Asset Management Plans (AMP) included a number of distribution transformer assets whose age had been estimated using the best information available at the time.  Powerco has undertaken an exercise to revise these ages and improve the accuracy of information relating to transformer age in its asset management systems.  To achieve this all transformer assets for which no date of installation was recorded in the 2004 ODV were identified and any duplicates removed. 29,306 transformers from the 2004 ODV were identified and their ages re-assessed either through Powerco‟s ENS system, or through average manufacture dates if more accurate information was not available.  Following establishment of more robust age data the transformers‟ DRC as of 31 March 2004 was re-assessed.  The 2004 DRC was $132,476,977. The revised DRC is $134,813,384.  The impact on 2004 DRC is an increase of $2,336,407. Detail on the calculation is provided in Appendix D.

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified and excluded

Link Pillars (Appendix E) Assets Covered  246 non standard distribution link pillars (LV cables) with more than four outgoing fuse ways (value modified).  Panels and service boxes that were double counted as link pillars in error (excluded). Type of error: Estimation of category now known to be incorrect. ODV Value  Powerco did not have accurate information on link pillars that had more than four outgoing fuse ways when completing the 2004 ODV. Powerco has performed field checks resulting in more accurate information, with some pillar sizes reaching up to 15 outgoing fuse ways. An MEA process was used to obtain non-standard costs for the different pillars.  In reviewing data, Powerco found panels and service boxes had been included in link pillars and needed to be removed 4

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified

as they were already included in the distribution substation and customer service connection categories. These assets have been excluded.  The overall result is a reduction in DRC of $5,530,329. More detailed calculations are in Appendix E. Distribution Substations (Appendix E) Assets Covered  Ground mounted distribution substations and kiosks. Type of error: Estimation of category now known to be incorrect.

Correct Asset Register Errors

Re-applying an existing multiplier

2.2.1(2)(b)

Included

ODV Value  Many distribution substations were incorrectly classified as standard ground mounted substations when the 2004 ODV was completed. Powerco used field check information to identify if the distribution substation was a standard, non standard MEA or a kiosk .  The overall result is a decrease in DRC of $494,129. More detailed calculations are in Appendix F. High Voltage Service Lines (Appendix F) Assets Covered  11kV service lines

2.2.1(2)(b)

Value Modified

ODV Value  In 2004 Powerco had incorrectly classified some 11kV service lines as private, instead of Powerco. Most of this error was corrected in 2009. However, on further review Powerco corrected assets installed up to 1993 and subsequently corrected ownership of those assets in the GIS system.  The ODV Handbook provides a range of standard RC for 11kV O/H conductors, ranging from $12,000/km (light underbuilt) - $25,000/km (light). Applying these costs results in an increase to the DRC of $1,015,806. Table 1 in Appendix F provides more information. Business District Multipliers (Appendix G) Assets Covered  Subtransmission, Distribution and Low Voltage Underground cables, including street light cables, located in „arterial routes‟,„100% asphalt areas‟, under „ornamental paving‟ or near shopping areas.  Correction of the value of multipliers to be applied to the above assets.  Due to errors in multiplier application in 2004, it is not possible to show asset quantities and multipliers of the ODV 5

valuation. The following figures correspond to the changes from the 2009 application of the 2004 methodology. See Appendix E for a more detailed explanation. ODV Value Arterial Routes  In the 2004 ODV cables located in arterial routes were identified, but the multipliers (1.1) not applied. This has been corrected. Improvements in the information on arterial routes obtained from City Councils, have enabled further underground assets in „arterial routes‟ which are not covered by other business district multipliers to be identified.  A detailed costing exercise was undertaken to review the arterial route multiplier of 1.1 used in 2004. This exercise concluded that a multiplier of 1.19 more accurately reflected the increased costs of installation in arterial routes. Details of this exercise are provided in Appendix E.  Application of the revised multiplier to the newly identified and previously omitted cable in arterial routes leads to an increase in 2004 ODV DRC of $1.58M above that identified in 2009. 100% Asphalt Areas  The original 2004 valuation used estimations of 100% asphalt areas; this failed to capture a number of those areas in main centres with no grass berm (i.e. 100% asphalt footpath on both sides of the road). Use of new software has enabled identification of errors in this methodology.  The 2004 memorandum determined a multiplier of 1.5 using broad engineering estimates. These estimates have been re-visited to account for reinstatement costs, importing fill, shoring and fencing in full. This exercise has identified a multiplier of 1.88 as being a more accurate representation of increased costs.  The multiplier of 1.88 was applied to those assets identified as being in 100% asphalt areas leading to an increase in the 2004 ODV DRC of $10.36M above that identified in 2009 for assets where the asphalt multiplier is applied. Ornamental Paving  The range for the ornamental paving multiplier was increased in 2010 by the Commission from 2.0 to 2.5. Review of detailed cost estimates for laying cable in areas of ornamental paving (details in Appendix E) concludes that a multiplier of 2.54 gives an accurate reflection of the increased costs, so this was capped at 2.5 and applied to relevant assets. The resultant increase in 2004 ODV DRC is $1.42M above that identified in 2009.3

3

The ornamental paving multiplier incorporates the increased range in the Input Methodologies. Due to the difficulty of separating out the change, it has been included under the „re-apply existing multiplier‟ category. The Rocky Ground Multiplier also incorporates the lower end of the range in the Input Methodologies, but for the same reason has been included under the „re-apply existing multiplier‟ category.

6

Street Lighting  In the 2004 ODV valuation and subsequent corrections in 2009 the Business District Multiplier was not applied to streetlight cables. This has been corrected in the application of the multipliers listed above leading to an increase in the 2004 ODV DRC of $2.17M above that identified in 2009

Re-apply existing multiplier

2.2.1(2)(c)

Included

 The total uplift in the 2004 ODV DRC resulting from corrections to the application of the business district multipliers is $21.02M which corresponds to an increase of $15.52M over and above the 2009 value.  Table 3 in Appendix G provides information on the changes in value. Rocky Ground Multiplier (Appendix H) Assets Covered  5,404km of distribution cables, low voltage cables and sub-transmission cables situated in conditions to which „rocky ground‟ multipliers may be applied. ODV Value  Powerco produced a memorandum concerning rocky ground as part of the 2004 ODV. For reasons which are not clear the methodology outlined in that document was never applied and hence the 2004 ODV did not apply rocky ground multipliers to Powerco assets. Following identification of this error, further work has been undertaken and new information on ground condition obtained which provides corrected and improved information for the application of the multiplier.  A rocky ground multiplier matrix was established through bottom-up costing methodology, full details and explanation of the methodology are provided at Appendix H.  DRC increase for distribution cables: $9.89M  DRC increase for low voltage cables: $11.86M  DRC increase for sub-transmission cables: $1.55M  Total increase in 2004 DRC $23.31M  Table 5 in Appendix H provides more information on the changes in value.

Re-apply a modified multiplier

Value modified

Rugged Area Multiplier (Appendix I) Assets Covered  Distribution lines, substations, switchgear, transformers, low voltage lines, sub-transmission lines, sub-transmission switch gear. 7

ODV Value  The Rugged Multiplier range increased from „1.2 to 1.3‟ to „1.2 to 1.8‟. Powerco undertook an exercise in early 2010 to develop a detailed breakdown of overhead line installation costs on its networks using a comprehensive bottom up approach, details of which are in Appendix I.  Noting that multipliers are additive, the following were used up to the maximum of 1.8.  Topography 2: 1.27  Topography 3: 1.64  Geology Soft: 1.2  Geology rubble: 1.15  Geology hard: 1.3  Wind / Soil Design (only applied in the most extreme cases (B.1.9.37)): 1.34  Snow and Ice: 1.2  As a result of the maximum imposed on the additive multipliers it is not possible to give an accurate breakdown of the change in value of multipliers applied to a particular asset group, as the maximum can only be applied by subtracting the relevant amount from the total valuation. The total increase in the 2004 DRC valuation is:  Increase due to Topography Multipliers $36.53M  Increase due to Geology Multipliers $13.39M  Increase due to Wind / Soil Multipliers $5.52M  Increase due to Snow / Ice Multipliers $2.94M  Increase from 2009 revisions taking capping into account to ODV DRC: $19.09M  Table 15 in Appendix I provides more information on the changes in value. Re-apply existing multiplier

2.2.1(2)(c)

Value modified

Remote Area Multiplier (Appendix J) Assets Covered  In the original 2004 ODV the remote area multiplier should have been applied to two areas of the Powerco network, but for reasons that are unclear it was not applied to one of these: the southern end of the Wairarapa Valley. Having identified this omission the multiplier has been applied and the revised value classified as „value modified‟ in line with section 2.2.1(2)(c). Following a review of potential remote areas on the network areas of east Pahiatua have also been identified as being in „remote areas‟.  The correction applies to:  Distribution lines – 293km  Distribution substations – 309  Distribution switchgear – 358 8

 Distribution transformers – 328  Low voltage lines – 24km ODV Value  Changes to the rugged terrain multiplier (range changed to 1.2 – 1.8) do not impact on the revaluation as the proposed multiplier (1.25) used is within the pre-existing range.  The change to the 2004 ODV DRC is an increase of $0.221M.  Table 3 in Appendix J provides more detail on the changes in value. Re-apply optimisation or economic value test

2.2.1(2)(e)

Included

Sub-transmission System Optimisation (Appendix K) Assets  The subtransmission network:  Excluded: Review of the optimisation work found a number of 33kV lines incorrectly optimised down to 11kV circuits listed with incorrect weight, so these have been restored to their pre-optimised states..  Included: In addition line previously optimised down either from 33kV to 11kV, or to a lower capacity has been found to be required at a higher capacity for security of supply so exclusion through optimisation has been reversed and included at their original size. ODV Value  Excluded: 33kV line being utilised at 11kV was changed to 11kV, and line listed as heavier duty than what is in place or than required was optimised down.  Included: Subtransmission lines and cables were considered against the required security level and forecast horizon.  The value of each asset in the 2004 ODV valuation was: o Subtransmission cables: $39,808 o Subtransmission lines: $822,978  The value of each asset after applying the optimisation test, in light of more up-to-date information becoming available: o Subtransmission cables: $34,365 o Subtransmission lines: $2,681,697  Resultant overall excluded/ included value in 2004 ODV: o Subtransmission cables: $-5,443 o Subtransmission lines: $1,858,719  The total effect is an increase to the 2004 ODV of $1,853,275.  Details of supporting facts, data, calculations and assumptions are detailed in Appendix L. 9

Re-apply optimisation or economic value test

2.2.1(2)(e)

Included

Distribution System Optimisation (Appendix L) Assets Distribution lines, cables, switchgear and LV cables. The 2004 optimisation had some sections of circuits optimised down to lower capacity conductors. Excluded: Circuits that were previously optimised down in capacity have been restored where the optimised capacity has been found to be uneconomic. Included: The reverted circuits have been restored to their original sizes.  The underlying economic conductor model was updated with present data and key figures modified as below:  WACC (Post-tax) to 9.08%  Value of losses to $0.115 per kWh (Cost of: Gen 5; Tx 1.7, Dis 5.9; Retail 3.7; Meter 0.8 c/kWh)  11kV Rural O/H RCs ($000s): Heavy, 59; medium, 54; light, 48  11kV Urban O/H RCs: 1.6x multiplier applied to rural figures  11kV U/G RCs ($000s): Heavy, 223; Medium, 184; Light, 145  In general, the review shows a decrease in the magnitude of MVA demarcations between each of the size codes. Two feeders remain optimised after going through the 2010 revised methodology: 1) Malden St, Kelvin Grove and 2) Bulls, Pukepapa. Due to an overall decrease in the magnitude of the MD demarcations in the economic conductor model, all other feeders present in the original table were filtered out as their limiting conductors are now judged as economic size or smaller. ODV Value  The value of each asset in the 2004 ODV valuation was: o Distribution cables: $968,190 o Distribution lines: $1,165,337 o Distribution Switchgear: $211,591  The value of each asset after applying the optimisation test, in light of more up-to-date information becoming available: o Distribution cables: $1,222,335 o Distribution lines: $1,248,296 o Distribution Switchgear: $105,152 o LV cables: $-1,577  Resultant overall excluded/ included value in 2004 ODV: o Distribution cables: $ -254,145 10

o Distribution lines: $82,959 o Distribution Switchgear: $-106,439 o LV cables: $-1,577  The total effect is an increase to the 2004 ODV of $230,665.  Details of supporting facts, data, calculations and assumptions are detailed in Appendix M.

11

APPENDICES ADDITIONAL INFORMATION ON ASSET ADJUSTMENT PROCESS

Introduction 8.

More detail on each of the asset adjustments is provided the Appendices. These outline data, information, calculations and assumptions employed.

Contents

Page

Appendix A: Traffic Management Allowances

3

Appendix B: Streetlight Point of Connection

7

Appendix C: Voltage Regulators

17

Appendix D: Distribution Transformers

25

Appendix E: Link Pillars and Distribution Substations

30

Appendix F: High Voltage Service Lines

44

Appendix G: Business District Multiplier

47

Appendix H: Rocky Ground Multiplier

57

Appendix I: Rugged Area Multiplier

68

Appendix J: Remote Area Multiplier

79

Appendix K: Sub-transmission System Optimisation

83

Appendix L: Distribution System Optimisation

101

2

Appendix A: Traffic Management Allowances Introduction 1.

In the 2004 ODV valuation the traffic management allowances used estimations of the category of road level/traffic volumes. Since 2004 better information is available from the Road Assessment and Maintenance Management (RAMM) data set and some of the estimations used in 2004 have been found to be incorrect. The RAMM data is from 2005, but the traffic counts and hence traffic management levels between 2004 and 2005 show no significant differences.4

2.

This memo explains movements in the 2004 ODV due to two different changes to traffic management allowances that have taken place since the changes included in the 2009 Information Disclosure. The two changes described below are: a. application of RAMM and Transit New Zealand datasets and correction of missing traffic data levels; and b. applying cable in carriageway allowances.

3.

Corrections were made in 2009 as part of the VIP1 project and it is this corrected 2009 asset ODV database which is used to show the movements from previous application of Traffic Management Allowances.

Relevant Extracts from 2004 Handbook 4.

Sections A.19 and A.20 of the ODV Handbook detail how allowances for traffic management should be applied. Traffic Management A.19 The standard replacement costs for overhead lines and cables include the cost of temporary traffic management as normally required for roads with low traffic volumes. However, where extensive traffic management provisions (e.g. the provisions of dedicated staff to direct/control traffic) are required by road control authorities, a traffic management allowance may be added to the standard replacement cost, after any other multipliers have been applied, for every kilometre of cables or line route length. The allowances are: Overhead Lines (a) (b)

Level 1 temporary traffic management requirements Level 2 temporary traffic management requirements

$800 per km $1,500 per km

Underground Cables (c) (d) (e)

4

Level 1 temporary traffic management requirements Level 2 temporary traffic management requirements Level 2 temporary traffic management requirements with excavation in the carriageway

$6,000 per km $15,000 per km $40,000 per km

Transit New Zealand, Transit State Highway Traffic Data Booklet 2003-2007, 2008.

3

For any line or cable route, the traffic management allowance shall be included in the replacement cost of the primary asset only. It shall not be added to the replacement cost of under built overhead lines or to the incremental costs of additional cables installed in a cable trench. A20. A traffic management allowance shall only be applied if the ELB has objective evidence (such as a classification by the road control authority in accordance with section A3 of the Transit Code of Practice for Temporary Traffic Management in New Zealand) that a given level of traffic control would apply to a particular location. Evidence relied on to support the application of traffic management allowances shall be retained by the ELB. Furthermore, the carriageway excavation allowance shall be applied only in situations where no more cost-efficient cable route is available. Any traffic management allowance shall only be applied to the actual length or excavation requiring the specified level of traffic control.

Method for Each Change 5.

Since the 2004 ODV Powerco has replaced its GIS system and is now able to apply the Territorial Local Authority and Transit New Zealand data (collated in the RAMM data set) in a spatial format to ensure that only those assets that fall within the identified traffic zones have allowances applied in the valuation and, that all of those that do fall within the area do have the allowances added.

6.

The 2004 ODV Handbook states that for any line or cable route, the traffic management allowance shall be included in the replacement cost of the primary asset only. For all parts of the traffic management work, Powerco has checked that the length of line or cable included only apply to primary assets.

Application RAMM and Transit data set and Correction of Missing Traffic Level Data 7.

Powerco reviewed all the traffic volume data in the RAMM data set and identified „holes‟ which needed clarification by local authorities. Maps identifying each query were sent to local authorities for their review. Their feedback on each query was updated in the data set and reapplied.

8.

During the consultation process, some local authorities provided published records confirming road levels5. Powerco‟s information was then updated with the missing traffic level data. Most of these are also covered by the application of the Transit New Zealand data.

Applying Cable in Carriageway Allowances 9.

Powerco extracted all cable underground assets within level 2 roads by over laying the traffic volumes6 onto its GIS system. Powerco then verified the identified locations from this overlay of data through field books7 to ensure cables were situated within the carriageway boundary.

10.

Some underground cables were found to be laid on the grass verge next to the carriageway, and were consequently excluded. Most of the cable that was laid within the carriageway of

5

For example, a map of level 2 roads was provided for Tauranga. Provided in the RAMM dataset. 7 Field books record accurate details of where cables are located when they are installed. 6

4

level 2 roads were road crossings, for example, where a cable had been laid across a road to feed supply on the other side. 11.

The ODV Handbook states that the carriageway excavation allowance shall be applied only in situations where no more cost-efficient cable route is available. Over 80%8 of the cable was less than 60 metres in length and could therefore be assumed to be short sections with no alternative routes. Over half9 of the cable is less than 30 metres in length and could therefore be assumed to be a road crossing. In this case there would be no other more cost-efficient cable route. For the other 20% the cable could be assumed not to be crossing the road however is the most cost efficient route because no other route exists, such as bridge crossings in Tauranga or Wanganui.

12.

The ODV Handbook states that any traffic management allowance shall only be applied to the actual length or excavation requiring the specified level of traffic control. Only cable within the carriageway was included, as this would have required excavation.

13.

Powerco also reapplied all the updated information on all traffic allowances to ensure there was no double counting. For example, that no level 2 cable in carriageways received both a level 2 allowance and a level 2 in carriageway allowance.

Impact on 2004 ODV Application of RAMM and Transit Data sets and Correction of Missing Traffic Level Data 14.

Powerco found 251km of lines and cables from the application of the RAMM and Transit datasets, including corrections to the „holes‟ identified. After clarification by local authorities these corrections resulted in an ODV uplift of $1,792,440.

VIP1corrected 2004 2010 correction11 Uplift

Quantity (km)10

Replacement Cost ($)

3,772 4,023 251

9,117,805 11,911,798 2,793,993

Depreciated Replacement Cost ($) 5,657,078 7,449,518 1,792,440

ODV ($)

5,657,078 7,449,518 1,792,440

Table 1

Apply Cable in Carriageway Allowances 15.

Powerco found 27.6km route length of cable located in the carriageway of level 2 category roads. The traffic management allowance of $40,000 per km was applied. This resulted in an ODV uplift of $699,934.

8

24kms out of a total of 29.6kms in carriageway before corrections for primary asset trench opening. 15.4km out of a total of 29.4kms in carriageway before corrections for primary asset trench opening. 10 In most cases, the length is stated to two decimal places. 11 The term “2010 correction” is used, as this work was completed in 2010. 9

5

VIP1corrected 2004 2010 correction Uplift

Quantity (km) 0

Replacement Cost ($) 0

Depreciated Replacement Cost ($) 0

ODV ($)

27.6 27.6

1,105,278 1,105,278

699,934 699,934

699,934 699,934

0

Table 2

Summary of Impact on 2004 ODV 16.

Table 3 shows the total correction to the 2004 ODV, disclosed in December 2004. It breaks down all corrections into each type of traffic management allowance. As some of these corrections had already been corrected in 2009, Table 4 shows the uplift to the 2004 ODV from just the 2010 corrections. The RC can be calculated by applying the RC‟s in the ODV Handbook to the quantity.

Overhead Traffic Level 1 Overhead Traffic Level 2 Underground Traffic Level 1 Underground Traffic Level 2 Underground Traffic Level 2 Cable in Carriageway Total

Quantity (km) 2,571 104 1,169 179 28

Replacement Cost ($) 2,056,450 156,599 7,014,837 2,683,912 1,105,278

ODV ($) 1,052,895 92,707 4,562,856 1,741,060 699,934

4,050

13,017,075

8,149,451

Table 3: All traffic management allowances.

Quantity (km) VIP1corrected 3,772 2004 4,050 2010 correction Uplift 278

Replacement Cost ($) 9,117,805

Depreciated ODV ($) Replacement Cost ($) 5,657,078 5,657,078

13,017,075

8,149,451

8,149,451

3,899,270

2,492,373

2,492,373

Table 4: Impact on VIP1 (corrected 2004 ODV in 2009)

6

Appendix B: Streetlight Point of Connection Introduction 1.

This memo provides a review of the valuation of street light point of connections and details the proposed changes to the valuation of this item.

Relevant Extracts from the ODV Handbook APPENDIX A: VALUING ASSETS AND STANDARD ASSET REPLACEMENT COSTS AND LIVES Standard Replacement Costs A.6 Where the nature of an asset in service differs from the nature of any assets in the tables, or where a standard replacement cost for an asset is not provided, an engineering assessment of the replacement cost for the asset shall be made in accordance with clauses 2.12-2.14. Calculations and other records relevant to the engineering assessment shall be retained by the ELB. […] Asset Types […] Street Lighting A.25 Circuits or other field equipment used exclusively for the control of street lights, or the supply of electricity to street lights in areas where LV reticulation is available, shall not be included in the valuation. Where LV reticulation is not available to supply street lights, street light mains owned by the ELB should be valued as a stand-alone two core cable or underbuilt two wire line, using the standard replacement costs given in Table A.1.

2.

The treatment of assets associated with street lights is further clarified in the Companion Report to the ODV Handbook. Implementation of the ODV Method 104 Assets specifically excluded from the ODV valuation in the Commission‟s ODV Handbook are: […]  street lights and poles, or other structures used exclusively for the support of street lights;41  street light control relays and circuits, or other equipment used exclusively for street light control; 42 and  assets where the ownership is disputed and unclear.

7

Powerco Valuation of System Fixed Assets 2004 3.

Powerco‟s 2004 valuation of assets associated with the supply of electricity to street lights conformed to the requirements specified in Section A 2.5 of the 2004 ODV Handbook. Although supply lines and cables were included, no allowance was made for connection assets at the point of supply. Although standard costs are specified in the 2004 ODV Handbook for Customer Service Connections, the cost for these includes the length of overhead wire or underground cable between the LV line and the property boundary. As the connections to street lights are normally much shorter than those to customers‟ points of connection it would be inappropriate to use these standard costs for street light connections.

Determination of Replacement Cost for Street Light Connection Points Justification for non-standard valuation 4.

The Companion Report to the ODV Handbook clarifies that while lines, poles and control circuits are excluded, the assets associated with circuits used to supply electricity to the point of connection of street lights are system fixed assets and should be included in the asset base to be valued. 8

Extract from the Companion Report to the ODV Handbook:

5.

Section A25 of the ODV Handbook specifically excludes control circuits in areas where LV reticulation is available and specifies the asset types to be used where LV reticulation is not available. The effect of this is to optimise out the control relays and the “fifth wire” of an overhead line supply or street light core in a 3 phase underground cable supply. This form of

9

treatment implies that the supply assets for streetlights should be valued on the basis of a direct connection to the LV circuit with individual control at the light (e.g. PE cell). 6.

In order to value the supply assets at the point of connection to LV reticulation it is necessary to adopt an MEA design for a street light connection point. The supply to street lights is covered in Powerco‟s internal document 310S067 Street Supply and Control AMP, which is presently in draft form. Whilst there are several different ownership arrangements for the various elements of the control and supply of street lights throughout Powerco‟s networks the ownership at the point of connection is common. This is dealt with in Section 1.3 Asset Description in the AMP document: Extract from Powerco Standard 310S067 Street Supply and Control AMP

7.

A fuse is required for fault current protection and isolation purposes. Section 32 of the Electricity (Safety) Regulations 2010 requires a service protective fitting to be installed where line function services are supplied to a consumer. Extract from Electricity (Safety) Regulations (2010)

8.

The terms “Consumer” and “Installation” are both defined in section 2(1) of the Electricity Act 1992.

10

Extract from Electricity Act (1992)

Conclusion 9.

Whilst control devices are excluded from the regulated asset base, assets associated with the supply of electricity to street lights should be included. As the effect of the requirements in the ODV Handbook is to optimise out the control relay and fifth wire supplying street lights an MEA design and cost is required for the supply to individual street lights.

10.

In the case of street light fittings line function services are being supplied, the consumer is the relevant local authority with ownership of the street light fitting and the Powerco assets connecting the street light fitting to the supply forms part of an electrical installation. A protective fuse is therefore required to be included in the MEA design and cost.

11.

This MEA design and cost should apply in the regions where Powerco owns the fifth wire systems in order to calculate the regulatory asset base RC.

Method of Valuation 12.

Under the provisions of the ODV Handbook individual system fixed assets are required to be valued using replacement costs (RC‟s) of modern equivalent assets (MEA‟s) and where a standard replacement cost is not provided an engineering assessment is required. The following describes the methods used to determine updated records of street lights in Powerco‟s networks and the process of categorisation and costing of MEA equivalents.

11

MEA Design & Costing 13.

Where a street light is fed from an overhead supply a pole fuse is included at the point of connection to the supply line and in the case of underground a fuse is included within the base of the freestanding street light support pole.

Typical supply arrangements for a free standing street light pole are shown in the diagram below:

12

14.

Typical supply arrangements for street light mounted on a distribution pole are shown in the diagram below:

15.

MEA costs are to be determined on the basis of installed replacement costs using modern designs with currently available materials similar to the existing assets. The design and costing for this update was provided by Tenix New Zealand.

16.

Typical supply arrangements as shown in the diagrams above were used as the basis of the costings. Material items associated with the supply only were included and control items such as the P/E cell were omitted. In the case of overhead supply materials and labour costs for connection of a fuse to a cross arm are used. The underground supply of a streetlight is based on materials and labour for a shared pillar box and associated fuse.

17.

The replacement costs have been calculated at today‟s prices (2010) and then a deflation factor used to arrive at equivalent 2004 costs. The deflator used is based on the difference 13

between the Capital Goods Price Index for Electrical Works from 2010 to 2004 (June quarters). This information was obtained from CGPI tables provided by Statistics NZ. Updated Records 18.

The numbers of streetlights in areas where Powerco owns the supply circuits is shown graphically in Figure 1 below and the numbers of street lights fed from underground reticulation is shown in Figure 2. The total of all street lights is 29,615 and the underground fed lights 17,583 with the remainder 12,032 fed from overhead reticulation.

Figure 1: Total Numbers of street lights in areas where Powerco owns the supply circuits.

14

Figure 2 Underground Fed street lights in areas where Powerco owns the supply circuits.

15

Impact on Powerco ODV Valuation 2004 19.

The following table compares the numbers and replacement cost valuations from the 2004 valuation with those derived in this report using MEA costs.

Powerco Networks - Valuation Integrity Project VIP2 Update Impact on Replacement Costs Subject:

Street Lights

Region:

Eastern & Western

Note:

The RC costs are in 2004$'s (deflated using the CGPI)

2010 Review Numbers RC $'000 Overhead Supply Underground Supply All types

12,032

610

17,583

4,635 5,245

2004 valuation report Numbers RC $'000 Not included

Table 1

20.

To determine DRC values for the MEA isolation point for streetlights, Powerco‟s default installation date of 1/1/1977 was used with a life of 45 years as per customer service connections. For practical purposes the replacement costs for overhead and underground connections have been determined in 2010 dollars and deflated to 2004 dollars for application in the 2004 ODV. The DRC is provided in Table 2.

Summary of Impact on 2004 ODV

Overhead Underground Total 2010 correction Table 2

Quantity (no.) 12,032 17,583 29,615

Replacement Cost ($) 609,661 4,635,055 5,244,716

Depreciated Replacement Cost ($) 243,865 1,854,022 2,097,887

16

Appendix C: Voltage Regulators Introduction 1.

This memo details the proposed changes to the valuation of voltage regulators.

Relevant Extracts from the ODV Handbook APPENDIX A: AND LIVES

VALUING ASSETS AND STANDARD ASSET REPLACEMENT COSTS

Standard Replacement Costs A.6 Where the nature of an asset in service differs from the nature of any assets in the tables, or where a standard replacement cost for an asset is not provided, an engineering assessment of the replacement cost for the asset shall be made in accordance with clauses 2.12-2.14. Calculations and other records relevant to the engineering assessment shall be retained by the ELB. Asset Types A.12 Standard replacement costs for special configurations (e.g. composite 33kV/11kV/LV lines and aerial bundled conductor construction) and for construction at other voltages (e.g. 110kV, 66kV) shall be determined in accordance with clause A.6. Table A.1: Distribution ELB Standard replacement Costs and Lives Voltage regulators are listed under distribution switchgear but no standard value is ascribed.

2.

Under Clause A.6 therefore an engineering assessment is required in order to value voltage regulators. PART TWO:PRACTICAL AND MANDATORY VALUATION PROCEDURES

3.

Clauses 2.12 to 2.14 of the ODV Handbook make reference to the use of modern equivalent assets (MEA). Whilst no definition of MEA is provided in the ODV Handbook as an internationally recognised term, it is defined in Section 3.6 of the International Valuation Guidance Note No. 8 The Cost Approach for Financial Reporting-(DRC) (Revised 2005) 3.6 Modern Equivalent Asset (MEA). A structure similar to an existing structure and having the equivalent productive capacity, which could be built using modern materials, techniques, and design. Replacement cost is the basis used to estimate the cost of constructing a modern equivalent asset.

17

Determination of Replacement Cost 2.11 Individual system fixed assets, including stores and spares, are to be valued using the replacement costs (RCs) of modern equivalent assets (MEAs) that would be installed today to provide the same service potential as the existing assets. The MEA shall not reflect a service potential required by legislative or regulatory changes made since the assets were first built or installed (except where this is inherent in equivalent assets available on the market at the time of valuation) if the existing assets do not yet need to comply with the additional requirements (e.g. where grandfathering provisions apply). The standard replacement costs for MEAs for commonly used system fixed assets (standard assets) are set out in tables contained in Appendix A. Other details regarding the valuation of particular types of system fixed assets are also contained in Appendix A. 2.12 Where a standard replacement cost for a system fixed asset is not provided in Appendix A (non-standard asset), the MEA would normally be the asset that: (i) can be purchased or constructed using current technology at the time of the valuation; and (ii) has an equivalent service potential to that of the existing asset to the extent that this is possible using currently available assets; and (iii) has the lowest lifetime cost. Indicators that can be used to determine the service potential of an MEA include: (a) number of faults/100km of line/year; (b) voltage complaints/100km of line/year; (c) proven reliability of the technology; (d) functional compliance with operating requirements; (e) electrical losses; and (f) meeting any statutory, environmental and industry safety requirements that existed at the time the existing asset was installed. 2.13 Replacement costs for non-standard assets should be determined on the basis that construction occurs around all existing infrastructure and development (other than the asset being valued). Furthermore, replacement costs shall be commensurate with a significant scale of construction rather than with piecemeal additions. As a guide, replacement costs for zone substations, subtransmission circuits and distribution feeders should be determined on the basis that each complete substation, circuit or feeder is constructed as a single project. 2.14 Equipment purchase costs for non-standard assets shall be based on costs charged by manufacturers or suppliers operating in a competitive environment. Construction cost estimates should be based on knowledge of the work involved and efficient industry practice with competitive costs, such as would be charged by efficient private contractors operating in a competitive environment. Alternatively, costs may be based on competitive quotes by turnkey private contractors. 2.15 The valuation report shall identify each class of non-standard asset that is included in the valuation. It shall also describe the basis for the determination of the MEAs, and the replacement costs and asset lives of such assets. Details of any analysis used to determine the appropriate MEA, including details of relevant indicators and life cycle cost analysis, and the basis for estimating the replacement cost and asset life used for valuation purposes shall also be provided. 2.16 Any grants or contributions towards system fixed assets that have been received should be ignored, as it is the deprival value of the assets that is required, not the actual investment. 2.17 Aggregating the RCs of the individual system fixed assets will produce the total network RC.

18

Powerco Valuation of System Fixed Assets 2004 4.

In Powerco‟s 2004 ODV Valuation Report a non-standard replacement cost was listed in Appendix 2 – Non-Standard Asset Replacement Costs and Lives for voltage regulators rated at 2.5MVA.

5.

As part of the optimisation process it was noted that an examination had been made of voltage control devices and as a result five voltage regulators at zone substations had been optimised and replaced in the ODV by on load tap changers. These were listed in Table A3.5.

19

6.

In the ODV Summary tables the following numbers and valuations were listed for voltage regulators. A total of 54 units were listed with a replacement cost of $1,847,850.

Eastern Region:

Western Region:

Determination of Replacement Cost for Voltage Regulators Method of valuation 7.

Under the provisions of the 2004 ODV Handbook individual system fixed assets are required to be valued using replacement costs (RC‟s) of modern equivalent assets (MEA‟s) and where a standard replacement cost is not provided an engineering assessment is required. The following describes the methods used to determine updated records of voltage regulators in Powerco‟s networks and the process of categorisation and costing of MEA equivalents.

20

MEA Design & Costing 8.

MEA costs are to be determined on the basis of installed replacement costs using modern designs with currently available materials similar to the existing assets. The design and costing for this update was provided by Tenix New Zealand.

9.

In order to provide the service capacity and levels required at optimum cost and to maintain flexibility the MEA design for voltage regulators is based on single phase units grouped together in 2 or 3 phase combinations. Costs are based on Cooper Power Systems VR-32 single phase step voltage regulator with CL-5C control12. These units are available for a range of voltage levels, system frequencies and load current ratings. The costs used are for 11kV, 50 Hz units with ratings of 50, 100,150 or 200 amps.

10.

The support structures for mounting voltage regulators are overhead pole designs incorporating a by-pass air break switch fuse and surge arrestor protection. The number of poles corresponds with the number of regulators with steel mounting structures included. The cost of the by-pass air break switch is not included as these switches will have been already included under Distribution Switchgear.

11.

Powerco‟s design standards as laid out in the Powerco Contract Works Manual limits the weight of items such as transformers and voltage regulators to certain limits when installed on overhead structures. If units exceed the defined limits then best practice requires them to be located on the ground. In the case of the MEA design for voltage regulators used in this case the voltage regulator units up to 200 amp fall below the weight criteria and so may be installed on overhead structures. The 300 amp unit exceeds the weight limit however as the maximum size used in the MEA design is 200 amp this does not effect the costing.

12.

Modern practice at zone substations is to install on-load tap changers rather than separate voltage regulators. The MEA equivalent for a regulator installed at a zone substation is therefore the installed cost of an on-load tap changer.

13.

The replacement costs have been calculated at today‟s prices (2010) and then a deflation factor used to arrive at equivalent 2004 costs. The deflator used is 0.7.

Updated records 14.

Voltage regulators are recorded in Powerco‟s GIS system but some of the data recorded in this system is incomplete or of doubtful quality. For example although site ID references are listed in many cases the location by street address is unknown. The voltage and number of phases is listed but in many cases the rating is recorded as zero. The ratings that are listed are recorded in MVA which is problematic as this may be the total load rating at the line voltage or the product of the line current over the voltage range of regulation. In order to cost MEA equivalents the units need to be categorised.

12

SCADA monitoring and control has not been included in the costs as it was not Powerco standard practice to include SCAD out station control to voltage regulators prior to 31 March 2004.

21

15.

Various other records consisting of spreadsheets and photographic records were made available and an attempt to correlate the information from these sources. This update uses the following data sources for information on site location, numbers of phases and load ratings:

Sites Eastern Western

# Phases

Load Ratings [Regulator Analysis from Photo records Photo records GIS.xls] [Western Voltage regulator survey July.xls] & Photograph records

16.

The records used include units installed up to 2009 and so for the purposes of this update those installed after 31 March 2004 need to be removed. The Excel workbook [Regulator Analysis from GIS.xls] included a field „INSTALLATI‟, which was assumed to be the date of installation. Where this field contained a date after 31 March 2004 that particular unit was removed from the costing.

17.

The majority of voltage regulators on Powerco‟s networks are combinations of single phase units. From a total of 47 9 are older 3 phase units and a further 6 are at zone substations.

18.

The profile of regulator types installed in Powerco‟s networks is as follows:

Powerco Networks - Valuation Integrity Project VIP2 Update Summary of types: Subject:

Voltage Regulators

Region:

Eastern & Western

FROM RECORDS: Phase(s) 1 x 1phase 2 x 1 phase 3 x 1 phase 3 phase 2 phase Zone Subs Total 2004 Valuation

Eastern Numbers 0 9 0 1 0 1 11

Western Numbers 1 11 10 8 0 5 35

Powerco Numbers 1 20 10 9 0 6 46

10

44

54

22

The profile of amperage ratings are as follows: MEA DESIGN: Amp ratings VRL50 VRL100 VRL150 VRL200 Feeders Zone Subs Totals

Eastern Numbers 0 3 1 6 10 1 11

Western Numbers 12 2 11 5 30 5 35

Powerco Numbers 12 5 12 11 40 6 46

Impact on Powerco ODV Valuation 2004 19.

The following table compares the numbers and replacement cost valuations from the 2004 valuation with those derived in this report using MEA costs. In summary compared to the 2004 valuation the numbers of regulators have decreased from 54 to 46 and the replacement cost (in 2004 $‟s) has increased from $1.8M to $3.3M.

Powerco Networks - Valuation Integrity Project VIP2 Update Impact on Replacement Costs Subject:

Voltage Regulators

Region:

Eastern & Western

Note:

The RC costs are in 2004$'s (deflated using the CGPI)

RC $'000 676 70 746

2004 valuation report Numbers RC $'000 10 162 0 0 10 162

Eastern Eastern Eastern

Feeders Zone Subs Total

Numbers 10 1 11

Western Western Western

Feeders Zone Subs Total

30 5 35

2,161 350 2,511

39 5 44

1,336 350 1,686

Powerco Powerco Powerco

Feeders Zone Subs Total

40 6 46

2,838 420 3,258

49 5 54

1,498 350 1,848

23

20.

For practical purposes the replacement costs for each type have been determined in 2010 dollars and deflated to 2004 dollars for application in the 2004 ODV.

Summary of Impact on 2004 ODV

2004 2010 correction Change

Quantity (no.) 54 46

Replacement Cost ($) 1,847,850 3,257,526

Depreciated Replacement Cost ($) 1,229,423 2,170,894

-8

1,409,676

941,471

ODV ($) 1,199,197 2,170,894 971,697

24

Appendix D: Distribution Transformer Ages Introduction 1.

The Optimised Deprival Value (ODV), performed in December 2004 as at 31 March 2004, and subsequent Asset Management Plans (AMP) included a number of transformer assets whose age had been estimated using the best information available at the time.

2.

At the time of the original data capture those transformers whose date of installation was known were entered into the Geographical Information System (GIS), but for many the dates of installation were unknown. The ages of such transformers were assigned using the date of purchase (where available) or by applying an estimate derived from a study of the age profile of similar transformers from the same manufacturer.

3.

In order to improve Powerco asset management information, work has been conducted to update the estimates of transformer based on the data in the GIS and ENS (an asset register) systems. This has included matching site references between equipment registers, updating average age data from other sources and some field investigations.

4.

The information is now more accurate than that in the 2004 report and has been used to revisit the depreciated replacement cost (DRC). This has resulted in a value modification of transformers leading to a net increase in the ODV of $2.3M DRC.

AMP Driver for Transformer Age Re-determination 5.

The age profiles of transformer assets in the 2005 to 2010 disclosure AMPs were based on the 2004 ODV data. These age profiles are characterised by a large spike in the quantities (or replacement cost) of transformers installed in 1973. This spike is shown in the extract from the 2010 AMP below. Extract from 2010 AMP, Section 3.8.1

25

6.

Figure 1 shows the age profile for distribution transformer assets based on current replacement costs. It shows that the distribution transformer population is relatively young, and few will require replacement in the near future, although some in harsh coastal environments are requiring replacement before their standard lives. Most distribution transformer replacement occurs due to changed capacity requirements. The large bars are years into which transformers of unknown age have been assigned. Extract from 2011 Disclosure AMP, Section 6.8.4

7.

Figure 2 indicates that distribution transformer replacement costs are set to increase steadily. This is because of rapid network development in the past, resulting in year on year increases in equipment being installed. This ageing profile is thought to be slightly pessimistic, as the load cycles of some distribution transformers result in them lasting longer than their standard lives. Powerco‟s analysis so far shows that distribution transformers may exhibit a wider variation of the average standard life than other assets. Older transformers are lasting longer (due to tank material) than their more modern equivalents.

8.

There are some instances where distribution transformers need to be replaced before their standard life. Examples of this include: •

Replacement due to capacity change, where the age or condition of the changed transformer makes its reuse uneconomic;



Asset replacement due to actual condition;



Unplanned defect repairs as a result of third-party damage;



Overhead transformer to pad-mount conversions due to seismic strength;



Overhead line to underground conversions; 26

9.



Severe corrosion in harsh coastal environments; and



Manufacturing defects (e.g. inadequate corrosion protection).

The incidence of large quantities of transformers of unknown age and inability to match ENS and GIS means that reviewing the age profiles of transformers is likely to have a significant impact on Powerco‟s understanding of the future needs for renewal capital expenditure. It is important therefore that the best information available is used to determine transformer age profiles.

Process Description - Re-determining Transformer Age 10.

In 2004 dates for transformers were drawn from the GIS and where no date was available they were estimated using the date of purchase (where available) or by studying the age profile of similar transformers from the same manufacturer. It has since become possible to cross match data from other equipment registries (ENS) to update and improve the validity of transformer age. The ENS data is more accurate as it includes transformer movements whereas the GIS only records the install date, which does not always give an accurate reflection of the manufacture date. Due to the prohibitively high cost of field investigations the date stamps on transformer plates were only checked for a small number, predominantly in the Eastern region.

11.

Initially the ENS data was cleansed to remove all non-transformer assets (e.g. transformer earths, aerial earths etc) and then instances of multiple transformers were manually removed where there was no data on movements. Data for sites with: 

an installation date prior to 31/03/04;



an installation date prior to 31/03/04 and no movement history (latest transformer date selected);



an installation date after 31/03/04 and no movement history (movement record that existed at 31/03/04 used);



all sites with null date for installation;

were selected and any duplicated records were removed to leave 29,306 records of the total of 30,068 declared in the 2011 AMP. These were then matched against the ENS data giving 29,227 matches. 27,998 of these could be matched by serial number, zone and manufacturer. A summary of these is provided at table 1. Of the remainder 1,308 records, 756 have no manufacturing information and it was decided not to pursue matching these records any further; their dates will remain as estimated in the 2004 ODV and is based on average purchase dates by manufacturer.

Analysis of Updated Purchase Dates Update Reason Number of Records for 2004_ID Date From ENS date Purchased 21987 Date From ENS Installed where prior to 31/03/2004 5195 27

Analysis of Updated Purchase Dates Update Reason Year From Equipment Movement History date Year from Manufacture Average Date Year from Manufacturing Serial Range

Number of Records for 2004_ID 57 749 10

Table 1. Summary of transformers that can be matched by serial number, zone and manufacturer.

12.

The UFID for these records were then matched against the data provided in the 2004 ODV to enable those transformers for which inaccurate dates had been provided to be updated. The process map at Figure 3 refers. A summary of those transformers which could be matched against the original ODV and the origins of the updated dates of installation are in Table 2. The revised ages for these 27,668 transformers was then used to re-value them, utilising the ODV methodology, giving an increased DRC valuation of $2,336,407.47. A full breakdown, by region, of the updated DRC is provided in Table 3.

Analysis of Final Dates Matched to ODV Data Update Reason CountOfTXUNITUFID Date From ENS date Purchased 21800 Date From ENS Installed date where leq 31032004 5090 Year From Eqp History From date 30 Year from Man Avg Date 744 Year from MFG Serial Range 4 Table 2 Reason for updating 2004 ODV data on transformer age

13.

ZONE

A by-product of this work has been a revision to the total number of transformers. Whilst verifying the data, a number of duplications in records were identified; these have been removed and the total revised down to 30,021.

Revised Quantity EGMONT 2004 MASTERTON 3836 NEW 1545 PLYMOUTH PALMERSTO 4510 N TARANAKI 2477 TAURANGA 5264 VALLEY 6608 WANGANUI 3777 30021

Revised RC

Revised DRC

$12,700,540.00 $8,259,926.50 $18,673,125.16 $9,979,455.02 $13,782,800.00 $7,438,434.70

Previou s Total 2004 3887 1545

2004 ODV derived RC $12,700,540.00 $18,850,525.16 $13,782,800.00

2004 ODV derived DRC $8,201,441.99 $9,963,301.46 $7,046,460.14

DRC change $58,484.51 $16,153.56 $391,974.55

$34,939,280.15 $22,534,719.03 4510

$34,939,280.15 $19,835,020.80 $2,699,698.23

$15,528,175.01 $43,990,150.21 $51,985,220.03 $26,773,250.14 $218,372,540.7 2

$15,521,175.01 $43,990,150.21 $51,985,220.03 $26,773,250.14 $218,542,940.72

$10,231,456.96 $28,814,070.59 $34,080,035.59 $13,475,285.90 $134,813,384.3 0

2476 5264 6608 3777 30071

$9,798,409.65 $29,407,504.86 $34,587,586.11 $13,637,251.81 $132,476,976.83

$433,047.31 -$593,434.27 -$507,550.52 -$161,965.91 $2,336,407.47

Table 3. Breakdown of revised transformer DRC valuations by region.

28

Manufacture Date on GIS

Pre 2004

6905

No ENS Purchase Date? from Manufacture Date

Yes 21987

Use purchase date and match UFID with ODV asset register

Yes

21800

Match ENS install date to UFID on ODV asset register

Yes

5090

Match „from‟ or mid point date to UFID on ODV asset register

Yes

30

No ENS install date ≤ 31/03/04

Yes 5195

No or > 31/03/04 „From‟ date in movements register

Yes 57

No Serial no to find purchase date (mid point)

No Manufacture average purchase date

Manufacture serial number table

Yes

749

10

Figure 3 Process map for identification of transformers

29

Appendix E: Link Pillars and Distribution Substations 1.

Link pillars and distribution substation classification (LV frames mounted in ground mounted distribution substations and kiosks) costs were one of those items that required more detailed review. This report details the proposed changes to the valuation of this item.

Relevant Extracts from the ODV Handbook APPENDIX A: VALUING ASSETS AND STANDARD ASSET REPLACEMENT COSTS AND LIVES Standard Replacement Costs A.6 Where the nature of an asset in service differs from the nature of any assets in the tables, or where a standard replacement cost for an asset is not provided, an engineering assessment of the replacement cost for the asset shall be made in accordance with clauses 2.12-2.14. Calculations and other records relevant to the engineering assessment shall be Asset Types A.12 Standard replacement costs for special configurations (e.g. composite 33kV/11kV/LV lines and aerial bundled conductor construction) and for construction at other voltages (e.g. 110kV, 66kV) shall be determined in accordance with clause A.6. Table A.1: Distribution ELB Standard replacement Costs and Lives LV Frames (Panels) are included under standard costs for Distribution Substations specified as Ground Mounted (covered) or Kiosk (Masonry or block enclosure):

Note (f) relates to Kiosks: (f) Includes enclosures and LV frames. Use kiosk only in situations where substation requires more than one LV frame.

2.

Whilst standard costs are specified for ground mounted distribution substations and kiosks and note (f) indicates that this includes the LV frame there is no indication of the number of outgoing cable ways that this relates to. Similarly with feed out from substations on customer‟s premises, there is no indication of how many ways this allows for.

30

Standard costs for link pillars are specified under LV Cables:

3.

There is no standard cost specified for link pillars exceeding 4 way. Powerco has many pillars that do not fit into the standard criteria and therefore under Clause A.6 an engineering assessment is required in order to value these assets.

4.

Powerco also has instances where the standard costs for ground mounted substations including those on customer‟s premises are not adequate and require an engineering assessment to value these assets.

PART TWO: PRACTICAL AND MANDATORY VALUATION PROCEDURES 5.

Clauses 2.12 to 2.14 of the 2004 ODV Handbook make reference to the use of modern equivalent assets (MEA). Whilst no definition of MEA is provided in the ODV Handbook as an internationally recognised term it is defined in Section 3.6 of the International Valuation Guidance Note No. 8 The Cost Approach for Financial Reporting-(DRC) (Revised 2005) 3.6 Modern Equivalent Asset (MEA).A structure similar to an existing structure and having the equivalent productive capacity, which could be built using modern materials, techniques, and design. Replacement cost is the basis used to estimate the cost of constructing a modern equivalent asset. Determination of Replacement Cost 2.11 Individual system fixed assets, including stores and spares, are to be valued using the replacement costs (RCs) of modern equivalent assets (MEAs) that would be installed today to provide the same service potential as the existing assets. The MEA shall not reflect a service potential required by legislative or regulatory changes made since the assets were first built or installed (except where this is inherent in equivalent assets available on the market at the time of valuation) if the existing assets do not yet need to comply with the additional requirements (e.g. where grandfathering provisions apply). The standard replacement costs for MEAs for commonly used system fixed assets (standard assets) are set out in tables contained in Appendix A. Other details regarding the valuation of particular types of system fixed assets are also contained in Appendix A. 2.12 Where a standard replacement cost for a system fixed asset is not provided in Appendix A (non-standard asset), the MEA would normally be the asset that: (i) can be purchased or constructed using current technology at the time of the valuation; and (ii) has an equivalent service potential to that of the existing asset to the extent that this is possible using currently

31

available assets; and (iii) has the lowest lifetime cost. Indicators that can be used to determine the service potential of an MEA include: (a) number of faults/100km of line/year; (b) voltage complaints/100km of line/year; (c) proven reliability of the technology; (d) functional compliance with operating requirements; (e) electrical losses; and (f) meeting any statutory, environmental and industry safety requirements that existed at the time the existing asset was installed. 2.13 Replacement costs for non-standard assets should be determined on the basis that construction occurs around all existing infrastructure and development (other than the asset being valued). Furthermore, replacement costs shall be commensurate with a significant scale of construction rather than with piecemeal additions. As a guide, replacement costs for zone substations, subtransmission circuits and distribution feeders should be determined on the basis that each complete substation, circuit or feeder is constructed as a single project. 2.14 Equipment purchase costs for non-standard assets shall be based on costs charged by manufacturers or suppliers operating in a competitive environment. Construction cost estimates should be based on knowledge of the work involved and efficient industry practice with competitive costs, such as would be charged by efficient private contractors operating in a competitive environment. Alternatively, costs may be based on competitive quotes by turnkey private contractors. 2.15 The valuation report shall identify each class of non-standard asset that is included in the valuation. It shall also describe the basis for the determination of the MEAs, and the replacement costs and asset lives of such assets. Details of any analysis used to determine the appropriate MEA, including details of relevant indicators and life cycle cost analysis, and the basis for estimating the replacement cost and asset life used for valuation purposes shall also be provided. 2.16 Any grants or contributions towards system fixed assets that have been received should be ignored, as it is the deprival value of the assets that is required, not the actual investment. 2.17 Aggregating the RCs of the individual system fixed assets will produce the total network RC.

Powerco Valuation of System Fixed Assets 2004 6.

For the purposes of this review these assets will be examined under two main categories: Distribution Link Pillars (LV Cables) – corresponds to the asset items listed in the ODV Handbook under LV Cables as Link Pillars 2 way and 4 way. Distribution Substations (GMS) – corresponds to the asset items listed in the ODV Handbook under Distribution Substations as Ground Mounted (Covered) and Kiosk (masonry or block enclosure).

32

Distribution Link Pillars 7.

When the Optimised Deprival Valuation (ODV) exercise was undertaken in December 2004 detailed data on the link pillars around the network was not available. In particular although it was known that many link pillars particularly in CBD locations had in excess of four outgoing fuse ways reliable data to identify the exact number for each pillar was not available.

8.

In reviewing the link pillars in the 2004 ODV, it has been found that a number of customer service connection service boxes, and panels associated with smaller ground mounted distribution substations, have been included in the link pillars data. These have been given non standard replacement costs of $200 and $500 respectively. There is no evidence of how the non standard costs were determined in 2004 and field checks of some of these items has confirmed that the link pillar assets were already included in the 2004 ODV as either as part of customer service connections or distribution substations.

9.

A GIS query of pillars, links and panels showed that 2,096 out of a total of 6,320 were listed as “unspecified”. Field checks were undertaken to determine these unspecified items. In the field checks the location was determined using GPS positioning and a physical determination made of the number of ways by photograph. Whilst it was not possible in the time available to site check all 2,096 units 604 (29%) were checked and the results extrapolated.

10.

In the ODV Summary tables the following numbers and valuations were listed for pillars. A total of 16,899 units were listed with a replacement cost of $12,835,500.

Eastern Region:

Western Region:

Distribution Substation (Ground Mounted Substation) 11.

When the Optimised Deprival Valuation (ODV) exercise was undertaken in December 2004 little data was available for the classification of distribution substations. As a result most had to be classed as ground mounted transformers and, in accordance with the Handbook, given a standard replacement cost of $4,000 as at 31 March 2004.

12.

In order to improve Powerco‟s asset management information, work has been conducted to review and update the classification of distribution substations with in Powerco‟s Geographic Information System (GIS) through the use of Google StreetView© and site visits. This work has identified a number of substations that were wrongly classified and hence whose 33

replacement cost was incorrect. As with all revised information on assets that has been produced during work to improve the fidelity of data on our network, the revised classifications have been entered in to the GIS to enable their use in improved network management and future valuations. 13.

A total of 6,132 ground mounted (covered) distribution substations were listed at a total replacement cost of $24,528,000. A total of 19 kiosks were listed at a replacement cost of $209,000. Combined together there was a total of 6,151 at a total replacement cost of $24,737,000.

14.

The detail from the 2004 ODV report is shown below:

Eastern Region:

Western Region:

VIP1 Project Work 15.

Significant corrections were made to Powerco‟s 2004 ODV in 2009 as part of the VIP1 project, and it is this corrected 2009 asset ODV database which is used as the base case for the corrections of this work.

16.

Field checks undertaken in 2011 have shown that the panels and service boxes need to be removed as these assets have already been included under the distribution substation and customer service connection asset categories respectively.

17.

The categories and average unit costs break down after VIP1 project work are as follows:

34

2004 ODV VALUATION REPORT UPDATED AFTER VIP1 IN 2009 RC $'000

Average

91 209 14,176 24,067 1,420 455 1,053 28,181 1,511 664 15,229 52,248 17,404 52,248

182 836 7,088 4,813 2,840 1,820 527 5,636 3,022 2,656 7,615 10,449 13,293 10,449

2.00 4.00 0.50 0.20 2.00 4.00 0.50 0.20 2.00 4.00 0.50 0.20 0.76 0.20

1

11

11.00

3,644 18

14,576 4.00 198 11.00

2,488 19

9,952 209

6,132

24,528 4.00

Numbers LV CABLES LINK PILLARS Eastern 2 Way 4 Way Panel Service Box Western 2 Way 4 Way Panel Service Box Powerco 2 Way 4 Way Panel Service Box Total Pillars Service Box DISTRIBUTION SUBSTATIONS Eastern Kiosk Ground Mounted Eastern Sub Western Kiosk Ground Mounted Western Sub Powerco Kiosk Ground Mounted Powerco Sub

4.00 11.00

35

Determination of Replacement Cost for Pillars & Distribution Substation Classifications Justification for Non-standard Valuation Distribution Substation Classifications (Ground Mounted Substations) 18.

In March 2010 a project was launched to review the classification of ground mounted distribution substations on the Powerco network, as part of efforts to improve asset management information. In the 2004 ODV the valuation assumed all but 19, as per extracts in the prior section from the ODV Report, to be ground mounted substations and valued using the Handbook replacement cost of $4,000 (which provides a value for the concrete pad, LV panel and earthing however excludes the transformer value). There was insufficient data available to identify which of these were in fact kiosks type substations.

19.

The aim of this piece of work was to identify the subset of ground mounted substations which are kiosks or are larger than the „standard‟ ground mounted substation and apply appropriate replacement costs; specific criteria were developed to assist with this: LV frame

kiosk

for the purpose of this reclassification those substations with five or more LV outgoing fuse ways (i.e. distribution or service connections) should be classified as having more than one LV frame identified as being a masonry or block enclosure and with more than one LV frame.13

MEA Ground a non-standard ground mounted substation with more than one LV Mounted frame but not in a building and those on customer‟s premises with Substation more than one LV frame and feedout to the local distribution system. 20.

13

Initially the GIS system was used to identify all distribution substations with a capacity greater than 500 kVA. Those with a lower capacity are highly unlikely to have a need for multiple LV frames and hence are considered to already be accurately classified and valued using the standard replacement cost for a ground mounted distribution substation. It was then possible to spatially identify the number of ways connected to each of the greater than 500kVA substations. Where multiple transformers were present in a single substation, the sum of their capacity and number of LV ways was used and any overlap in spatial data discounted. Those with less than five were already correctly classified as standard ground mounted substations and retained the Handbook value of $4,000. Those with more than five ways were then checked to establish if they were housed in a „building‟. Those that were, have been reclassified as kiosks and given the standard Handbook replacement cost of $11,000. Those that were not kiosks but had multiple LV frames were costed from an MEA design described in the following section of this report. Figure 1 below refers to the process followed.

Note (f) of the standard replacement cost table (A1) from the Handbook.

36

GIS search for capacity of ground mounted transformers

240 mm2 Rating > 341 A

Medium

Largest 300 mm2 Rating = 384 A Z = 0.157 /km 240 mm2 Rating = 341 A

>50 mm2 Rating > 133 A 102

Z = 0.185 /km Light 50 mm2 Rating = 133 A Z = 0.830 /km TABLE 2: UNDERGROUND SIZE CODES Economic Conductor Cost - RURAL

$90.00

PV of lifetime cost ($/m)

$80.00 $70.00 $60.00 Lion

$50.00

Dog Ferret

$40.00 $30.00 $20.00 $10.00 $0.00 0

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

1

1.1 1.2 1.3 1.4 1.5

MVA peak

FIGURE 1: ECONOMIC CONDUCTOR SIZING (REVIEWED 2010)

103

Size Code Economic Range 2010 Review Heavy > 1.35 MVA > 1.1 MVA Medium > 0.7 MVA and < 1.35 MVA > 0.7 MVA and < 1.1 MVA Light < 0.7 MVA < 0.7 MVA TABLE 3: ECONOMIC OVERHEAD CONDUCTOR SIZING Size Code Economic Range Heavy > 2.5 MVA Medium > 1.0 MVA and < 2.5 MVA Light < 1.0 MVA TABLE 4: ECONOMIC UNDERGROUND CABLE SIZING

2010 Review > 3.5 MVA > 0.7 MVA and < 3.5 MVA < 0.7 MVA

Detailed Steps 77. Copy the following columns from the MTDP development spreadsheet into a new ODV spreadsheet:            

Substation Feeder Operating Voltage Zone Thermal Limit (based on smallest conductor in the 1st 2km of feeder) Size of Limiting Conductor Cable or Overhead Length of Feeder Feeder Security Rating (F1-F5) Pseudo Impedance (takes account of non-radial layout of feeders) Maximum Demand (98 percentile) Worst expected voltage (rough calculation using data from above columns)

78.

List the growth factor (%) from the AMP against each feeder, assuming the growth at each substation is evenly distributed between the feeders (growth can be applied over 5 years for distribution networks according to the Handbook)

79.

Calculate the size code for the limiting conductor (Light, Medium or Heavy)

80.

Determine the next smallest size code and its thermal rating (refer Table 1 and Table 2)

81.

Calculate the pseudo-impedance expected if the feeder was constructed to the smaller size code (I have assumed this to be 2 times the MTDP's pseudo-impedance for a Medium to Light notional reduction and 1.5 times for a Heavy to Medium)

82.

Calculate the worst expected voltage assuming the feeder was constructed to the smaller size code and that the feeder is being used to back-feed another feeder to a level of 1/3rd of the actual conductor's rating (ie the 2/3rds rule).

83.

Filter out feeders not thermally capable of supplying the 2/3rds rule current when constructed to the smaller size code.

84.

Filter out feeders for which the worst expected voltage is worse than 0.95 pu when constructed to the smaller size code and after applying the 2/3rds rule.

104

85.

Compare the economic range of the smaller size code with the MD of the feeder and filter out those feeders where the smaller conductor is uneconomic (not using the 2/3rds rule as losses are not the primary concern during fault conditions).

86.

Filter out feeders using local knowledge (incorporating Feeder Security Ratings) which require the larger conductor size although the statistics indicate differently (eg Main St 13 which backs is a major tie line to Pascal St 8 and is an F2 feeder in its own right).

87.

Extract lengths of the portions of the feeders that are oversized

2010 Review 88.

In 2010 the list table of lines to be optimised was reviewed using the following steps. The general principle remained the same as in the 2004 review, but availability of GIS updated feeder models in PSSE Sincal was taken advantage of with steps 3 - 8 in the original review methodology completed via modelling of the various scenarios.

89.

Using data from the Eastern/Western MTDPs, GIS and PSS Sincal models, data was reviewed for accuracy.

90.

a. “Limiting Size (2km from sub)” was found from what was judged to be the limiting conductor in the main branch of the Sincal feeder models. b. “Limiting Size Code” was reviewed using new conductor data compared against the ODV size demarcation. From the reviewed Economic Conductor Sizing model, 2014 MDs were used to determine the economic conductor size of each feeder, as a 5 year horizon for growth is permitted for HV distribution.

91.

Feeders with economic conductor size equal to or larger than the limiting size code were filtered out.

92.

Sincal feeder models for those circuits remaining were obtained, their limiting conductor sizes optimised down to the next smallest size, and load flow run with an additional load on the main branch of the feeder approximate to 1/3rd of the thermal limit of the line, to simulate the backfeed scenario.

93.

Those feeders remaining that comply with the 0.95 pu voltage are then selected to be optimised, with the total length of conductor needing to be changed recorded.

Note: In the 2004 review, allocation of the economic conductor sizes appeared to be based on the 2004 98th percentile MD, rather than the forecasted value at 2009, taking into account the 5 year horizon. This 5 year horizon has been included in this review. Eastern and Western Regions 94.

Due to a difference in available data between the regions there has been some slight differences in the methodology used. The same principals have been used for both regions and so the results are consistent.

105

Stranded Assets 95.

The location of Stranded Distribution Network Assets can, at present, only be located by local knowledge. As "connectivity" information is progressively improved in Powerco's GIS system the identification of such sections may be automated.

Conclusions 96.

There is one feeder from the Eastern region and eighteen feeders from the Western region that require some downwards optimisation. It is to be expected that the Eastern region would have few over-sized feeders as there has been a significant level of growth in the area recently and it is showing no signs of slowing. The growth rate in the Western region is slower, leading to the greater number of feeders that may require optimising down.

97.

There is only one section of "stranded" distribution network known at this time. It is a 450 metre section of DOG (medium) conductor in Carlton Avenue, Wanganui. This section should be given a zero dollar value in the ODV calculation.

2010 Review 98.

Two feeders remain optimised after going through the 2010 revised methodology: 1) Malden St, Kelvin Grove and 2) Bulls, Pukepapa. Due to an overall decrease in the magnitude of the MD demarcations in the economic conductor model, all other feeders present in the original table were filtered out – based on the revised table their limiting conductors were now judged as economic size or smaller, so there was to be no optimisation. The two remaining feeders to be optimised are shown shaded in the following table.

Impact on 2004 ODV 99.

The results of the optimisation review are shown below.

Asset Class Distribution Cables Distribution Lines Distribution Switchgear LV Cables Total Optimisation Value

Quantity 22,569 64,311 5 -25

RC DRC ODRC 2,125,163 1,222,335 968,190 2,289,982 1,248,296 1,165,337 200,000 105,152 211,591 -1,580 -1,577 -1,577 2,574,205 2,343,540 230,665

106

Summary The following optimisation should be applied to Powerco‟s Eastern and Western Distribution networks.

SUBSTATION

FEEDER

kV

ZONE

Thermal Limit (A)

Limitting Size (2km from sub)

Smaller, Length to be Cable / Limiting Change in Optimised Optimised OH Size Code optimisation Size Down (km)

KAIRANGA

TAKARO

11 PALMERSTON

309

161 3C

Cable

Medium

Light

5.2

Excluded

KAPONGA

DUTHIE RD

11 TARANAKI

202

Medium

O/H

Medium

Light

8.7

Excluded

KEITH ST

KEITH ST 14

11 PALMERSTON

255

95mm² 3C

Cable

Medium

Light

3.3

Excluded

KEITH ST

KEITH ST 22

11 PALMERSTON

368

185mm² 3C

Cable

Medium

Light

2.9

Excluded

KEITH ST

KEITH ST 24

11 PALMERSTON

255

95mm² 3C

Cable

Medium

Light

4.2

Excluded

KELVIN GROVE

ARMSTRONG ST 11 PALMERSTON

368

185mm² 3C

Cable

Medium

Light

3

Excluded

KELVIN GROVE

MALDEN ST

11 PALMERSTON

368

185mm² 3C

Cable

Medium

Light

2.2

KELVIN GROVE

STONEY CREEK

11 PALMERSTON

190

19/14

O/H

Medium

Light

1.4

Excluded

LIVINGSTONE

OTAUTU

11 EGMONT

218

WEKE

O/H

Heavy

Medium

1.8

Excluded

LIVINGSTONE

PATEA

11 EGMONT

168

RANGO

O/H

Medium

Light

3.6

Excluded

11 EGMONT

246

DINGO

O/H

Heavy

Medium

3.1

Excluded

LIVINGSTONE

PORTLAND QUAY

107

PASCAL ST

PASCAL ST 6

11 PALMERSTON

313

95mm² 3C

Cable

Medium

Light

2.2

Excluded

PUKEPAPA

BULLS

11 WANGANUI

202

DOG

O/H

Medium

Light

11.1

SANSON

RONGOTEA

11 PALMERSTON

246

DINGO

O/H

Heavy

Medium

2.4

Excluded

TASMAN

OAONUI

11 EGMONT

253

Heavy

O/H

Heavy

Medium

6.4

Excluded

TAUPO QUAY

GUYTON

11 WANGANUI

350

.3in² 3C

Cable

Medium

Light

2.1

Excluded

TP_MOTUROA

MOTUROA 6

11

NEW PLYMOUTH

253

HEAVY

O/H

Heavy

Medium

5.1

Excluded

WAITARA WEST

BROWNE ST

11 TARANAKI

243

95mm² 3C

Cable

Medium

Light

3.2

Excluded

MIKKLESON RD

THOMAS RD

11 VALLEY

340

Jaguar

O/H

Heavy

Medium

3.2

Excluded

In addition: 450 metres of DOG (Medium) conductor in Wanganui (between poles 705150 and 705159 on Carlton Ave) should be removed from the ODV calculations as it is stranded.

108

109

Wilson Cook & Co Engineering and Management Consultants Advisers and Valuers

Reply to: Auckland Office Our ref: 1103 Email: [email protected]

13 May, 2011 Mr Paul Goodeve Regulatory & Business Manager Powerco Limited 84 Liardet Street NEW PLYMOUTH BY EMAIL Dear Mr Goodeve,

RE: ENGINEERING REPORT IN RELATION TO COMMERCE COMMISSION’S ASSET ADJUSTMENT PROCESS In accordance with your instructions of 29 March 2011 in relation to Powerco Limited’s (Powerco’s) response to the Commerce Commission’s (Commission’s) request for information under section 53ZD of the Commerce Act 1986 issued to Powerco on 16 March 2006 (the Notice), relating in turn to the electricity distribution default price-quality path determination process presently under way, we report as follows.

1

Adjustments

We understand that the asset adjustments that you propose to make are as follows: (a) corrections to asset registers ($2,890,000); (b) re-application of existing or modified multipliers ($58,141,000); and (c) the updating of optimisation calculations ($2,084,000). These adjustments, which total $63,115,000, are further identified, described and explained in the attached table, prepared by you in the form of Schedule C of the Notice. The table is supported by a report dated 9 May 2011 that was also prepared by you, is referred to in the table and should be read in conjunction with the table. We note that, as a matter of practicality, neither the table nor its supporting documents contains enough information for a reader to verify the arithmetical accuracy of the asset adjustment calculations as the calculations are made, in the main, in a computerised geographical information system (GIS) or in other such systems operated by your staff. However, we further note that those systems are of a type commonly used by electricity lines businesses for undertaking analyses and making calculations of the type concerned in relation to the present matter.

Registered Office Wilson Cook & Co Limited Level 2, Fidelity House 81 Carlton Gore Road PO Box 2296 Auckland 1140 www.wilsoncook.co.nz

Auckland 8 Harapaki Road Meadowbank Auckland 1072 +64 (9) 578 0770 +64 (21) 645 521 [email protected]

2

Opinion

Having reviewed your material as identified above and after making reasonable enquiries with you, we are satisfied that to the best of our knowledge: (a) the adjustments are of types that comply with the Commission’s requirements, as set out in its determination of December 2010 and as summarised in the Notice; (b) the data, information, criteria and assumptions employed, as set out in your documentation (but not repeated or paraphrased here for reasons of their length and for clarity), are appropriate and reasonable for the purpose of defining the adjustments; (c) the methods of calculation employed to quantify the adjustments, as set out in your documentation, are appropriate for the purpose; and (d) the ODV rules have been properly applied for assets that had not had an ODV valuation calculated originally. Based on the foregoing, we consider that this report meets the requirements of Schedule C, subject to the qualifications stated in 3 below.

3

Qualifications

Values Determined under Generally Accepted Accounting Practice Not Reviewed by Us The derivation of values of a type normally determined in accordance with generally accepted accounting practice is a matter outside our ambit and therefore no such values, if any, have been reviewed by us or are covered by our opinion. Verification of Calculations by Audit Not Reviewed by Us The verification of calculations by methods normally considered an audit (or using processes of a type that a qualified auditor would use) is also a matter outside our ambit and therefore no such calculations have been verified by us or are covered by our opinion. For the avoidance of doubt, we confirm that such calculations include those made in or derived from your GIS system or from other such systems. No Consideration of Roll-Forward of Valuation No consideration has been given by us to the roll-forward of any values from the year 2004. No Determination of Impact of Professional Judgement For reasons of practicality, no attempt has been made by us to quantify the impact of the exercise of professional judgement in your calculations, as the exercise of professional judgement is implicit in (and an integral part of) the calculations and the calculations would not be valid without the assumptions so made.

4

Qualifications of the Reviewer

This opinion has been prepared for and on behalf of Wilson Cook & Co Ltd by Mr Jeffrey Wilson. Mr Wilson believes that he meets the definition of “engineer” in clause 1.1.4 of the Commerce Act (Electricity Distribution Services Input Methodologies) Determination 2010 as he is a chartered professional engineer, acting in that professional capacity and independent (defined in turn by the Commission as neither in a relationship with, nor having an interest in, for present purposes, Powerco, that is likely to involve him in a conflict of interest between his duties to us and any normal professional duties to the Commission). Mr Wilson is qualified professionally in engineering and commerce and has over forty years experience as a professional engineering adviser in the electricity supply industry, including more than 20 years of experience in asset valuations, regulatory assessments and related work.

2

No restriction or influence that we consider inappropriate was imposed on us or on the scope of our services by Powerco’s management or other circumstances.

5

Conditions Accompanying Our Opinion

Disclosure Wilson Cook & Co Limited has prepared this report in accordance with the instructions of its client on the basis that all data and information that may affect its conclusions have been made available to it. No responsibility is accepted if full disclosure has not been made. No responsibility is accepted for any consequential error or defect in our conclusions resulting from any error, omission or inaccuracy in the data or information supplied directly or indirectly. Disclaimer This report has been prepared solely for our client, Powerco, for the purpose stated in the preamble to this report. Wilson Cook & Co Limited, its officers, agents, subcontractors and their staff owe no duty of care and accept no liability to any other party, make no representation or warranty as to the accuracy or completeness of the information or opinions set out in the report to any person other than to its client including any errors or omissions howsoever caused, and do not accept any liability to any party if the report is used for other than its stated purpose. Non-Publication With the exception of its publication by Powerco in full as part of its response to the Commission, neither the whole nor any part of this report may be included in any published document, circular or statement or published in any way without our prior written approval of the form and context in which it may appear. Yours faithfully

Wilson Cook & Co Limited

Encl.

Letter of Engagement and Table of Adjustments

3

29 March 2011

Jeffrey Wilson Managing Director Wilson Cook & Co Ltd PO Box 2296 Auckland New Zealand

Dear Jeff POWERCO – ENGINEERING REPORT AND OPINION IN RELATION TO ASSET ADJUSTMENT PROCESS – TERMS OF ENGAGEMENT 1

Thank you for agreeing to act as Powerco Limited’s (Powerco) independent engineer for the purpose of our response to the Commerce Commission’s request for information under section 53ZD of the Commerce Act 1986, in relation to the Commission’s Commerce Act (Electricity Distribution Default Price-Quality Path) Determination process.

2

Powerco has elected to undertake the asset adjustment process set out in clause 2.2.1 of the Commerce Act (Electricity Distribution Services Input Methodologies) Determination 2010. As such, we need to provide the Commission with certain expert opinions and supporting information.

3

In this letter we set out the key terms of your engagement as one of our independent experts.

4

5

Terms of engagement specifics Wilson Cook & Co Ltd is engaged by Powerco to provide your services to perform, on its behalf, the services set out in paragraph [7] (the Services) until 27 May 2011 or such longer period as may be agreed between us (the Term). You confirm that you meet the definition of “engineer” in clause 1.1.4 of the Commerce Act (Electricity Distribution Services Input Methodologies) Determination 2010. Namely, that you are: 5.1

a chartered professional engineer as defined in s6 of the Chartered Professionals Engineers Act 2002;

5.2

acting in that professional capacity; and

5.3

independent (which is defined in turn as neither in a relationship with, nor having an interest in, for present purposes, Powerco, that is likely to involve you in a conflict of interest between your duties to Powerco and your duties to the Commission).

6

Your report and opinion should be marked for the attention of myself, Paul Goodeve, Regulatory and Business Manager of Powerco.

7

The services are:

8

9

10

7.1

the preparation of a report complying with the requirements set out in Schedule C (including Table 1 of that Schedule) of the Commission’s 16 March 2011 Notice to Supply Information. A copy of those requirements is attached as Appendix A to this letter;

7.2

reporting to Powerco on the progress of your work, either orally or in written form as requested by Powerco;

7.3

all other work as required by Powerco from time to time during the Term of your engagement.

As to payment terms, Wilson Cook & Co will bill Powerco monthly, the invoice to be received by the end of the month. In the normal course, you will be paid by Powerco by the end of the following month. Fees Your fees have been previously agreed with Powerco by way of a separate agreement. Confidentiality You will be required to hold in strict confidence all information and documents that you acquire during the term of this engagement, other than where Powerco specifically authorises you in writing to disclose such information or you must do so by law.

I look forward to hearing whether these terms are acceptable to you. Yours faithfully

Paul Goodeve Regulatory and Business Manager Powerco

Table (Summary of Minimum Information Requirements for Adjustments to Assets Consistent with requirement in Schedule C) Category of Adjustment Correct Asset Register Errors

EDB IM cl. ref 2.2.1(2)(a)

Designated asset type Value modified

Information Required Traffic Management Allowances (Appendix A) Assets Covered  278.6km cable that had an incorrect traffic management allowance applied in the 2004 ODV valuation (251km with the wrong traffic level applied and 27.6km laid in the carriageway of level 2 roads). Type of error: Estimation of category now known to be incorrect. Correcting road levels  Data from the RAMM dataset, Transit New Zealand and Local Authorities has corrected the traffic level of 251km of lines and cable.  Table 3 and Table 4 of Appendix A detail the corrected quantities applicable to each traffic management allowance. The total increase in Depreciated Replacement Cost (DRC) is $1,792,440. Cable in Carriageway Allowances  In 2004 Powerco did not have data to be able to apply the “Level 2 temporary traffic management requirements with excavation in the carriageway” to any cables. The availability of better data has allowed Powerco establish that 251km of cable should have had this allowance applied in 2004.  The allowance is $40,000 per km. Applying this to 27.63km of cable results in an increased in DRC of $699,934 1 .  The total Traffic Management Allowance in 2004 ODV before applying these changes was $5,657,078. 2  Total uplift to the 2004 ODV as a result of these two changes is $2,492,373.

Correct Asset Register Errors

1 2

2.2.1(2)(b)

Included

Street Light Point of Connection (Appendix B) Assets Covered  Assets used to supply electricity to the point of connection with street lights, both for overhead and underground supply.  Underground feed: Connections to 17,583 lights. Overhead feed: Connections to 12,032 lights.

The DRC is calculated from the RC by applying the standard asset lives, inline with the Information Disclosure Requirements 2004. This figure is following corrections in 2009.

ODV Value  No allowance was included for connection assets at the point of supply to streetlights in Powerco’s 2004 ODV.  The streetlight point of connection valuation was conducted using the MEA approach, in line with ODV guidance.  Replacement costs for overhead and underground connections have been determined in 2010 dollars and deflated to 2004 dollars for application in the 2004 ODV.  Underground feed cost per unit is $263.60. This results in a DRC of $1,854,022.  Overhead feed cost per unit is $50.70. This results in a DRC of $243,865.  The total uplift is $2,097,887 DRC.

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified, included and excluded

Voltage Regulators (Appendix C) Assets Covered  46 voltage regulators. 54 were identified in the 2004 ODV, but following field checking and improvements in data undertaken to better ascertain replacement costs, 9 of these were found to be duplicates in the Western Region and one extra was found in the Eastern Region. Type of error in 46 voltage regulators: Estimation of category & quantity now known to be incorrect. ODV Value  The 2004 ODV value of 54 voltage regulators was $1,847,850 (RC). The table on p24 provides information on the 2004 ODV value and the modified value.  In the 2004 ODV voltage regulators were allocated a non-standard replacement cost. They were assigned the same type and therefore replacement cost. Field checks identified a number of different types and hence new replacement values were calculated in accordance with section 2.2.1(2)(b) of the input methodologies.  Total uplift in ODV of all the changes is $971,697. More detailed information on the calculations is provided in Appendix C.

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified

Distribution Transformers (Appendix D) Assets Covered  All distribution transformers for which a date of installation was estimated in the GIS system at the time of the compilation of the 2004 ODV. Type of error: Estimation of age now known to be incorrect.

ODV Value  The 2004 ODV and subsequent Asset Management Plans (AMP) included a number of distribution transformer assets whose age had been estimated using the best information available at the time.  Powerco has undertaken an exercise to revise these ages and improve the accuracy of information relating to transformer age in its asset management systems.  To achieve this all transformer assets for which no date of installation was recorded in the 2004 ODV were identified and any duplicates removed. 29,306 transformers from the 2004 ODV were identified and their ages re-assessed either through Powerco’s ENS system, or through average manufacture dates if more accurate information was not available.  Following establishment of more robust age data the transformers’ DRC as of 31 March 2004 was re-assessed.  The 2004 DRC was $132,476,977. The revised DRC is $134,813,384.  The impact on 2004 DRC is an increase of $2,336,407. Detail on the calculation is provided in Appendix D. Correct Asset Register Errors

2.2.1(2)(b)

Value Modified and excluded

Link Pillars (Appendix E) Assets Covered  246 non standard distribution link pillars (LV cables) with more than four outgoing fuse ways (value modified).  Panels and service boxes that were double counted as link pillars in error (excluded). Type of error: Estimation of category now known to be incorrect.

Correct Asset Register Errors

2.2.1(2)(b)

Value Modified

ODV Value  Powerco did not have accurate information on link pillars that had more than four outgoing fuse ways when completing the 2004 ODV. Powerco has performed field checks resulting in more accurate information, with some pillar sizes reaching up to 15 outgoing fuse ways. An MEA process was used to obtain non-standard costs for the different pillars.  In reviewing data, Powerco found panels and service boxes had been included in link pillars and needed to be removed as they were already included in the distribution substation and customer service connection categories. These assets have been excluded.  The overall result is a reduction in DRC of $5,530,329. More detailed calculations are in Appendix E. Distribution Substations (Appendix E) Assets Covered  Ground mounted distribution substations and kiosks. Type of error: Estimation of category now known to be incorrect.

Correct Asset Register Errors

Re-applying an existing multiplier

2.2.1(2)(b)

Included

ODV Value  Many distribution substations were incorrectly classified as standard ground mounted substations when the 2004 ODV was completed. Powerco used field check information to identify if the distribution substation was a standard, non standard MEA or a kiosk .  The overall result is a decrease in DRC of $494,129. More detailed calculations are in Appendix F. High Voltage Service Lines (Appendix F) Assets Covered  11kV service lines

2.2.1(2)(b)

Value Modified

ODV Value  In 2004 Powerco had incorrectly classified some 11kV service lines as private, instead of Powerco. Most of this error was corrected in 2009. However, on further review Powerco corrected assets installed up to 1993 and subsequently corrected ownership of those assets in the GIS system.  The ODV Handbook provides a range of standard RC for 11kV O/H conductors, ranging from $12,000/km (light underbuilt) - $25,000/km (light). Applying these costs results in an increase to the DRC of $1,015,806. Table 1 in Appendix F provides more information. Business District Multipliers (Appendix G) Assets Covered  Subtransmission, Distribution and Low Voltage Underground cables, including street light cables, located in ‘arterial routes’,‘100% asphalt areas’, under ‘ornamental paving’ or near shopping areas.  Correction of the value of multipliers to be applied to the above assets.  Due to errors in multiplier application in 2004, it is not possible to show asset quantities and multipliers of the ODV valuation. The following figures correspond to the changes from the 2009 application of the 2004 methodology. See Appendix E for a more detailed explanation. ODV Value Arterial Routes  In the 2004 ODV cables located in arterial routes were identified, but the multipliers (1.1) not applied. This has been corrected. Improvements in the information on arterial routes obtained from City Councils, have enabled further underground assets in ‘arterial routes’ which are not covered by other business district multipliers to be identified.  A detailed costing exercise was undertaken to review the arterial route multiplier of 1.1 used in 2004. This exercise concluded that a multiplier of 1.19 more accurately reflected the increased costs of installation in arterial routes. Details of this exercise are provided in Appendix E.  Application of the revised multiplier to the newly identified and previously omitted cable in arterial routes leads to an

increase in 2004 ODV DRC of $1.58M above that identified in 2009.   



100% Asphalt Areas The original 2004 valuation used estimations of 100% asphalt areas; this failed to capture a number of those areas in main centres with no grass berm (i.e. 100% asphalt footpath on both sides of the road). Use of new software has enabled identification of errors in this methodology. The 2004 memorandum determined a multiplier of 1.5 using broad engineering estimates. These estimates have been re-visited to account for reinstatement costs, importing fill, shoring and fencing in full. This exercise has identified a multiplier of 1.88 as being a more accurate representation of increased costs. The multiplier of 1.88 was applied to those assets identified as being in 100% asphalt areas leading to an increase in the 2004 ODV DRC of $10.36M above that identified in 2009 for assets where the asphalt multiplier is applied. Ornamental Paving The range for the ornamental paving multiplier was increased in 2010 by the Commission from 2.0 to 2.5. Review of detailed cost estimates for laying cable in areas of ornamental paving (details in Appendix E) concludes that a multiplier of 2.54 gives an accurate reflection of the increased costs, so this was capped at 2.5 and applied to relevant assets. The resultant increase in 2004 ODV DRC is $1.42M above that identified in 2009. 3

Street Lighting  In the 2004 ODV valuation and subsequent corrections in 2009 the Business District Multiplier was not applied to streetlight cables. This has been corrected in the application of the multipliers listed above leading to an increase in the 2004 ODV DRC of $2.17M above that identified in 2009 

Re-apply existing multiplier

3

2.2.1(2)(c)

Included

The total uplift in the 2004 ODV DRC resulting from corrections to the application of the business district multipliers is $21.02M which corresponds to an increase of $15.52M over and above the 2009 value.  Table 3 in Appendix G provides information on the changes in value. Rocky Ground Multiplier (Appendix H) Assets Covered  5,404km of distribution cables, low voltage cables and sub-transmission cables situated in conditions to which ‘rocky

The ornamental paving multiplier incorporates the increased range in the Input Methodologies. Due to the difficulty of separating out the change, it has been included under the ‘re-apply existing multiplier’ category. The Rocky Ground Multiplier also incorporates the lower end of the range in the Input Methodologies, but for the same reason has been included under the ‘re-apply existing multiplier’ category.

ground’ multipliers may be applied. ODV Value  Powerco produced a memorandum concerning rocky ground as part of the 2004 ODV. For reasons which are not clear the methodology outlined in that document was never applied and hence the 2004 ODV did not apply rocky ground multipliers to Powerco assets. Following identification of this error, further work has been undertaken and new information on ground condition obtained which provides corrected and improved information for the application of the multiplier.  A rocky ground multiplier matrix was established through bottom-up costing methodology, full details and explanation of the methodology are provided at Appendix H.  DRC increase for distribution cables: $9.89M  DRC increase for low voltage cables: $11.86M  DRC increase for sub-transmission cables: $1.55M  Total increase in 2004 DRC $23.31M  Table 5 in Appendix H provides more information on the changes in value. Re-apply a modified multiplier

Value modified

Rugged Area Multiplier (Appendix I) Assets Covered  Distribution lines, substations, switchgear, transformers, low voltage lines, sub-transmission lines, sub-transmission switch gear. ODV Value  The Rugged Multiplier range increased from ‘1.2 to 1.3’ to ‘1.2 to 1.8’. Powerco undertook an exercise in early 2010 to develop a detailed breakdown of overhead line installation costs on its networks using a comprehensive bottom up approach, details of which are in Appendix I.  Noting that multipliers are additive, the following were used up to the maximum of 1.8.  Topography 2: 1.27  Topography 3: 1.64  Geology Soft: 1.2  Geology rubble: 1.15  Geology hard: 1.3  Wind / Soil Design (only applied in the most extreme cases (B.1.9.37)): 1.34  Snow and Ice: 1.2  As a result of the maximum imposed on the additive multipliers it is not possible to give an accurate breakdown of the change in value of multipliers applied to a particular asset group, as the maximum can only be applied by subtracting the

      Re-apply existing multiplier

2.2.1(2)(c)

Value modified

relevant amount from the total valuation. The total increase in the 2004 DRC valuation is: Increase due to Topography Multipliers $36.53M Increase due to Geology Multipliers $13.39M Increase due to Wind / Soil Multipliers $5.52M Increase due to Snow / Ice Multipliers $2.94M Increase from 2009 revisions taking capping into account to ODV DRC: $19.09M Table 15 in Appendix I provides more information on the changes in value.

Remote Area Multiplier (Appendix J) Assets Covered  In the original 2004 ODV the remote area multiplier should have been applied to two areas of the Powerco network, but for reasons that are unclear it was not applied to one of these: the southern end of the Wairarapa Valley. Having identified this omission the multiplier has been applied and the revised value classified as ‘value modified’ in line with section 2.2.1(2)(c). Following a review of potential remote areas on the network areas of east Pahiatua have also been identified as being in ‘remote areas’.  The correction applies to:  Distribution lines – 293km  Distribution substations – 309  Distribution switchgear – 358  Distribution transformers – 328  Low voltage lines – 24km ODV Value  Changes to the rugged terrain multiplier (range changed to 1.2 – 1.8) do not impact on the revaluation as the proposed multiplier (1.25) used is within the pre-existing range.  The change to the 2004 ODV DRC is an increase of $0.221M.  Table 3 in Appendix J provides more detail on the changes in value.

Re-apply optimisation or economic value test

2.2.1(2)(e)

Included

Sub-transmission System Optimisation (Appendix K) Assets  The subtransmission network:  Excluded: Review of the optimisation work found a number of 33kV lines incorrectly optimised down to 11kV circuits listed with incorrect weight, so these have been restored to their pre-optimised states..  Included: In addition line previously optimised down either from 33kV to 11kV, or to a lower capacity has been

found to be required at a higher capacity for security of supply so exclusion through optimisation has been reversed and included at their original size.

Re-apply optimisation or economic value test

2.2.1(2)(e)

Included

ODV Value  Excluded: 33kV line being utilised at 11kV was changed to 11kV, and line listed as heavier duty than what is in place or than required was optimised down.  Included: Subtransmission lines and cables were considered against the required security level and forecast horizon.  The value of each asset in the 2004 ODV valuation was: o Subtransmission cables: $39,808 o Subtransmission lines: $822,978  The value of each asset after applying the optimisation test, in light of more up-to-date information becoming available: o Subtransmission cables: $34,365 o Subtransmission lines: $2,681,697  Resultant overall excluded/ included value in 2004 ODV: o Subtransmission cables: $-5,443 o Subtransmission lines: $1,858,719  The total effect is an increase to the 2004 ODV of $1,853,275.  Details of supporting facts, data, calculations and assumptions are detailed in Appendix L. Distribution System Optimisation (Appendix L) Assets Distribution lines, cables, switchgear and LV cables. The 2004 optimisation had some sections of circuits optimised down to lower capacity conductors. Excluded: Circuits that were previously optimised down in capacity have been restored where the optimised capacity has been found to be uneconomic. Included: The reverted circuits have been restored to their original sizes.  The underlying economic conductor model was updated with present data and key figures modified as below:  WACC (Post-tax) to 9.08%  Value of losses to $0.115 per kWh (Cost of: Gen 5; Tx 1.7, Dis 5.9; Retail 3.7; Meter 0.8 c/kWh)  11kV Rural O/H RCs ($000s): Heavy, 59; medium, 54; light, 48  11kV Urban O/H RCs: 1.6x multiplier applied to rural figures  11kV U/G RCs ($000s): Heavy, 223; Medium, 184; Light, 145  In general, the review shows a decrease in the magnitude of MVA demarcations between each of the size codes. Two feeders remain optimised after going through the 2010 revised methodology: 1) Malden St, Kelvin Grove and 2) Bulls,

Pukepapa. Due to an overall decrease in the magnitude of the MD demarcations in the economic conductor model, all other feeders present in the original table were filtered out as their limiting conductors are now judged as economic size or smaller. ODV Value  The value of each asset in the 2004 ODV valuation was: o Distribution cables: $968,190 o Distribution lines: $1,165,337 o Distribution Switchgear: $211,591  The value of each asset after applying the optimisation test, in light of more up-to-date information becoming available: o Distribution cables: $1,222,335 o Distribution lines: $1,248,296 o Distribution Switchgear: $105,152 o LV cables: $-1,577  Resultant overall excluded/ included value in 2004 ODV: o Distribution cables: $ -254,145 o Distribution lines: $82,959 o Distribution Switchgear: $-106,439 o LV cables: $-1,577  The total effect is an increase to the 2004 ODV of $230,665.  Details of supporting facts, data, calculations and assumptions are detailed in Appendix M.