EDB Information Disclosure Requirements Information Templates for

Transcription

1 EDB Information Disclosure Requirements Information Templates for Schedules 1 10 Disclosure Date 31 August 2017 Disclosure Year (year ended) Templates for Schedules 1 10 excluding 5f 5g Template Version 4.1. Prepared 24 March 2015 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended xlsx CoverSheet

2 Table of Contents Schedule Schedule name 1 ANALYTICAL RATIOS 2 REPORT ON RETURN ON INVESTMENT 3 REPORT ON REGULATORY PROFIT 4 REPORT ON VALUE OF THE REGULATORY ASSET BASE (ROLLED FORWARD) 5a REPORT ON REGULATORY TAX ALLOWANCE 5b REPORT ON RELATED PARTY TRANSACTIONS 5c REPORT ON TERM CREDIT SPREAD DIFFERENTIAL ALLOWANCE 5d REPORT ON COST ALLOCATIONS 5e REPORT ON ASSET ALLOCATIONS 6a REPORT ON CAPITAL EXPENDITURE FOR THE DISCLOSURE YEAR 6b REPORT ON OPERATIONAL EXPENDITURE FOR THE DISCLOSURE YEAR 7 COMPARISON OF FORECASTS TO ACTUAL EXPENDITURE 8 REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES 9a ASSET REGISTER 9b ASSET AGE PROFILE 9c REPORT ON OVERHEAD LINES AND UNDERGROUND CABLES 9d REPORT ON EMBEDDED NETWORKS 9e REPORT ON NETWORK DEMAND 10 REPORT ON NETWORK RELIABILITY Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx2 TOC

3 Disclosure Template Instructions These templates have been prepared for use by EDBs when making disclosures under clauses 2.3.1, , , 2.5.1, and of the Electricity Distribution Information Disclosure Determination and Dates To prepare the templates for disclosure, the supplier's company name should be entered in cell C8, the date of the last day of the current (disclosure) year should be entered in cell C12, and the date on which the information is disclosed should be entered in cell C10 of the CoverSheet worksheet. The cell C12 entry (current year) is used to calculate disclosure years in the column headings that show above some of the tables and in labels adjacent to some entry cells. It is also used to calculate the For year ended date in the template title blocks (the title blocks are the light green shaded areas at the top of each template). The cell C8 entry (company name) is used in the template title blocks. Dates should be entered in day/month/year order (Example -"1 April 2013"). Data Entry Cells and Calculated Cells Data entered into this workbook may be entered only into the data entry cells. Data entry cells are the bordered, unshaded areas (white cells) in each template. Under no circumstances should data be entered into the workbook outside a data entry cell. In some cases, where the information for disclosure is able to be ascertained from disclosures elsewhere in the workbook, such information is disclosed in a calculated cell. Validation Settings on Data Entry Cells To maintain a consistency of format and to help guard against errors in data entry, some data entry cells test keyboard entries for validity and accept only a limited range of values. For example, entries may be limited to a list of category names, to values between 0% and 100%, or either a numeric entry or the text entry N/A. Where this occurs, a validation message will appear when data is being entered. These checks are applied to keyboard entries only and not, for example, to entries made using Excel s copy and paste facility. Conditional Formatting Settings on Data Entry Cells Schedule 2 cells G79 and I79:L79 will change colour if the total cashflows do not equal the corresponding values in table 2(ii). Schedule 4 cells P99:P105 and P107 will change colour if the RAB values do not equal the corresponding values in table 4(ii). Schedule 9b columns AA to AE (2013 to 2017) contain conditional formatting. The data entry cells for future years are hidden (are changed from white to yellow). Schedule 9b cells AG10 to AG60 will change colour if the total assets at year end for each asset class does not equal the corresponding values in column I in Schedule 9a. Schedule 9c cell G30 will change colour if G30 (overhead circuit length by terrain) does not equal G18 (overhead circuit length by operating voltage). Inserting Additional Rows and Columns The templates for schedules 4, 5b, 5c, 5d, 5e, 6a, 8, 9d, and 9e may require additional rows to be inserted in tables marked 'include additional rows if needed' or similar. Column A schedule references should not be entered in additional rows, and should be deleted from additional rows that are created by copying and pasting rows that have schedule references. Additional rows in schedules 5c, 6a, and 9e must not be inserted directly above the first row or below the last row of a table. This is to ensure that entries made in the new row are included in the totals. Schedules 5d and 5e may require new cost or asset category rows to be inserted in allocation change tables 5d(iii) and 5e(ii). Accordingly, cell protection has been removed from rows 77 and 78 of the respective templates to allow blocks of rows to be copied. The four steps to add new cost category rows to table 5d(iii) are: Select Excel rows 69:77, copy, select Excel row 78, insert copied cells. Similarly, for table 5e(ii): Select Excel rows 70:78, copy, select Excel row 79, then insert copied cells. The template for schedule 8 may require additional columns to be inserted between column P and U. To avoid interfering with the title block entries, these should be inserted to the left of column S. If inserting additional columns, the formulas for standard consumers total, non-standard consumers totals and total for all consumers will need to be copied into the cells of the added columns. The formulas can be found in the equivalent cells of the existing columns. Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended xlsx Instructions

4 Disclosures by Sub-Network If the supplier has sub-networks, schedules 8, 9a, 9b, 9c, 9e, and 10 must be completed for the network and for each sub-network. A copy of the schedule worksheet(s) must be made for each sub-network and named accordingly. Schedule References The references labelled '' in the leftmost column of each template are consistent with the row references in the Electricity Distribution ID Determination 2012 (as issued on 24 March 2015). They provide a common reference between the rows in the determination and the template. Description of Calculation References Calculation cell formulas contain links to other cells within the same template or elsewhere in the workbook. Key cell references are described in a column to the right of each template. These descriptions are provided to assist data entry. Cell references refer to the row of the template and not the schedule reference. Worksheet Completion Sequence Calculation cells may show an incorrect value until precedent cell entries have been completed. Data entry may be assisted by completing the schedules in the following order: 1. Coversheet 2. Schedules 5a 5e 3. Schedules 6a 6b 4. Schedule 8 5. Schedule 3 6. Schedule 4 7. Schedule 2 8. Schedule 7 9. Schedules 9a 9e 10. Schedule 10 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended xlsx Instructions

5 SCHEDULE 1: ANALYTICAL RATIOS 7 1(i): Expenditure metrics 8 Expenditure per GWh energy delivered to ICPs ($/GWh) Expenditure per average no. of ICPs ($/ICP) Expenditure per MW maximum coincident system demand ($/MW) Expenditure per km circuit length ($/km) Expenditure per MVA of capacity from EDBowned distribution transformers ($/MVA) 9 Operational expenditure 22, ,422 3,854 79, Network 5, , , Non-network 16, ,649 2,910 60, Expenditure on assets 29, ,718 5, , Network 25, ,557 4,427 91, Non-network 3, , , (ii): Revenue metrics 18 Revenue per GWh energy delivered to ICPs ($/GWh) Revenue per average no. of ICPs ($/ICP) 19 Total consumer line charge revenue 93,774 1, Standard consumer line charge revenue 95,113 1, Non-standard consumer line charge revenue 52, , (iii): Service intensity measures Demand density 15 Maximum coincident system demand per km of circuit length (for supply) (kw/km) 26 Volume density 172 Total energy delivered to ICPs per km of circuit length (for supply) (MWh/km) 27 Connection point density 12 Average number of ICPs per km of circuit length (for supply) (ICPs/km) 28 Energy intensity 14,153 Total energy delivered to ICPs per average number of ICPs (kwh/icp) (iv): Composition of regulatory income 31 ($000) % of revenue 32 Operational expenditure 35, % 33 Pass-through and recoverable costs excluding financial incentives and wash-ups 41, % 34 Total depreciation 25, % 35 Total revaluations 11, % 36 Regulatory tax allowance 11, % 37 Regulatory profit/(loss) including financial incentives and wash-ups 45, % 38 Total regulatory income 148, (v): Reliability 41 This schedule calculates expenditure, revenue and service ratios from the information disclosed. The disclosed ratios may vary for reasons that are company specific and, as a result, must be interpreted with care. The Commerce Commission will publish a summary and analysis of information disclosed in accordance with the ID determination. This will include information disclosed in accordance with this and other schedules, and information disclosed under the other requirements of the determination. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Interruption rate Interruptions per 100 circuit km Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 5 S1.Analytical Ratios

6 SCHEDULE 2: REPORT ON RETURN ON INVESTMENT This schedule requires information on the Return on Investment (ROI) for the EDB relative to the Commerce Commission's estimates of post tax WACC and vanilla WACC. EDBs must calculate their ROI based on a monthly basis if required by clause of the ID Determination or if they elect to. If an EDB makes this election, information supporting this calculation must be provided in 2(iii). EDBs must provide explanatory comment on their ROI in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (i): Return on Investment CY-2 CY-1 Current Year CY 8 31 Mar Mar Mar 17 9 ROI comparable to a post tax WACC % % % 10 Reflecting all revenue earned 5.42% 6.48% 8.12% 11 Excluding revenue earned from financial incentives 5.38% 6.43% 8.10% 12 Excluding revenue earned from financial incentives and wash-ups 5.38% 6.14% 7.87% Mid-point estimate of post tax WACC 6.10% 5.37% 4.77% 15 25th percentile estimate 5.39% 4.66% 4.05% 16 75th percentile estimate 6.82% 6.09% 5.48% ROI comparable to a vanilla WACC 20 Reflecting all revenue earned 6.21% 7.13% 8.66% 21 Excluding revenue earned from financial incentives 6.16% 7.08% 8.64% 22 Excluding revenue earned from financial incentives and wash-ups 6.16% 6.79% 8.41% WACC rate used to set regulatory price path 8.77% 7.19% 7.19% Mid-point estimate of vanilla WACC 6.89% 6.02% 5.31% 27 25th percentile estimate 6.17% 5.30% 4.59% 28 75th percentile estimate 7.60% 6.74% 6.03% (ii): Information Supporting the ROI ($000) Total opening RAB value 547, plus Opening deferred tax (23,525) 34 Opening RIV 524, Line charge revenue 148, Expenses cash outflow 77, add Assets commissioned 47, less Asset disposals 1, add Tax payments 8, less Other regulated income Mid-year net cash outflows 131, Term credit spread differential allowance Total closing RAB value 581, less Adjustment resulting from asset allocation 0 49 less Lost and found assets adjustment plus Closing deferred tax (27,133) 51 Closing RIV 553, ROI comparable to a vanilla WACC 8.66% Leverage (%) 44% 56 Cost of debt assumption (%) 4.41% 57 Corporate tax rate (%) 28% ROI comparable to a post tax WACC 8.12% 60 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx6 S2.Return on Investment

7 SCHEDULE 2: REPORT ON RETURN ON INVESTMENT This schedule requires information on the Return on Investment (ROI) for the EDB relative to the Commerce Commission's estimates of post tax WACC and vanilla WACC. EDBs must calculate their ROI based on a monthly basis if required by clause of the ID Determination or if they elect to. If an EDB makes this election, information supporting this calculation must be provided in 2(iii). EDBs must provide explanatory comment on their ROI in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (iii): Information Supporting the Monthly ROI Opening RIV N/A Line charge revenue Expenses cash outflow Assets commissioned Asset disposals Other regulated income Monthly net cash outflows 67 April 68 May 69 June 70 July 71 August 72 September 73 October 74 November 75 December 76 January 77 February 78 March 79 Total Tax payments N/A Term credit spread differential allowance N/A Closing RIV N/A Monthly ROI comparable to a vanilla WACC N/A Monthly ROI comparable to a post tax WACC N/A (iv): Year-End ROI Rates for Comparison Purposes Year-end ROI comparable to a vanilla WACC 8.04% Year-end ROI comparable to a post tax WACC 7.50% * these year-end ROI values are comparable to the ROI reported in pre 2012 disclosures by EDBs and do not represent the Commission's current view on ROI (v): Financial Incentives and Wash-Ups Net recoverable costs allowed under incremental rolling incentive scheme 103 Purchased assets avoided transmission charge Energy efficiency and demand incentive allowance 105 Quality incentive adjustment 106 Other financial incentives 107 Financial incentives Impact of financial incentives on ROI 0.02% Input methodology claw-back 2, Recoverable customised price-quality path costs 113 Catastrophic event allowance 114 Capex wash-up adjustment (464) 115 Transmission asset wash-up adjustment NPV wash-up allowance Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx7 S2.Return on Investment

8 SCHEDULE 2: REPORT ON RETURN ON INVESTMENT 117 Reconsideration event allowance This schedule requires information on the Return on Investment (ROI) for the EDB relative to the Commerce Commission's estimates of post tax WACC and vanilla WACC. EDBs must calculate their ROI based on a monthly basis if required by clause of the ID Determination or if they elect to. If an EDB makes this election, information supporting this calculation must be provided in 2(iii). EDBs must provide explanatory comment on their ROI in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Other wash-ups 119 Wash-up costs 1, Impact of wash-up costs on ROI 0.23% Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx8 S2.Return on Investment

9 SCHEDULE 3: REPORT ON REGULATORY PROFIT 7 3(i): Regulatory Profit ($000) 8 Income 9 Line charge revenue 148, plus Gains / (losses) on asset disposals (1,185) 11 plus Other regulated income (other than gains / (losses) on asset disposals) 1, Total regulatory income 148, Expenses 15 less Operational expenditure 35, less Pass-through and recoverable costs excluding financial incentives and wash-ups 41, Operating surplus / (deficit) 71, less Total depreciation 25, plus Total revaluations 11, Regulatory profit / (loss) before tax 57, less Term credit spread differential allowance less Regulatory tax allowance 11, Regulatory profit/(loss) including financial incentives and wash-ups 45, (ii): Pass-through and Recoverable Costs excluding Financial Incentives and Wash-Ups ($000) 34 Pass through costs 35 Rates Commerce Act levies Industry levies CPP specified pass through costs 39 Recoverable costs excluding financial incentives and wash-ups 40 Electricity lines service charge payable to Transpower 32, Transpower new investment contract charges 1, System operator services 43 Distributed generation allowance 6, Extended reserves allowance 45 Other recoverable costs excluding financial incentives and wash-ups This schedule requires information on the calculation of regulatory profit for the EDB for the disclosure year. All EDBs must complete all sections and provide explanatory comment on their regulatory profit in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Pass-through and recoverable costs excluding financial incentives and wash-ups 41, Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 9 S3.Regulatory Profit

10 SCHEDULE 3: REPORT ON REGULATORY PROFIT This schedule requires information on the calculation of regulatory profit for the EDB for the disclosure year. All EDBs must complete all sections and provide explanatory comment on their regulatory profit in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (iii): Incremental Rolling Incentive Scheme ($000) 49 CY-1 CY Mar Mar Allowed controllable opex 52 Actual controllable opex Incremental change in year CY-5 31 Mar CY-4 31 Mar CY-3 31 Mar CY-2 31 Mar CY-1 31 Mar 16 Previous years' incremental change Previous years' incremental change adjusted for inflation 62 Net incremental rolling incentive scheme Net recoverable costs allowed under incremental rolling incentive scheme 65 3(iv): Merger and Acquisition Expenditure Merger and acquisition expenditure Provide commentary on the benefits of merger and acquisition expenditure to the electricity distribution business, including required disclosures in accordance with section 2.7, in Schedule 14 (Mandatory Explanatory Notes) ($000) 69 3(v): Other Disclosures Self-insurance allowance ($000) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 10 S3.Regulatory Profit

11 SCHEDULE 4: REPORT ON VALUE OF THE REGULATORY ASSET BASE (ROLLED FORWARD) 7 4(i): Regulatory Asset Base Value (Rolled Forward) RAB RAB RAB RAB RAB 8 for year ended 31 Mar Mar Mar Mar Mar 17 9 ($000) ($000) ($000) ($000) ($000) 10 Total opening RAB value 488, , , , , less Total depreciation 20,409 21,312 22,846 24,802 25, plus Total revaluations 4,188 7, ,129 11, plus Assets commissioned 20,048 48,677 43,840 33,577 47, less Asset disposals 504 5,462 3,565 2,815 1, plus Lost and found assets adjustment plus Adjustment resulting from asset allocation Total closing RAB value 491, , , , , (ii): Unallocated Regulatory Asset Base Unallocated RAB * RAB ($000) ($000) ($000) ($000) 29 Total opening RAB value 547, , less 31 Total depreciation 25,277 25, plus 33 Total revaluations 11,807 11, plus 35 Assets commissioned (other than below) 28,655 28, Assets acquired from a regulated supplier 37 Assets acquired from a related party 19,306 19, Assets commissioned 47,961 47, less 40 Asset disposals (other than below) 1,493 1, Asset disposals to a regulated supplier 42 Asset disposals to a related party 43 Asset disposals 1,493 1, plus Lost and found assets adjustment This schedule requires information on the calculation of the Regulatory Asset Base (RAB) value to the end of this disclosure year. This informs the ROI calculation in Schedule 2. EDBs must provide explanatory comment on the value of their RAB in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section plus Adjustment resulting from asset allocation Total closing RAB value 581, , * The 'unallocated RAB' is the total value of those assets used wholly or partially to provide electricity distribution services without any allowance being made for the allocation of costs to services provided by the supplier that are not electricity distribution services. The RAB value represents the value of these assets after applying this cost allocation. Neither value includes works under construction. Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 11 S4.RAB Value (Rolled Forward)

12 SCHEDULE 4: REPORT ON VALUE OF THE REGULATORY ASSET BASE (ROLLED FORWARD) This schedule requires information on the calculation of the Regulatory Asset Base (RAB) value to the end of this disclosure year. This informs the ROI calculation in Schedule 2. EDBs must provide explanatory comment on the value of their RAB in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (iii): Calculation of Revaluation Rate and Revaluation of Assets CPI 4 1, CPI 4 1, Revaluation rate (%) 2.17% ($000) ($000) ($000) ($000) 60 Total opening RAB value 547, , less Opening value of fully depreciated, disposed and lost assets 3,073 3, Total opening RAB value subject to revaluation 544, , Total revaluations 11,807 11, (iv): Roll Forward of Works Under Construction Works under construction preceding disclosure year 20,136 20, plus Capital expenditure 40,538 40, less Assets commissioned 47,961 47, plus Adjustment resulting from asset allocation 72 Works under construction - current disclosure year 12,713 12, Highest rate of capitalised finance applied 6.35% 75 Unallocated RAB * Unallocated works under construction RAB Allocated works under construction Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 12 S4.RAB Value (Rolled Forward)

13 SCHEDULE 4: REPORT ON VALUE OF THE REGULATORY ASSET BASE (ROLLED FORWARD) This schedule requires information on the calculation of the Regulatory Asset Base (RAB) value to the end of this disclosure year. This informs the ROI calculation in Schedule 2. EDBs must provide explanatory comment on the value of their RAB in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (v): Regulatory Depreciation ($000) ($000) ($000) ($000) 79 Depreciation - standard 25,277 25, Depreciation - no standard life assets 81 Depreciation - modified life assets 82 Depreciation - alternative depreciation in accordance with CPP Unallocated RAB * 83 Total depreciation 25,277 25, RAB 85 4(vi): Disclosure of Changes to Depreciation Profiles ($000 unless otherwise specified) 86 Asset or assets with changes to depreciation* Reason for non-standard depreciation (text entry) * include additional rows if needed Depreciation charge for the period (RAB) Closing RAB value under 'nonstandard' depreciation Closing RAB value under 'standard' depreciation 96 4(vii): Disclosure by Asset Category 97 ($000 unless otherwise specified) 98 Subtransmission lines Subtransmission cables Zone substations Distribution and LV lines Distribution and LV cables Distribution substations and transformers Distribution switchgear Other network assets Non-network assets 99 Total opening RAB value 19,871 21,663 67, , ,742 89,812 48,698 16,578 37, , less Total depreciation ,084 4,255 4,379 4,731 1,481 2,029 5,251 25, plus Total revaluations ,363 2,408 2,919 1, , plus Assets commissioned 1,633 2,043 16,291 6,100 5,149 3,870 4, ,916 47, less Asset disposals , plus Lost and found assets adjustment (14) plus Adjustment resulting from asset allocation 106 plus Asset category transfers (4,512) (1) 48 (2,927) 7,405 (13) 107 Total closing RAB value 21,047 23,645 78, , ,431 90,507 50,233 23,432 39, , Asset Life 110 Weighted average remaining asset life (years) 111 Weighted average expected total asset life (years) Total Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 13 S4.RAB Value (Rolled Forward)

14 SCHEDULE 5a: REPORT ON REGULATORY TAX ALLOWANCE This schedule requires information on the calculation of the regulatory tax allowance. This information is used to calculate regulatory profit/loss in Schedule 3 (regulatory profit). EDBs must provide explanatory commentary on the information disclosed in this schedule, in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section a(i): Regulatory Tax Allowance ($000) 8 Regulatory profit / (loss) before tax 57, plus Income not included in regulatory profit / (loss) before tax but taxable * 11 Expenditure or loss in regulatory profit / (loss) before tax but not deductible 30 * 12 Amortisation of initial differences in asset values 5, Amortisation of revaluations , less Total revaluations 11, Income included in regulatory profit / (loss) before tax but not taxable * 18 Discretionary discounts and customer rebates 19 Expenditure or loss deductible but not in regulatory profit / (loss) before tax * 20 Notional deductible interest 9, , Regulatory taxable income 42, less Utilised tax losses 26 Regulatory net taxable income 42, Corporate tax rate (%) 28% 29 Regulatory tax allowance 11, * Workings to be provided in Schedule a(ii): Disclosure of Permanent Differences 33 In Schedule 14, Box 5, provide descriptions and workings of items recorded in the asterisked categories in Schedule 5a(i). 34 5a(iii): Amortisation of Initial Difference in Asset Values ($000) Opening unamortised initial differences in asset values 124, less Amortisation of initial differences in asset values 5, plus Adjustment for unamortised initial differences in assets acquired 39 less Adjustment for unamortised initial differences in assets disposed 40 Closing unamortised initial differences in asset values 119, Opening weighted average remaining useful life of relevant assets (years) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 14 S5a.Regulatory Tax Allowance

15 SCHEDULE 5a: REPORT ON REGULATORY TAX ALLOWANCE This schedule requires information on the calculation of the regulatory tax allowance. This information is used to calculate regulatory profit/loss in Schedule 3 (regulatory profit). EDBs must provide explanatory commentary on the information disclosed in this schedule, in Schedule 14 (Mandatory Explanatory Notes). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section a(iv): Amortisation of Revaluations ($000) Opening sum of RAB values without revaluations 512, Adjusted depreciation 24, Total depreciation 25, Amortisation of revaluations a(v): Reconciliation of Tax Losses ($000) Opening tax losses 55 plus Current period tax losses 56 less Utilised tax losses 57 Closing tax losses 58 5a(vi): Calculation of Deferred Tax Balance ($000) Opening deferred tax (23,525) plus Tax effect of adjusted depreciation 6, less Tax effect of tax depreciation 9, plus Tax effect of other temporary differences* less Tax effect of amortisation of initial differences in asset values 1, plus Deferred tax balance relating to assets acquired in the disclosure year less Deferred tax balance relating to assets disposed in the disclosure year (130) plus Deferred tax cost allocation adjustment (0) Closing deferred tax (27,133) a(vii): Disclosure of Temporary Differences In Schedule 14, Box 6, provide descriptions and workings of items recorded in the asterisked category in Schedule 5a(vi) (Tax effect of other temporary differences). 81 5a(viii): Regulatory Tax Asset Base Roll-Forward Opening sum of regulatory tax asset values 303, less Tax depreciation 32, plus Regulatory tax asset value of assets commissioned 47, less Regulatory tax asset value of asset disposals 1, plus Lost and found assets adjustment 88 plus Adjustment resulting from asset allocation 89 plus Other adjustments to the RAB tax value 90 Closing sum of regulatory tax asset values 317,596 ($000) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 15 S5a.Regulatory Tax Allowance

16 SCHEDULE 5b: REPORT ON RELATED PARTY TRANSACTIONS This schedule provides information on the valuation of related party transactions, in accordance with section and of the ID determination. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section b(i): Summary Related Party Transactions ($000) 8 Total regulatory income 9 Operational expenditure 12, Capital expenditure 24, Market value of asset disposals 12 Other related party transactions 13 5b(ii): Entities Involved in Related Party Transactions 14 Name of related party 15 Unison Fibre Limited 16 ETEL Limited Related party relationship A wholly owned subsidiary of A wholly owned subsidiary of 17 Unison Insurance Limited 18 Unison Contracting Services Limited * include additional rows if needed A wholly owned subsidiiary of A wholly owned subsidiary of Unison Networks 21 5b(iii): Related Party Transactions 22 Name of related party Related party transaction type Value of transaction ($000) Basis for determining value 23 Unison Fibre Limited Opex Fibre Optic interconnections 823 ID clause 2.3.6(1)(a) Corporate overhead and rent charge. Offsets against 24 Unison Fibre Limited Opex non-network opex (584) ID clause 2.3.6(1)(a) Purchase of electrical distribution transformers and 25 ETEL Limited Capex other electrical components 2,797 IM clause (5)(b)(i) Insurance premium - Transmission and Distribution 26 Unison Insurance Limited Opex policy 876 ID clause 2.3.6(1)(f) 27 Unison Contracting Services Limited Capex Construction of new network equipment 19,306 IM clause (5)(g) 28 Unison Contracting Services Limited Capex Non network asset purchases 2,421 IM clause (5)(g) 29 Unison Contracting Services Limited Opex Service Interruptions and emergencies 2,767 ID clause 2.3.6(1)(b) 30 Unison Contracting Services Limited Opex Vegetation Management 1,265 ID clause 2.3.6(1)(b) 31 Unison Contracting Services Limited Opex Routine and corrective maintenance and inspection 1,971 ID clause 2.3.6(1)(b) 32 Unison Contracting Services Limited Opex Asset replacement and renewal 1,052 ID clause 2.3.6(1)(b) 33 Unison Contracting Services Limited Opex Systems operations and network support 284 ID clause 2.3.6(1)(b) 34 Unison Contracting Services Limited Opex Business support 4,179 ID clause 2.3.6(1)(b) * include additional rows if needed Description of transaction Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 16 S5b.Related Party Transactions

17 SCHEDULE 5c: REPORT ON TERM CREDIT SPREAD DIFFERENTIAL ALLOWANCE 7 8 5c(i): Qualifying Debt (may be Commission only) 9 This schedule is only to be completed if, as at the date of the most recently published financial statements, the weighted average original tenor of the debt portfolio (both qualifying debt and non-qualifying debt) is greater than five years. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Issuing party Issue date Pricing date Original tenor (in years) Coupon rate (%) Book value at issue date (NZD) Book value at date of financial statements (NZD) Term Credit Spread Difference Cost of executing an interest rate swap Debt issue cost readjustment 11 31/10/ /8/ % 58,997 72, (103) 12 31/10/ /8/ % 58,997 72, (121) * include additional rows if needed 145, (224) c(ii): Attribution of Term Credit Spread Differential Gross term credit spread differential (0) Total book value of interest bearing debt 234, Leverage 44% 24 Average opening and closing RAB values 564, Attribution Rate (%) 106% Term credit spread differential allowance Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 17 S5c.TCSD Allowance

18 SCHEDULE 5d: REPORT ON COST ALLOCATIONS This schedule provides information on the allocation of operational costs. EDBs must provide explanatory comment on their cost allocation in Schedule 14 (Mandatory Explanatory Notes), including on the impact of any reclassifications. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section d(i): Operating Cost Allocations 8 Value allocated ($000s) 9 10 Service interruptions and emergencies Arm's length deduction Electricity distribution services 11 Directly attributable 3,262 Non-electricity distribution services 12 Not directly attributable 13 Total attributable to regulated service 3, Vegetation management 15 Directly attributable 1, Not directly attributable 17 Total attributable to regulated service 1, Routine and corrective maintenance and inspection 19 Directly attributable 2, Not directly attributable 21 Total attributable to regulated service 2, Asset replacement and renewal 23 Directly attributable 1, Not directly attributable 25 Total attributable to regulated service 1, System operations and network support 27 Directly attributable 4, Not directly attributable 3,066 3, Total attributable to regulated service 7, Business support 31 Directly attributable 8, Not directly attributable 11,026 1,777 12, Total attributable to regulated service 19, Operating costs directly attributable 21,294 Total OVABAA allocation increase ($000s) 36 Operating costs not directly attributable 14,092 1,777 15, Operational expenditure 35, Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 18 S5d.Cost Allocations

19 SCHEDULE 5d: REPORT ON COST ALLOCATIONS This schedule provides information on the allocation of operational costs. EDBs must provide explanatory comment on their cost allocation in Schedule 14 (Mandatory Explanatory Notes), including on the impact of any reclassifications. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section d(ii): Other Cost Allocations 40 Pass through and recoverable costs ($000) 41 Pass through costs 42 Directly attributable 1, Not directly attributable 44 Total attributable to regulated service 1, Recoverable costs 46 Directly attributable 40, Not directly attributable 48 Total attributable to regulated service 40, d(iii): Changes in Cost Allocations* Change in cost allocation 1 CY-1 Current Year (CY) 53 Cost category Original allocation 54 Original allocator or line items New allocation 55 New allocator or line items Difference Rationale for change Change in cost allocation 2 CY-1 Current Year (CY) 62 Cost category Original allocation 63 Original allocator or line items New allocation 64 New allocator or line items Difference Rationale for change Change in cost allocation 3 CY-1 Current Year (CY) 71 Cost category Original allocation 72 Original allocator or line items New allocation 73 New allocator or line items Difference Rationale for change * a change in cost allocation must be completed for each cost allocator change that has occurred in the disclosure year. A movement in an allocator metric is not a change in allocator or component. 79 include additional rows if needed ($000) ($000) ($000) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 19 S5d.Cost Allocations

20 SCHEDULE 5e: REPORT ON ASSET ALLOCATIONS This schedule requires information on the allocation of asset values. This information supports the calculation of the RAB value in Schedule 4. EDBs must provide explanatory comment on their cost allocation in Schedule 14 (Mandatory Explanatory Notes), including on the impact of any changes in asset allocations. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section e(i): Regulated Service Asset Values Subtransmission lines Value allocated ($000s) Electricity distribution services 11 Directly attributable 21, Not directly attributable 13 Total attributable to regulated service 21, Subtransmission cables 15 Directly attributable 23, Not directly attributable 17 Total attributable to regulated service 23, Zone substations 19 Directly attributable 78, Not directly attributable 21 Total attributable to regulated service 78, Distribution and LV lines 23 Directly attributable 115, Not directly attributable 25 Total attributable to regulated service 115, Distribution and LV cables 27 Directly attributable 138, Not directly attributable 29 Total attributable to regulated service 138, Distribution substations and transformers 31 Directly attributable 90, Not directly attributable 33 Total attributable to regulated service 90, Distribution switchgear 35 Directly attributable 50, Not directly attributable 37 Total attributable to regulated service 50, Other network assets 39 Directly attributable 23, Not directly attributable 41 Total attributable to regulated service 23, Non-network assets 43 Directly attributable 39, Not directly attributable 45 Total attributable to regulated service 39, Regulated service asset value directly attributable 581, Regulated service asset value not directly attributable 49 Total closing RAB value 581, e(ii): Changes in Asset Allocations* Change in asset value allocation 1 CY-1 Current Year (CY) 54 Asset category Original allocation 55 Original allocator or line items New allocation 56 New allocator or line items Difference Rationale for change Change in asset value allocation 2 CY-1 Current Year (CY) 63 Asset category Original allocation 64 Original allocator or line items New allocation 65 New allocator or line items Difference Rationale for change Change in asset value allocation 3 CY-1 Current Year (CY) 72 Asset category Original allocation 73 Original allocator or line items New allocation 74 New allocator or line items Difference Rationale for change * a change in asset allocation must be completed for each allocator or component change that has occurred in the disclosure year. A movement in an allocator metric is not a change in allocator or compone 80 include additional rows if needed ($000) ($000) ($000) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 20 S5e.Asset Allocations

21 SCHEDULE 6a: REPORT ON CAPITAL EXPENDITURE FOR THE DISCLOSURE YEAR This schedule requires a breakdown of capital expenditure on assets incurred in the disclosure year, including any assets in respect of which capital contributions are received, but excluding assets that are vested assets. Information on expenditure on assets must be provided on an accounting accruals basis and must exclude finance costs. EDBs must provide explanatory comment on their expenditure on assets in Schedule 14 (Explanatory Notes to Templates). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section a(i): Expenditure on Assets ($000) ($000) 8 Consumer connection 11,663 9 System growth 7, Asset replacement and renewal 17, Asset relocations 2, Reliability, safety and environment: 13 Quality of supply 1, Legislative and regulatory 15 Other reliability, safety and environment Total reliability, safety and environment 1, Expenditure on network assets 40, Expenditure on non-network assets 5, Expenditure on assets 46, plus Cost of financing less Value of capital contributions 6, plus Value of vested assets Capital expenditure 40, a(ii): Subcomponents of Expenditure on Assets (where known) ($000) 27 Energy efficiency and demand side management, reduction of energy losses 28 Overhead to underground conversion 2, Research and development 30 6a(iii): Consumer Connection 31 Consumer types defined by EDB* ($000) ($000) 32 Simple customer connection 2, Complex customer connection 8, Special customer connections * include additional rows if needed 38 Consumer connection expenditure 11, less Capital contributions funding consumer connection expenditure 4, Consumer connection less capital contributions 7, a(iv): System Growth and Asset Replacement and Renewal ($000) ($000) 45 Subtransmission 1,142 2, Zone substations 3,537 1, Distribution and LV lines 1,367 5, Distribution and LV cables 359 4, Distribution substations and transformers 402 1, Distribution switchgear 47 1, Other network assets System growth and asset replacement and renewal expenditure 7,083 17, less Capital contributions funding system growth and asset replacement and renewal System growth and asset replacement and renewal less capital contributions 7,083 17, a(v): Asset Relocations 57 Project or programme* ($000) ($000) 58 Asset relocations 2, * include additional rows if needed 64 All other projects or programmes - asset relocations System Growth 65 Asset relocations expenditure 2, less Capital contributions funding asset relocations 1,660 Asset Replacement and Renewal 67 Asset relocations less capital contributions 1,060 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 21 S6a.Actual Expenditure Capex

22 SCHEDULE 6a: REPORT ON CAPITAL EXPENDITURE FOR THE DISCLOSURE YEAR This schedule requires a breakdown of capital expenditure on assets incurred in the disclosure year, including any assets in respect of which capital contributions are received, but excluding assets that are vested assets. Information on expenditure on assets must be provided on an accounting accruals basis and must exclude finance costs. EDBs must provide explanatory comment on their expenditure on assets in Schedule 14 (Explanatory Notes to Templates). This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section a(vi): Quality of Supply 70 Project or programme* ($000) ($000) 71 Sherenden Protection Upgrade * include additional rows if needed 77 All other projects programmes - quality of supply Quality of supply expenditure 1, less Capital contributions funding quality of supply 80 Quality of supply less capital contributions 1, a(vii): Legislative and Regulatory 82 Project or programme* ($000) ($000) * include additional rows if needed 89 All other projects or programmes - legislative and regulatory 90 Legislative and regulatory expenditure 91 less Capital contributions funding legislative and regulatory 92 Legislative and regulatory less capital contributions 93 6a(viii): Other Reliability, Safety and Environment 94 Project or programme* ($000) ($000) 95 Dynamic Line Rating * include additional rows if needed 101 All other projects or programmes - other reliability, safety and environment Other reliability, safety and environment expenditure less Capital contributions funding other reliability, safety and environment 104 Other reliability, safety and environment less capital contributions a(ix): Non-Network Assets 107 Routine expenditure 108 Project or programme* ($000) ($000) 109 Motor Vehicles 1, Plant, Equipment and Tools Information Technology 1, Office Furniture Land and Buildings 1, * include additional rows if needed 115 All other projects or programmes - routine expenditure 116 Routine expenditure 5, Atypical expenditure 118 Project or programme* ($000) ($000) * include additional rows if needed 125 All other projects or programmes - atypical expenditure 126 Atypical expenditure Expenditure on non-network assets 5,542 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 22 S6a.Actual Expenditure Capex

23 SCHEDULE 6b: REPORT ON OPERATIONAL EXPENDITURE FOR THE DISCLOSURE YEAR This schedule requires a breakdown of operational expenditure incurred in the disclosure year. EDBs must provide explanatory comment on their operational expenditure in Schedule 14 (Explanatory notes to templates). This includes explanatory comment on any atypical operational expenditure and assets replaced or renewed as part of asset replacement and renewal operational expenditure, and additional information on insurance. This information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section b(i): Operational Expenditure ($000) ($000) 8 Service interruptions and emergencies 3,262 9 Vegetation management 1, Routine and corrective maintenance and inspection 2, Asset replacement and renewal 1, Network opex 8, System operations and network support 7, Business support 19, Non-network opex 26, Operational expenditure 35, b(ii): Subcomponents of Operational Expenditure (where known) 19 Energy efficiency and demand side management, reduction of energy losses 20 Direct billing* 21 Research and development 22 Insurance 1, * Direct billing expenditure by suppliers that directly bill the majority of their consumers Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 23 S6b.Actual Expenditure Opex

24 SCHEDULE 7: COMPARISON OF FORECASTS TO ACTUAL EXPENDITURE This schedule compares actual revenue and expenditure to the previous forecasts that were made for the disclosure year. Accordingly, this schedule requires the forecast revenue and expenditure information from previous disclosures to be inserted. EDBs must provide explanatory comment on the variance between actual and target revenue and forecast expenditure in Schedule 14 (Mandatory Explanatory Notes). This information is part of the audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section 2.8. For the purpose of this audit, target revenue and forecast expenditures only need to be verified back to previous disclosures. 7 7(i): Revenue Target ($000) ¹ Actual ($000) % variance 8 Line charge revenue 147, ,431 1% 9 7(ii): Expenditure on Assets Forecast ($000) ² Actual ($000) % variance 10 Consumer connection 7,360 11,663 58% 11 System growth 8,387 7,083 (16%) 12 Asset replacement and renewal 14,767 17,404 18% 13 Asset relocations 1,382 2,720 97% 14 Reliability, safety and environment: 15 Quality of supply 436 1, % 16 Legislative and regulatory 61 (100%) 17 Other reliability, safety and environment 1, (27%) 18 Total reliability, safety and environment 1,505 1,779 18% 19 Expenditure on network assets 33,401 40,649 22% 20 Expenditure on non-network assets 7,947 5,542 (30%) 21 Expenditure on assets 41,348 46,191 12% 22 7(iii): Operational Expenditure 23 Service interruptions and emergencies 2,838 3,262 15% 24 Vegetation management 1,107 1,280 16% 25 Routine and corrective maintenance and inspection 2,692 2,511 (7%) 26 Asset replacement and renewal 1,526 1,610 5% 27 Network opex 8,163 8,663 6% 28 System operations and network support 6,891 7,600 10% 29 Business support 22,999 19,124 (17%) 30 Non-network opex 29,890 26,724 (11%) 31 Operational expenditure 38,053 35,386 (7%) 32 7(iv): Subcomponents of Expenditure on Assets (where known) 33 Energy efficiency and demand side management, reduction of energy losses 34 Overhead to underground conversion 1,759 2,084 18% 35 Research and development 512 (100%) (v): Subcomponents of Operational Expenditure (where known) 38 Energy efficiency and demand side management, reduction of energy losses 39 Direct billing 40 Research and development 41 Insurance 1,783 1,572 (12%) From the nominal dollar target revenue for the disclosure year disclosed under clause 2.4.3(3) of this determination 44 2 From the CY+1 nominal dollar expenditure forecasts disclosed in accordance with clause for the forecast period starting at the beginning of the disclosure year (the second to last disclosure of Schedules 11a and 11b) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 24 S7.Actual vs Forecast

25 SCHEDULE 8: REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES This schedule requires the billed quantities and associated line charge revenues for each price category code used by the EDB in its pricing schedules. Information is also required on the number of ICPs that are included in each consumer group or price category code, and the energy delivered to these ICPs. Network / Sub-Network Name 8 8(i): Billed Quantities by Price Component Billed quantities by price component Price component 24UC AICO CTRL CTUD NITE PROJ TAIC DEFT OFPK ONPK DMND KVAR RKVAR SOPD WOPD Fixed COAD T020 T030 T050 T075 T100 T150 DGNS DGEN DGNU UNMT 12 Energy delivered to ICPs Unit charging basis (eg, days, kw of demand, Consumer group name or price Consumer type or types (eg, Standard or non-standard Average no. of ICPs in in disclosure year kva of capacity, etc.) kwh kwh kwh kwh kwh kwh kwh kwh kwh kwh Demand kvar kvar Demand Demand Daily Daily Daily Daily Daily Daily Daily Daily Free Free Free kwh 13 category code residential, commercial etc.) consumer group (specify) disclosure year (MWh) Non Permanent Residential - DNR Residential Standard 3,765 12,909 6,338,409 4,750,491 1,168, , ,475 6,456 1,364,683 12,918 (1,044) 16 Distributed Generation - G11 Residential Standard ,649 41,507 2,005 1,758 11,548 65, Distributed Generation - G12 Residential Standard ,302 68,697 1,048 1,908 3,594 16, , Residential Low Fixed - M11 Residential Standard 42, , ,499,392 89,208,519 27,497,181 1,307,427 1,584, ,725 15,397,542 (8,836) 700,393 (1,205) 19 Residential - M12 Residential Standard 48, , ,480, ,607,520 46,219,576 3,677,388 3,668, ,128 17,290,827 (14,151) 692,283 (4,249) 20 Commercial - MC1 Commercial Standard 6, , ,077,174 2,191,166 15,079,026 7,421, ,548 7,494,553 26,138 4,061 14,422 10,021 2,438, ,095 1, (2,162) 102,097 (1,047) 21 Commercial - MC2 Commercial Standard ,674 44,857, ,341 3,024,807 1,246,190 29,698 27,053,247 82,304 8,569 43,446 34, ,099 4, , Commercial - MC3 Commercial Standard , ,305,628 8,706, ,161 40, , , , ,592 18,584 3, Commercial - MC5 Commercial Standard ,185 74,746, , ,853 27, ,408 97,803 38, ,190 17,369 2,920 1,095 Commercial - MC6 Commercial Standard 45 51,718 51,703,712 14, ,912 11,560 75,917 56,988 16, ,238 3, Commercial - MC7 Commercial Standard 17 22,363 21,965, ,135 60,543 2,136 33,249 23,384 6, , Commercial - MC8 Commercial Standard 23 32,547 32,547,497 98,788 5,678 53,649 37,672 8, ,095 4,745 1, Commercial - MC9 Commercial Standard 16 34,028 34,028,423 91,495 18,253 12,150 50,387 36,273 5, ,095 2,555 3, , General High User - NDH Commercial Standard 3,330 48,273 43,051,177 2,771,264 1,234, , ,644 19,664 1,179,293 34,151 General Low User - NDL Commercial Standard 5,105 11,981 10,904, , , , ,683 5,329 1,730,279 8,003 Temporary Supply - T1P Commercial Standard ,802 (1,543) 93,738 Temporary Supply - T3P Commercial Standard ,151 8,770 6,210 Residential TOU - TCU Commercial Standard ,673 5, Residential TOU - THU Residential Standard 1 8 2, ,749 1, General TOU - TLU Residential Standard 1 1 1, Unmetered - U01 Commercial Standard ,836 Unmetered - U02 Commercial Standard ,741 Unmetered - U03 Commercial Standard 17 12,629 9,769,064 12,628,922 Industrial - I60 Industrial Standard , ,707, ,355 23,004 2,786 18,677 Industrial - I60 Industrial Non-standard 12 49,359 49,359, ,194 34,649 14,373 7,224 Unison Commercial Standard , Add extra rows for additional consumer groups or price category codes as necessary 26 Standard consumer totals 111,830 1,533, ,370, ,037,555 78,988,826 24,337,354 14,787,518 1,493, ,692,108 9,556,027 20,501 6,848 1,548, ,228 14, , ,182 49,728,781 1,460 34,282 25,519 35,082 14,281 6,147 1,095 (25,149) 1,748,091 (7,545) 14,205, Non-standard consumer totals 12 49,359 49,359, ,194 34,649 14,373 7, Total for all consumers 111,842 1,582, ,370, ,037,555 78,988,826 24,337,354 14,787,518 1,493, ,051,412 9,556,027 20,501 6,848 1,724, ,877 29, , ,182 49,736,005 1,460 34,282 25,519 35,082 14,281 6,147 1,095 (25,149) 1,748,091 (7,545) 14,205,499 Add extra columns for additional billed quantities by price component as necessary Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 25 S8.Billed Quantities+Revenues

26 SCHEDULE 8: REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES This schedule requires the billed quantities and associated line charge revenues for each price category code used by the EDB in its pricing schedules. Information is also required on the number of ICPs that are included in each consumer group or price category code, and the energy delivered to these ICPs. Network / Sub-Network Name 31 8(ii): Line Charge Revenues ($000) by Price Component Line charge revenues ($000) by price component Price component 24UC AICO CTRL CTUD NITE PROJ TAIC DEFT OFPK ONPK DMND KVAR RKVAR SOPD WOPD Fixed COAD T020 T030 T050 T075 T100 T150 DGNS DGNU DGEN UNMT 34 Total transmission Notional revenue Total distribution line charge Rate (eg, $ per day, $ per kwh kwh kwh kwh kwh kwh kwh kwh kwh kwh Demand kvar kvar Demand Demand Daily Daily Daily Daily Daily Daily Daily Daily Free Free Free kwh Consumer group name or price Consumer type or types (eg, Standard or non-standard Total line charge revenue foregone from posted line charge revenue (if kwh, etc.) 35 category code residential, commercial etc.) consumer group (specify) in disclosure year discounts (if applicable) revenue available) Non Permanent Residential - DNR Residential Standard $2,958 $2,958 $565 $321 $42 $41 $9 $1 $1, Distributed Generation - G11 Residential Standard $25 $25 $17 $6 $2 39 Distributed Generation - G12 Residential Standard $58 $58 $23 $5 $30 40 Residential Low Fixed - M11 Residential Standard $29,665 $29,665 $14,295 $10,360 $2,357 $224 $76 $43 $2, Residential - M12 Residential Standard $51,306 $51,306 $17,333 $11,646 $1,833 $416 $117 $81 $19, Commercial - MC1 Commercial Standard $22,891 $22,891 $12,594 $68 $1,360 $178 $17 $1 $68 $28 $52 $100 $8,407 ($1) $5 $7 $6 $1 43 Commercial - MC2 Commercial Standard $6,252 $6,252 $3,176 $14 $275 $30 $2 $217 $65 $163 $347 $1,934 $24 $2 $3 44 Commercial - MC3 Commercial Standard $6,610 $6,610 $768 $963 $309 $707 $1,407 $2,171 ($1) $133 $124 $29 45 Commercial - MC5 Commercial Standard $3,582 $3,582 $39 $618 $211 $456 $971 $1,073 $4 $14 $151 $31 $14 Commercial - MC6 Commercial Standard $1,974 $1,974 $1 $368 $87 $274 $556 $562 $2 $71 $39 $9 $5 Commercial - MC7 Commercial Standard $841 $841 $36 $163 $16 $118 $224 $246 ($1) $6 $28 $5 Commercial - MC8 Commercial Standard $1,381 $1,381 $263 $43 $196 $370 $422 $2 $9 $52 $19 $5 Commercial - MC9 Commercial Standard $1,239 $1,239 $244 $138 ($91) $183 $356 $320 $5 $17 $28 $4 $30 $5 General High User - NDH Commercial Standard $5,695 $5,695 $3,906 $267 $67 $83 $14 $2 $1,356 General Low User - NDL Commercial Standard $3,434 $3,434 $759 $43 $7 $15 $3 $2,607 Temporary Supply - T1P Commercial Standard $151 $151 $35 $116 Temporary Supply - T3P Commercial Standard $60 $60 $35 $1 $24 General TOU - TCU Commercial Standard $2 $2 $1 $1 Residential TOU - THU Residential Standard Residential TOU - TLU Residential Standard Unmetered - U01 Commercial Standard $113 $113 $113 Unmetered - U02 Commercial Standard $88 $88 $88 Unmetered - U03 Commercial Standard $1,540 $1,540 $742 $798 Industrial - I60 Industrial Standard $5,990 $5,990 $167 ($21) $5,844 Industrial - I60 Industrial Non-standard $2,576 $2,576 $262 ($109) $2,423 Unison Commercial Standard Add extra rows for additional consumer groups or price category codes as necessary 48 Standard consumer totals $145,855 $145,855 $52,738 $22,648 $4,388 $2,414 $427 $147 $845 $1 $1 $2,904 $1,064 ($112) $2,149 $4,331 $50,025 ($3) $171 $168 $303 $154 $78 $15 $ Non-standard consumer totals $2,576 $2,576 $262 ($109) $2, Total for all consumers $148,431 $148,431 $52,738 $22,648 $4,388 $2,414 $427 $147 $845 $1 $1 $2,904 $1,326 ($221) $2,149 $4,331 $52,448 ($3) $171 $168 $303 $154 $78 $15 $ (iii): Number of ICPs directly billed Check OK 53 Number of directly billed ICPs at year end 8 Add extra columns for additional line charge revenues by price component as necessary Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 26 S8.Billed Quantities+Revenues

27 SCHEDULE 8: REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES This schedule requires the billed quantities and associated line charge revenues for each price category code used by the EDB in its pricing schedules. Information is also required on the number of ICPs that are included in each consumer group or price category code, and the energy delivered to these ICPs. Network / Sub-Network Name Hawke's Bay 8 8(i): Billed Quantities by Price Component Billed quantities by price component Price component 24UC AICO CTRL CTUD NITE PROJ TAIC DEFT OFPK ONPK DMND KVAR RKVAR SOPD WOPD Fixed COAD T020 T030 T050 T075 T100 T150 DGNS DGEN DGNU UNMT 12 Energy delivered to ICPs Unit charging basis (eg, days, kw of demand, Consumer group name or price Consumer type or types (eg, Standard or non-standard Average no. of ICPs in in disclosure year kva of capacity, etc.) kwh kwh kwh kwh kwh kwh kwh kwh kwh kwh Demand kvar kvar Demand Demand Daily Daily Daily Daily Daily Daily Daily Daily Free Free Free kwh 13 category code residential, commercial etc.) consumer group (specify) disclosure year (MWh) Non Permanent Residential - DNR Residential Standard 536 1,951 1,167, , , , ,899 1, Distributed Generation - G11 Residential Standard ,509 28,449 1,755 1,207 8,260 48, Distributed Generation - G12 Residential Standard ,824 48, (473) ,587 86, Residential Low Fixed - M11 Residential Standard 24, ,399 60,178,100 44,967,416 20,839,980 8, , ,771 8,792,896 (6,347) 486, Residential - M12 Residential Standard 28, , ,450,676 95,020,183 31,840, , , ,256 10,340,238 (10,025) 539, Commercial - MC1 Commercial Standard 2,942 96,247 86,781, ,548 3,468,132 1,453, ,335 3,883,196 14,557 1,305 7,878 5,470 1,034, , (2,162) 58, Commercial - MC2 Commercial Standard ,214 23,696,587 50, , ,947 10,901 11,073,949 33,176 2,815 16,909 14, ,585 2, Commercial - MC3 Commercial Standard ,789 74,074,711 3,714, ,516 31, , ,268 82,077 17,884 12,775 3, Commercial - MC5 Commercial Standard 54 36,219 35,924, , ,955 13,976 63,689 51,519 19,305 6,570 1, Commercial - MC6 Commercial Standard 30 36,169 36,154,513 14,334 99,128 7,448 55,075 40,586 10, ,588 3, Commercial - MC7 Commercial Standard 16 20,959 20,562, ,135 54,711 2,136 29,935 20,929 5, , Commercial - MC8 Commercial Standard 12 22,256 22,256,414 62,137 3,568 33,255 24,176 4, ,190 1, Commercial - MC9 Commercial Standard 10 25,811 25,810,639 60,506 2,036 33,762 23,676 3, , , General High User - NDH Commercial Standard 2,214 31,656 27,828,578 2,722, , , ,851 15, ,012 28,145 General Low User - NDL Commercial Standard 3,549 8,530 7,568, , , ,155 89,415 4,199 1,207,593 8,003 Temporary Supply - T1P Commercial Standard , ,151 Temporary Supply - T3P Commercial Standard ,063 4,478 Residential TOU - TCU Commercial Standard Residential TOU - THU Residential Standard General TOU - TLU Residential Standard 1 1 1, Unmetered - U01 Commercial Standard ,531 Unmetered - U02 Commercial Standard ,960 Unmetered - U03 Commercial Standard 8 7,472 6,040,167 7,471,855 Industrial - I60 Industrial Standard , ,633, ,583 12,578 2,786 14,662 Industrial - I60 Industrial Non-standard 4 15,102 15,102,486 62,392 18,967 2,190 Unison Commercial Standard Add extra rows for additional consumer groups or price category codes as necessary 26 Standard consumer totals 63, , ,135, ,983,262 54,252,819 4,946,748 2,776,024 1,015, ,373,138 4,419,976 1, ,037,269 77,680 2, , ,166 28,717, ,899 14,600 16,587 9,536 4,216 1,095 (18,534) 1,258,463 8,568, Non-standard consumer totals 4 15,102 15,102,486 62,392 18,967 2, Total for all consumers 63, , ,135, ,983,262 54,252,819 4,946,748 2,776,024 1,015, ,475,624 4,419,976 1, ,099,660 96,647 2, , ,166 28,719, ,899 14,600 16,587 9,536 4,216 1,095 (18,534) 1,258,463 8,568,346 Add extra columns for additional billed quantities by price component as necessary Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 27 S8a.Billed Q+Rev Hawkes Bay

28 SCHEDULE 8: REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES This schedule requires the billed quantities and associated line charge revenues for each price category code used by the EDB in its pricing schedules. Information is also required on the number of ICPs that are included in each consumer group or price category code, and the energy delivered to these ICPs. Network / Sub-Network Name Hawke's Bay 31 8(ii): Line Charge Revenues ($000) by Price Component Line charge revenues ($000) by price component Price component 24UC AICO CTRL CTUD NITE PROJ TAIC DEFT OFPK ONPK DMND KVAR RKVAR SOPD WOPD Fixed COAD T020 T030 T050 T075 T100 T150 DGNS DGNU DGEN UNMT 34 Total transmission Notional revenue Total distribution line charge Rate (eg, $ per day, $ per kwh kwh kwh kwh kwh kwh kwh kwh kwh kwh Demand kvar kvar Demand Demand Daily Daily Daily Daily Daily Daily Daily Daily Free Free Free kwh Consumer group name or price Consumer type or types (eg, Standard or non-standard Total line charge revenue foregone from posted line charge revenue (if kwh, etc.) 35 category code residential, commercial etc.) consumer group (specify) in disclosure year discounts (if applicable) revenue available) Non Permanent Residential - DNR Residential Standard $445 $445 $112 $46 $7 $ Distributed Generation - G11 Residential Standard $16 $16 $11 $4 $1 39 Distributed Generation - G12 Residential Standard $40 $40 $15 $4 $21 40 Residential Low Fixed - M11 Residential Standard $17,119 $17,119 $8,534 $5,405 $1,816 $2 $10 $33 $1, Residential - M12 Residential Standard $31,422 $31,422 $11,033 $7,085 $1,323 $13 $18 $60 $11, Commercial - MC1 Commercial Standard $10,707 $10,707 $6,595 $16 $340 $40 $10 $37 $10 $28 $52 $3,570 ($1) $5 $2 $3 43 Commercial - MC2 Commercial Standard $3,179 $3,179 $1,801 $2 $93 $11 $1 $90 $21 $59 $138 $950 $13 44 Commercial - MC3 Commercial Standard $4,340 $4,340 $335 $706 $240 $503 $1,000 $1,354 $89 $85 $28 45 Commercial - MC5 Commercial Standard $1,763 $1,763 $26 $332 $106 $223 $489 $513 $57 $12 $5 Commercial - MC6 Commercial Standard $1,358 $1,358 $1 $268 $56 $193 $386 $359 $2 $40 $39 $9 $5 Commercial - MC7 Commercial Standard $768 $768 $36 $148 $16 $105 $199 $230 ($1) $6 $24 $5 Commercial - MC8 Commercial Standard $799 $799 $168 $27 $116 $230 $209 $6 $24 $14 $5 Commercial - MC9 Commercial Standard $751 $751 $163 $15 $118 $225 $188 $2 $7 $3 $4 $21 $5 General High User - NDH Commercial Standard $3,883 $3,883 $2,643 $261 $39 $34 $5 $1 $900 General Low User - NDL Commercial Standard $2,438 $2,438 $552 $42 $5 $14 $2 $1,823 Temporary Supply - T1P Commercial Standard $82 $82 $14 $68 Temporary Supply - T3P Commercial Standard $26 $26 $9 $17 General TOU - TCU Commercial Standard Residential TOU - THU Residential Standard Residential TOU - TLU Residential Standard Unmetered - U01 Commercial Standard $65 $65 $65 Unmetered - U02 Commercial Standard $71 $71 $71 Unmetered - U03 Commercial Standard $922 $922 $459 $463 Industrial - I60 Industrial Standard $4,588 $4,588 $94 ($21) $4,515 Industrial - I60 Industrial Non-standard $908 $908 $143 $765 Unison Commercial Standard Add extra rows for additional consumer groups or price category codes as necessary 48 Standard consumer totals $84,782 $84,782 $31,319 $12,847 $3,208 $496 $86 $105 $398 $1,912 $585 ($21) $1,345 $2,719 $28,666 ($2) $109 $96 $143 $103 $54 $15 $ Non-standard consumer totals $908 $908 $143 $ Total for all consumers $85,690 $85,690 $31,319 $12,847 $3,208 $496 $86 $105 $398 $1,912 $728 ($21) $1,345 $2,719 $29,431 ($2) $109 $96 $143 $103 $54 $15 $ (iii): Number of ICPs directly billed Check OK 53 Number of directly billed ICPs at year end 4 Add extra columns for additional line charge revenues by price component as necessary Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 28 S8a.Billed Q+Rev Hawkes Bay

29 SCHEDULE 8: REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES This schedule requires the billed quantities and associated line charge revenues for each price category code used by the EDB in its pricing schedules. Information is also required on the number of ICPs that are included in each consumer group or price category code, and the energy delivered to these ICPs. Network / Sub-Network Name Rotorua / Taupo 8 8(i): Billed Quantities by Price Component Billed quantities by price component Price component 24UC AICO CTRL CTUD NITE PROJ TAIC DEFT OFPK ONPK DMND KVAR RKVAR SOPD WOPD Fixed COAD T020 T030 T050 T075 T100 T150 DGNS DGEN DGNU UNMT 12 Energy delivered to ICPs Unit charging basis (eg, days, kw of demand, Consumer group name or price Consumer type or types (eg, Standard or non-standard Average no. of ICPs in in disclosure year kva of capacity, etc.) kwh kwh kwh kwh kwh kwh kwh kwh kwh kwh Demand kvar kvar Demand Demand Daily Daily Daily Daily Daily Daily Daily Daily Free Free Free kwh 13 category code residential, commercial etc.) consumer group (specify) disclosure year (MWh) Non Permanent Residential - DNR Residential Standard 3,229 10,958 5,171,254 4,128,431 1,008, , ,200 3,929 1,171,784 10,998 (1,044) 16 Distributed Generation - G11 Residential Standard ,141 13, ,288 17, Distributed Generation - G12 Residential Standard ,478 20, ,381 2,971 5,394 32, Residential Low Fixed - M11 Residential Standard 18,237 97,008 43,321,292 44,241,103 6,657,201 1,298,452 1,404,781 84,954 6,604,646 (2,489) 213,577 (1,205) 19 Residential - M12 Residential Standard 19, ,984 72,029,784 68,587,336 14,378,718 3,571,318 3,185, ,872 6,950,589 (4,126) 153,139 (4,249) 20 Commercial - MC1 Commercial Standard 3, ,271 92,295,705 1,661,618 11,610,893 5,967, ,213 3,611,357 11,581 2,756 6,544 4,551 1,403, ,368 (1,047) 21 Commercial - MC2 Commercial Standard ,461 21,161, ,668 2,071, ,244 18,797 15,979,298 49,129 5,754 26,537 20, ,514 2, , Commercial - MC3 Commercial Standard ,221 31,230,917 4,991,881 98,645 9,151 52,238 39,148 44, ,708 5, Commercial - MC5 Commercial Standard 54 38,966 38,821, , ,897 14,021 59,718 46,284 19, ,190 10,799 1, Commercial - MC6 Commercial Standard 15 15,549 15,549,199 38,784 4,113 20,841 16,402 5,475 3,650 Commercial - MC7 Commercial Standard 1 1,404 1,403,864 5,832 3,314 2, Commercial - MC8 Commercial Standard 11 10,291 10,291,083 36,651 2,111 20,394 13,496 4, , Commercial - MC9 Commercial Standard 6 8,218 8,217,784 30,989 16,218 12,150 16,625 12,597 2, ,460 2, General High User - NDH Commercial Standard 1,116 16,617 15,222,599 48, , , ,793 3, ,281 6,006 General Low User - NDL Commercial Standard 1,556 3,451 3,336,860 15,677 57,894 9,697 29,268 1, ,686 Temporary Supply - T1P Commercial Standard ,609 (1,597) 38,587 Temporary Supply - T3P Commercial Standard ,088 8,770 1,732 Residential TOU - TCU Commercial Standard ,673 5, Residential TOU - THU Residential Standard 1 8 2, ,749 1, General TOU - TLU Residential Standard Unmetered - U01 Commercial Standard ,305 Unmetered - U02 Commercial Standard ,781 Unmetered - U03 Commercial Standard 9 5,157 3,728,897 5,157,067 Industrial - I60 Industrial Standard 10 55, ,073, ,771 10,426 4,015 Industrial - I60 Industrial Non-standard 8 34,256 34,256, ,803 15,682 14,373 5,034 Unison Commercial Standard , Add extra rows for additional consumer groups or price category codes as necessary 26 Standard consumer totals 48, , ,235, ,054,293 24,736,007 19,390,605 12,011, , ,318,970 5,136,051 19,422 6, ,279 64,549 12, , ,016 21,011, ,383 10,919 18,495 4,745 1,931 (6,615) 489,628 (7,545) 5,637, Non-standard consumer totals 8 34,256 34,256, ,803 15,682 14,373 5, Total for all consumers 48, , ,235, ,054,293 24,736,007 19,390,605 12,011, , ,575,788 5,136,051 19,422 6, ,082 80,230 26, , ,016 21,016, ,383 10,919 18,495 4,745 1,931 (6,615) 489,628 (7,545) 5,637,153 Add extra columns for additional billed quantities by price component as necessary Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 29 S8b.Billed Q+Rev RotoTaupo

30 SCHEDULE 8: REPORT ON BILLED QUANTITIES AND LINE CHARGE REVENUES This schedule requires the billed quantities and associated line charge revenues for each price category code used by the EDB in its pricing schedules. Information is also required on the number of ICPs that are included in each consumer group or price category code, and the energy delivered to these ICPs. Network / Sub-Network Name Rotorua / Taupo 31 8(ii): Line Charge Revenues ($000) by Price Component Line charge revenues ($000) by price component Price component 24UC AICO CTRL CTUD NITE PROJ TAIC DEFT OFPK ONPK DMND KVAR RKVAR SOPD WOPD Fixed COAD T020 T030 T050 T075 T100 T150 DGNS DGNU DGEN UNMT 34 Total transmission Notional revenue Total distribution line charge Rate (eg, $ per day, $ per kwh kwh kwh kwh kwh kwh kwh kwh kwh kwh Demand kvar kvar Demand Demand Daily Daily Daily Daily Daily Daily Daily Daily Free Free Free kwh Consumer group name or price Consumer type or types (eg, Standard or non-standard Total line charge revenue foregone from posted line charge revenue (if kwh, etc.) 35 category code residential, commercial etc.) consumer group (specify) in disclosure year discounts (if applicable) revenue available) Non Permanent Residential - DNR Residential Standard $2,513 $2,513 $453 $275 $36 $41 $9 $1, Distributed Generation - G11 Residential Standard $8 $8 $6 $2 39 Distributed Generation - G12 Residential Standard $17 $17 $7 $1 $9 40 Residential Low Fixed - M11 Residential Standard $12,544 $12,544 $5,761 $4,955 $539 $221 $66 $11 $ Residential - M12 Residential Standard $19,887 $19,887 $6,302 $4,561 $510 $403 $99 $20 $7, Commercial - MC1 Commercial Standard $12,189 $12,189 $5,999 $52 $1,020 $138 $9 $30 $22 $25 $47 $4,838 $5 $3 $1 43 Commercial - MC2 Commercial Standard $3,072 $3,072 $1,375 $13 $182 $19 $1 $128 $43 $103 $209 $983 $11 $2 $3 44 Commercial - MC3 Commercial Standard $2,266 $2,266 $434 $256 $69 $204 $407 $816 ($1) $43 $38 45 Commercial - MC5 Commercial Standard $1,819 $1,819 $13 $286 $106 $233 $481 $560 $4 $14 $93 $20 $9 Commercial - MC6 Commercial Standard $618 $618 $101 $31 $81 $171 $202 $32 Commercial - MC7 Commercial Standard $74 $74 $15 $13 $26 $16 $4 Commercial - MC8 Commercial Standard $582 $582 $95 $16 $80 $140 $213 $2 $3 $27 $6 Commercial - MC9 Commercial Standard $487 $487 $81 $122 ($91) $65 $131 $131 $4 $10 $25 $9 General High User - NDH Commercial Standard $1,811 $1,811 $1,263 $6 $28 $49 $9 $456 General Low User - NDL Commercial Standard $996 $996 $207 $1 $2 $1 $1 $784 Temporary Supply - T1P Commercial Standard $69 $69 $21 $48 Temporary Supply - T3P Commercial Standard $33 $33 $25 $1 $7 General TOU - TCU Commercial Standard $2 $2 $1 $1 Residential TOU - THU Residential Standard Residential TOU - TLU Residential Standard Unmetered - U01 Commercial Standard $48 $48 $48 Unmetered - U02 Commercial Standard $17 $17 $17 Unmetered - U03 Commercial Standard $618 $618 $283 $335 Industrial - I60 Industrial Standard $1,401 $1,401 $72 $1,329 Industrial - I60 Industrial Non-standard $1,667 $1,667 $118 ($109) $1,658 Unison Commercial Standard 46 [Select one] 47 Add extra rows for additional consumer groups or price category codes as necessary 48 Standard consumer totals $61,071 $61,071 $21,419 $9,801 $1,180 $1,917 $341 $42 $447 $1 $1 $992 $481 ($91) $804 $1,612 $21,357 ($1) $62 $71 $159 $51 $25 $ Non-standard consumer totals $1,667 $1,667 $118 ($109) $1, Total for all consumers $62,738 $62,738 $21,419 $9,801 $1,180 $1,917 $341 $42 $447 $1 $1 $992 $599 ($200) $804 $1,612 $23,015 ($1) $62 $71 $159 $51 $25 $ (iii): Number of ICPs directly billed Check OK 53 Number of directly billed ICPs at year end 4 Add extra columns for additional line charge revenues by price component as necessary Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 30 S8b.Billed Q+Rev RotoTaupo

31 SCHEDULE 9a: ASSET REGISTER Network / Sub-network Name This schedule requires a summary of the quantity of assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. 8 Voltage Asset category Asset class Units Items at start of year (quantity) Items at end of year (quantity) Net change 9 All Overhead Line Concrete poles / steel structure No. 36,302 37, All Overhead Line Wood poles No. 27,395 27, All Overhead Line Other pole types No HV Subtransmission Line Subtransmission OH up to 66kV conductor km (1) 4 13 HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 14 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km 4 17 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 19 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 22 HV Subtransmission Cable Subtransmission submarine cable km N/A 23 HV Zone substation Buildings Zone substations up to 66kV No HV Zone substation Buildings Zone substations 110kV+ No. N/A 25 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 26 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. N/A 27 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. N/A 28 HV Zone substation switchgear 33kV Switch (Pole Mounted) No HV Zone substation switchgear 33kV RMU No. N/A 30 HV Zone substation switchgear 22/33kV CB (Indoor) No HV Zone substation switchgear 22/33kV CB (Outdoor) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No HV Zone Substation Transformer Zone Substation Transformers No HV Distribution Line Distribution OH Open Wire Conductor km 3,774 3, HV Distribution Line Distribution OH Aerial Cable Conductor km HV Distribution Line SWER conductor km (11) 4 38 HV Distribution Cable Distribution UG XLPE or PVC km HV Distribution Cable Distribution UG PILC km (3) 3 40 HV Distribution Cable Distribution Submarine Cable km N/A 41 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No. 9 8 (1) 4 43 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No. 10,576 10, HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No (2) 4 45 HV Distribution switchgear 3.3/6.6/11/22kV RMU No HV Distribution Transformer Pole Mounted Transformer No. 6,622 6, HV Distribution Transformer Ground Mounted Transformer No. 2,844 2, HV Distribution Transformer Voltage regulators No HV Distribution Substations Ground Mounted Substation Housing No LV LV Line LV OH Conductor km 1,244 1,242 (2) 3 51 LV LV Cable LV UG Cable km 2,612 2, LV LV Street lighting LV OH/UG Streetlight circuit km 1,672 1, LV Connections OH/UG consumer service connections No. 110, , All Protection Protection relays (electromechanical, solid state and numeric) No All SCADA and communications SCADA and communications equipment operating as a single system Lot All Capacitor Banks Capacitors including controls No All Load Control Centralised plant Lot (1) 4 58 All Load Control Relays No 4,881 4, All Civils Cable Tunnels km N/A Data accuracy (1 4) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 31 S9a.Asset Register

32 SCHEDULE 9a: ASSET REGISTER Network / Sub-network Name Hawke's Bay This schedule requires a summary of the quantity of assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. 8 Voltage Asset category Asset class Units Items at start of year (quantity) Items at end of year (quantity) Net change Data accuracy (1 4) 9 All Overhead Line Concrete poles / steel structure No , All Overhead Line Wood poles No ,760 (32) 3 11 All Overhead Line Other pole types No HV Subtransmission Line Subtransmission OH up to 66kV conductor km (1) 4 13 HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 14 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km 4 17 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 19 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 22 HV Subtransmission Cable Subtransmission submarine cable km N/A 23 HV Zone substation Buildings Zone substations up to 66kV No HV Zone substation Buildings Zone substations 110kV+ No. N/A 25 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 26 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. N/A 27 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. N/A 28 HV Zone substation switchgear 33kV Switch (Pole Mounted) No HV Zone substation switchgear 33kV RMU No. N/A 30 HV Zone substation switchgear 22/33kV CB (Indoor) No HV Zone substation switchgear 22/33kV CB (Outdoor) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No HV Zone Substation Transformer Zone Substation Transformers No HV Distribution Line Distribution OH Open Wire Conductor km ,002 (6) 3 36 HV Distribution Line Distribution OH Aerial Cable Conductor km (0) 3 37 HV Distribution Line SWER conductor km HV Distribution Cable Distribution UG XLPE or PVC km HV Distribution Cable Distribution UG PILC km (2) 3 40 HV Distribution Cable Distribution Submarine Cable km 0 N/A 41 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No. 8 7 (1) 4 43 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No , HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No (1) 4 45 HV Distribution switchgear 3.3/6.6/11/22kV RMU No HV Distribution Transformer Pole Mounted Transformer No , HV Distribution Transformer Ground Mounted Transformer No , HV Distribution Transformer Voltage regulators No HV Distribution Substations Ground Mounted Substation Housing No LV LV Line LV OH Conductor km (5) 3 51 LV LV Cable LV UG Cable km 1,980 1, LV LV Street lighting LV OH/UG Streetlight circuit km 997 1, LV Connections OH/UG consumer service connections No , All Protection Protection relays (electromechanical, solid state and numeric) No All SCADA and communications SCADA and communications equipment operating as a single system Lot All Capacitor Banks Capacitors including controls No All Load Control Centralised plant Lot All Load Control Relays No , All Civils Cable Tunnels km 0 N/A

33 SCHEDULE 9a: ASSET REGISTER Network / Sub-network Name Central Region This schedule requires a summary of the quantity of assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. 8 Voltage Asset category Asset class Units Items at start of year (quantity) Items at end of year (quantity) Net change Data accuracy (1 4) 9 All Overhead Line Concrete poles / steel structure No , All Overhead Line Wood poles No , All Overhead Line Other pole types No HV Subtransmission Line Subtransmission OH up to 66kV conductor km (0) 4 13 HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 14 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km 4 17 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km 4 18 HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 19 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 22 HV Subtransmission Cable Subtransmission submarine cable km N/A 23 HV Zone substation Buildings Zone substations up to 66kV No HV Zone substation Buildings Zone substations 110kV+ No. N/A 25 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 26 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. N/A 27 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. N/A 28 HV Zone substation switchgear 33kV Switch (Pole Mounted) No HV Zone substation switchgear 33kV RMU No. N/A 30 HV Zone substation switchgear 22/33kV CB (Indoor) No HV Zone substation switchgear 22/33kV CB (Outdoor) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No HV Zone Substation Transformer Zone Substation Transformers No HV Distribution Line Distribution OH Open Wire Conductor km 1, , HV Distribution Line Distribution OH Aerial Cable Conductor km HV Distribution Line SWER conductor km (11) 4 38 HV Distribution Cable Distribution UG XLPE or PVC km HV Distribution Cable Distribution UG PILC km (1) 3 40 HV Distribution Cable Distribution Submarine Cable km 0.00 N/A 41 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No , HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No (1) 4 45 HV Distribution switchgear 3.3/6.6/11/22kV RMU No HV Distribution Transformer Pole Mounted Transformer No , HV Distribution Transformer Ground Mounted Transformer No , HV Distribution Transformer Voltage regulators No HV Distribution Substations Ground Mounted Substation Housing No LV LV Line LV OH Conductor km LV LV Cable LV UG Cable km LV LV Street lighting LV OH/UG Streetlight circuit km LV Connections OH/UG consumer service connections No , All Protection Protection relays (electromechanical, solid state and numeric) No All SCADA and communications SCADA and communications equipment operating as a single system Lot All Capacitor Banks Capacitors including controls No All Load Control Centralised plant Lot (1) 4 58 All Load Control Relays No (2) 2 59 All Civils Cable Tunnels km 0 N/A

34 SCHEDULE 9b: ASSET AGE PROFILE This schedule requires a summary of the age profile (based on year of installation) of the assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. Network / Sub-network Name 8 Disclosure Year (year ended) Number of assets at disclosure year end by installation date No. with Items at No. with age end of default Data accuracy 9 Voltage Asset category Asset class Units pre unknown year dates (1 4) 10 All Overhead Line Concrete poles / steel structure No ,099 5,174 11,941 4, ,323 1, , , All Overhead Line Wood poles No ,363 7,843 3,429 6, , All Overhead Line Other pole types No HV Subtransmission Line Subtransmission OH up to 66kV conductor km HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 17 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km 4 18 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 22 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 23 HV Subtransmission Cable Subtransmission submarine cable km N/A 24 HV Zone substation Buildings Zone substations up to 66kV No HV Zone substation Buildings Zone substations 110kV+ No. N/A 26 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 27 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. N/A 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. N/A 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No HV Zone substation switchgear 33kV RMU No. N/A 31 HV Zone substation switchgear 22/33kV CB (Indoor) No HV Zone substation switchgear 22/33kV CB (Outdoor) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No HV Zone Substation Transformer Zone Substation Transformers No HV Distribution Line Distribution OH Open Wire Conductor km , HV Distribution Line Distribution OH Aerial Cable Conductor km HV Distribution Line SWER conductor km HV Distribution Cable Distribution UG XLPE or PVC km HV Distribution Cable Distribution UG PILC km HV Distribution Cable Distribution Submarine Cable km N/A 42 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No ,259 1,557 2,309 1, , HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No HV Distribution switchgear 3.3/6.6/11/22kV RMU No HV Distribution Transformer Pole Mounted Transformer No ,457 1, , HV Distribution Transformer Ground Mounted Transformer No , HV Distribution Transformer Voltage regulators No HV Distribution Substations Ground Mounted Substation Housing No LV LV Line LV OH Conductor km , LV LV Cable LV UG Cable km , , LV LV Street lighting LV OH/UG Streetlight circuit km , LV Connections OH/UG consumer service connections No ,622 27,237 7,193 52,627 1,887 1,511 1,684 1,361 1,396 1,769 1,560 1,529 1,145 1,051 1, , All Protection Protection relays (electromechanical, solid state and numeric) No All SCADA and communications SCADA and communications equipment operating as a single system Lot All Capacitor Banks Capacitors including controls No All Load Control Centralised plant Lot All Load Control Relays No , , All Civils Cable Tunnels km 4 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 34 S9b.Asset Age Profile

35 SCHEDULE 9b: ASSET AGE PROFILE This schedule requires a summary of the age profile (based on year of installation) of the assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. 8 Disclosure Year (year ended) 9 Voltage Asset category Asset class Units pre Number of assets at disclosure year end by installation date Network / Sub-network Name All Overhead Line Concrete poles / steel structure No , All Overhead Line Wood poles No , All Overhead Line Other pole types No HV Subtransmission Line Subtransmission OH up to 66kV conductor km HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 17 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km 4 18 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 22 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 23 HV Subtransmission Cable Subtransmission submarine cable km N/A 24 HV Zone substation Buildings Zone substations up to 66kV No HV Zone substation Buildings Zone substations 110kV+ No. N/A 26 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 27 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. N/A 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. N/A 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No HV Zone substation switchgear 33kV RMU No. N/A 31 HV Zone substation switchgear 22/33kV CB (Indoor) No HV Zone substation switchgear 22/33kV CB (Outdoor) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No HV Zone Substation Transformer Zone Substation Transformers No HV Distribution Line Distribution OH Open Wire Conductor km , HV Distribution Line Distribution OH Aerial Cable Conductor km HV Distribution Line SWER conductor km HV Distribution Cable Distribution UG XLPE or PVC km HV Distribution Cable Distribution UG PILC km HV Distribution Cable Distribution Submarine Cable km N/A 42 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No , HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No HV Distribution switchgear 3.3/6.6/11/22kV RMU No HV Distribution Transformer Pole Mounted Transformer No , HV Distribution Transformer Ground Mounted Transformer No , HV Distribution Transformer Voltage regulators No HV Distribution Substations Ground Mounted Substation Housing No LV LV Line LV OH Conductor km LV LV Cable LV UG Cable km , LV LV Street lighting LV OH/UG Streetlight circuit km , LV Connections OH/UG consumer service connections No , All Protection Protection relays (electromechanical, solid state and numeric) No All SCADA and communications SCADA and communications equipment operating as a single system Lot All Capacitor Banks Capacitors including controls No All Load Control Centralised plant Lot All Load Control Relays No , All Civils Cable Tunnels km N/A No. with age unknown Hawke's Bay Items at end of year No. with default dates Data accuracy (1 4)

36 SCHEDULE 9b: ASSET AGE PROFILE This schedule requires a summary of the age profile (based on year of installation) of the assets that make up the network, by asset category and asset class. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. 8 Disclosure Year (year ended) 9 Voltage Asset category Asset class Units pre Number of assets at disclosure year end by installation date Network / Sub-network Name All Overhead Line Concrete poles / steel structure No , All Overhead Line Wood poles No , All Overhead Line Other pole types No HV Subtransmission Line Subtransmission OH up to 66kV conductor km HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 17 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km 4 18 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km 4 19 HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 22 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 23 HV Subtransmission Cable Subtransmission submarine cable km N/A 24 HV Zone substation Buildings Zone substations up to 66kV No HV Zone substation Buildings Zone substations 110kV+ No. N/A 26 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 27 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. N/A 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. N/A 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No HV Zone substation switchgear 33kV RMU No. N/A 31 HV Zone substation switchgear 22/33kV CB (Indoor) No HV Zone substation switchgear 22/33kV CB (Outdoor) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No HV Zone Substation Transformer Zone Substation Transformers No HV Distribution Line Distribution OH Open Wire Conductor km , HV Distribution Line Distribution OH Aerial Cable Conductor km HV Distribution Line SWER conductor km HV Distribution Cable Distribution UG XLPE or PVC km HV Distribution Cable Distribution UG PILC km HV Distribution Cable Distribution Submarine Cable km N/A 42 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No , HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No HV Distribution switchgear 3.3/6.6/11/22kV RMU No HV Distribution Transformer Pole Mounted Transformer No , HV Distribution Transformer Ground Mounted Transformer No , HV Distribution Transformer Voltage regulators No HV Distribution Substations Ground Mounted Substation Housing No LV LV Line LV OH Conductor km LV LV Cable LV UG Cable km LV LV Street lighting LV OH/UG Streetlight circuit km LV Connections OH/UG consumer service connections No , All Protection Protection relays (electromechanical, solid state and numeric) No All SCADA and communications SCADA and communications equipment operating as a single system Lot All Capacitor Banks Capacitors including controls No 4 58 All Load Control Centralised plant Lot All Load Control Relays No All Civils Cable Tunnels km N/A No. with age unknown Central Region Items at end of year No. with default dates Data accuracy (1 4)

37 Network / Sub-network Name SCHEDULE 9c: REPORT ON OVERHEAD LINES AND UNDERGROUND CABLES This schedule requires a summary of the key characteristics of the overhead line and underground cable network. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths Circuit length by operating voltage (at year end) Overhead (km) Underground (km) Total circuit length (km) 11 > 66kV 12 50kV & 66kV 13 33kV SWER (all SWER voltages) kV (other than SWER) kV to 11kV (inclusive other than SWER) 3, , Low voltage (< 1kV) 1,242 2,743 3, Total circuit length (for supply) 5,569 3,613 9, Dedicated street lighting circuit length (km) 367 1,317 1, Circuit in sensitive areas (conservation areas, iwi territory etc) (km) 1, Overhead circuit length by terrain (at year end) Circuit length (km) (% of total overhead length) 24 Urban 1,175 21% 25 Rural 1,185 21% 26 Remote only 245 4% 27 Rugged only 2,651 48% 28 Remote and rugged 29 Unallocated overhead lines 314 6% 30 Total overhead length 5, % Circuit length (km) (% of total circuit length) 33 Length of circuit within 10km of coastline or geothermal areas (where known) 3,666 40% 34 Circuit length (km) (% of total overhead length) 35 Overhead circuit requiring vegetation management 5, % Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 37 S9c.Overhead Lines

38 Network / Sub-network Name SCHEDULE 9c: REPORT ON OVERHEAD LINES AND UNDERGROUND CABLES Hawke's Bay This schedule requires a summary of the key characteristics of the overhead line and underground cable network. All units relating to cable and line assets, that are expressed in km, refer 9 10 Circuit length by operating voltage (at year end) Overhead (km) Underground (km) Total circuit length (km) 11 > 66kV 12 50kV & 66kV 13 33kV SWER (all SWER voltages) kV (other than SWER) kV to 11kV (inclusive other than SWER) 2, , Low voltage (< 1kV) 739 1,990 2, Total circuit length (for supply) 2,993 2,515 5, Dedicated street lighting circuit length (km) , Circuit in sensitive areas (conservation areas, iwi territory etc) (km) Overhead circuit length by terrain (at year end) Circuit length (km) (% of total overhead length) 24 Urban % 25 Rural % 26 Remote only 14 0% 27 Rugged only 1,247 42% 28 Remote and rugged 29 Unallocated overhead lines % 30 Total overhead length 2, % Circuit length (km) (% of total circuit length) 33 Length of circuit within 10km of coastline or geothermal areas (where known) 1,339 24% 34 Circuit length (km) (% of total overhead length) 35 Overhead circuit requiring vegetation management 2, %

39 Network / Sub-network Name SCHEDULE 9c: REPORT ON OVERHEAD LINES AND UNDERGROUND CABLES Central Region This schedule requires a summary of the key characteristics of the overhead line and underground cable network. All units relating to cable and line assets, that are expressed in km, refer 9 10 Circuit length by operating voltage (at year end) Overhead (km) Underground (km) Total circuit length (km) 11 > 66kV 12 50kV & 66kV 13 33kV SWER (all SWER voltages) kV (other than SWER) kV to 11kV (inclusive other than SWER) 1, , Low voltage (< 1kV) , Total circuit length (for supply) 2,577 1,098 3, Dedicated street lighting circuit length (km) Circuit in sensitive areas (conservation areas, iwi territory etc) (km) 1, Overhead circuit length by terrain (at year end) Circuit length (km) (% of total overhead length) 24 Urban % 25 Rural % 26 Remote only 231 9% 27 Rugged only 1,404 54% 28 Remote and rugged 29 Unallocated overhead lines 3 0% 30 Total overhead length 2, % Circuit length (km) (% of total circuit length) 33 Length of circuit within 10km of coastline or geothermal areas (where known) 2,327 63% 34 Circuit length (km) (% of total overhead length) 35 Overhead circuit requiring vegetation management 2, %

40 8 Location * SCHEDULE 9d: REPORT ON EMBEDDED NETWORKS This schedule requires information concerning embedded networks owned by an EDB that are embedded in another EDB s network or in another embedded network. Nil Number of ICPs served Line charge revenue ($000) * Extend embedded distribution networks table as necessary to disclose each embedded network owned by the EDB which is embedded in another EDB s network or in another embedded network Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 40 S9d.Embedded Networks

41 SCHEDULE 9e: REPORT ON NETWORK DEMAND 8 9e(i): Consumer Connections 9 Number of ICPs connected in year by consumer type 10 Consumer types defined by EDB* Network / Sub-network Name Number of connections (ICPs) 11 Residential Commercial Industrial * include additional rows if needed 17 Connections total 1, Distributed generation 20 Number of connections made in year 267 connections 21 Capacity of distributed generation installed in year 0.94 MVA 22 9e(ii): System Demand Maximum coincident system demand 26 GXP demand plus Distributed generation output at HV and above Maximum coincident system demand less Net transfers to (from) other EDBs at HV and above 30 Demand on system for supply to consumers' connection points Electricity volumes carried Energy (GWh) 32 Electricity supplied from GXPs 1, less Electricity exports to GXPs plus Electricity supplied from distributed generation less Net electricity supplied to (from) other EDBs 36 Electricity entering system for supply to consumers' connection points 1, less Total energy delivered to ICPs 1, Electricity losses (loss ratio) % Load factor e(iii): Transformer Capacity Distribution transformer capacity (EDB owned) 1, Distribution transformer capacity (Non-EDB owned, estimated) Total distribution transformer capacity 1, This schedule requires a summary of the key measures of network utilisation for the disclosure year (number of new connections including distributed generation, peak demand and electricity volumes conveyed). Demand at time of maximum coincident demand (MW) 47 Zone substation transformer capacity 865 (MVA) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 41 S9e. Demand

42 SCHEDULE 9e: REPORT ON NETWORK DEMAND 8 9e(i): Consumer Connections 9 Number of ICPs connected in year by consumer type 10 Consumer types defined by EDB* Network / Sub-network Name Number of connections (ICPs) 11 Residential Commercial Industrial * include additional rows if needed 17 Connections total Distributed generation 20 Number of connections made in year 196 connections 21 Capacity of distributed generation installed in year 0.65 MVA 22 9e(ii): System Demand Maximum coincident system demand 26 GXP demand plus Distributed generation output at HV and above 28 Maximum coincident system demand less Net transfers to (from) other EDBs at HV and above 30 Demand on system for supply to consumers' connection points Electricity volumes carried Energy (GWh) 32 Electricity supplied from GXPs less Electricity exports to GXPs 34 plus Electricity supplied from distributed generation less Net electricity supplied to (from) other EDBs 36 Electricity entering system for supply to consumers' connection points less Total energy delivered to ICPs Electricity losses (loss ratio) % Load factor e(iii): Transformer Capacity Distribution transformer capacity (EDB owned) Distribution transformer capacity (Non-EDB owned, estimated) Total distribution transformer capacity Hawke's Bay This schedule requires a summary of the key measures of network utilisation for the disclosure year (number of new connections including distributed generation, peak demand and electricity volumes conveyed). Demand at time of maximum coincident demand (MW) 47 Zone substation transformer capacity 611 (MVA) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 42 S9e.Demand HB

43 SCHEDULE 9e: REPORT ON NETWORK DEMAND 8 9e(i): Consumer Connections 9 Number of ICPs connected in year by consumer type 10 Consumer types defined by EDB* Network / Sub-network Name Number of connections (ICPs) 11 Residential Commercial Industrial * include additional rows if needed 17 Connections total Distributed generation 20 Number of connections made in year 71 connections 21 Capacity of distributed generation installed in year 0.29 MVA 22 9e(ii): System Demand Maximum coincident system demand 26 GXP demand plus Distributed generation output at HV and above Maximum coincident system demand less Net transfers to (from) other EDBs at HV and above 30 Demand on system for supply to consumers' connection points Electricity volumes carried Energy (GWh) 32 Electricity supplied from GXPs less Electricity exports to GXPs plus Electricity supplied from distributed generation less Net electricity supplied to (from) other EDBs 36 Electricity entering system for supply to consumers' connection points less Total energy delivered to ICPs Electricity losses (loss ratio) % Load factor e(iii): Transformer Capacity Distribution transformer capacity (EDB owned) Distribution transformer capacity (Non-EDB owned, estimated) 7 45 Total distribution transformer capacity Central Region This schedule requires a summary of the key measures of network utilisation for the disclosure year (number of new connections including distributed generation, peak demand and electricity volumes conveyed). Demand at time of maximum coincident demand (MW) 47 Zone substation transformer capacity 254 (MVA) Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 43 S9e.Demand CR

44 SCHEDULE 10: REPORT ON NETWORK RELIABILITY 8 10(i): Interruptions 9 Interruptions by class Network / Sub-network Name Number of interruptions 10 Class A (planned interruptions by Transpower) 7 11 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Class D (unplanned interruptions by Transpower) Class E (unplanned interruptions of EDB owned generation) - 15 Class F (unplanned interruptions of generation owned by others) 1 16 Class G (unplanned interruptions caused by another disclosing entity) - 17 Class H (planned interruptions caused by another disclosing entity) - 18 Class I (interruptions caused by parties not included above) 7 19 Total 1, Interruption restoration 3Hrs >3hrs 22 Class C interruptions restored within SAIFI and SAIDI by class SAIFI SAIDI 25 Class A (planned interruptions by Transpower) Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Class D (unplanned interruptions by Transpower) Class E (unplanned interruptions of EDB owned generation) Class F (unplanned interruptions of generation owned by others) Class G (unplanned interruptions caused by another disclosing entity) Class H (planned interruptions caused by another disclosing entity) Class I (interruptions caused by parties not included above) Total This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Normalised SAIFI and SAIDI Normalised SAIFI Normalised SAIDI 37 Classes B & C (interruptions on the network) Quality path normalised reliability limit SAIFI reliability limit SAIDI reliability limit 40 SAIFI and SAIDI limits applicable to disclosure year* * not applicable to exempt EDBs Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 44 S10.Reliability (Total)

45 SCHEDULE 10: REPORT ON NETWORK RELIABILITY Network / Sub-network Name This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (ii): Class C Interruptions and Duration by Cause Cause SAIFI SAIDI 45 Lightning Vegetation Adverse weather Adverse environment Third party interference Wildlife Human error Defective equipment Cause unknown (iii): Class B Interruptions and Duration by Main Equipment Involved Main equipment involved SAIFI SAIDI 58 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) Distribution cables (excluding LV) Distribution other (excluding LV) (iv): Class C Interruptions and Duration by Main Equipment Involved Main equipment involved SAIFI SAIDI 67 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) Distribution cables (excluding LV) Distribution other (excluding LV) (v): Fault Rate 74 Main equipment involved Number of Faults Circuit length (km) Fault rate (faults per 100km) 75 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) 1,188 3, Distribution cables (excluding LV) Distribution other (excluding LV) - 81 Total 1,394 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 45 S10.Reliability (Total)

46 SCHEDULE 10: REPORT ON NETWORK RELIABILITY 8 10(i): Interruptions 9 Interruptions by class Network / Sub-network Name Number of interruptions 10 Class A (planned interruptions by Transpower) 1 11 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Class D (unplanned interruptions by Transpower) Class E (unplanned interruptions of EDB owned generation) - 15 Class F (unplanned interruptions of generation owned by others) - 16 Class G (unplanned interruptions caused by another disclosing entity) - 17 Class H (planned interruptions caused by another disclosing entity) - 18 Class I (interruptions caused by parties not included above) 3 19 Total Interruption restoration 3Hrs >3hrs 22 Class C interruptions restored within SAIFI and SAIDI by class SAIFI SAIDI 25 Class A (planned interruptions by Transpower) Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Class D (unplanned interruptions by Transpower) Class E (unplanned interruptions of EDB owned generation) Class F (unplanned interruptions of generation owned by others) Class G (unplanned interruptions caused by another disclosing entity) Class H (planned interruptions caused by another disclosing entity) Class I (interruptions caused by parties not included above) Total Hawkes Bay This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Normalised SAIFI and SAIDI Normalised SAIFI Normalised SAIDI 37 Classes B & C (interruptions on the network) Quality path normalised reliability limit SAIFI reliability limit 40 SAIFI and SAIDI limits applicable to disclosure year* N/A N/A 41 * not applicable to exempt EDBs SAIDI reliability limit Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 46 S10.Reliability (HB)

47 SCHEDULE 10: REPORT ON NETWORK RELIABILITY Network / Sub-network Name Hawkes Bay This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (ii): Class C Interruptions and Duration by Cause Cause SAIFI SAIDI 45 Lightning Vegetation Adverse weather Adverse environment Third party interference Wildlife Human error Defective equipment Cause unknown (iii): Class B Interruptions and Duration by Main Equipment Involved Main equipment involved SAIFI SAIDI 58 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) Distribution cables (excluding LV) Distribution other (excluding LV) (iv): Class C Interruptions and Duration by Main Equipment Involved Main equipment involved SAIFI SAIDI 67 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) Distribution cables (excluding LV) Distribution other (excluding LV) (v): Fault Rate 74 Main equipment involved Number of Faults Circuit length (km) Fault rate (faults per 100km) 75 Subtransmission lines Subtransmission cables Subtransmission other 3 78 Distribution lines (excluding LV) 668 2, Distribution cables (excluding LV) Distribution other (excluding LV) - 81 Total 802 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 47 S10.Reliability (HB)

48 SCHEDULE 10: REPORT ON NETWORK RELIABILITY 8 10(i): Interruptions 9 Interruptions by class Network / Sub-network Name Number of interruptions 10 Class A (planned interruptions by Transpower) 6 11 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Class D (unplanned interruptions by Transpower) - 14 Class E (unplanned interruptions of EDB owned generation) - 15 Class F (unplanned interruptions of generation owned by others) 1 16 Class G (unplanned interruptions caused by another disclosing entity) - 17 Class H (planned interruptions caused by another disclosing entity) - 18 Class I (interruptions caused by parties not included above) 4 19 Total Interruption restoration 3Hrs >3hrs 22 Class C interruptions restored within SAIFI and SAIDI by class SAIFI SAIDI 25 Class A (planned interruptions by Transpower) Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Class D (unplanned interruptions by Transpower) Class E (unplanned interruptions of EDB owned generation) Class F (unplanned interruptions of generation owned by others) Class G (unplanned interruptions caused by another disclosing entity) Class H (planned interruptions caused by another disclosing entity) Class I (interruptions caused by parties not included above) Total Central Region This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section Normalised SAIFI and SAIDI Normalised SAIFI Normalised SAIDI 37 Classes B & C (interruptions on the network) Quality path normalised reliability limit SAIFI reliability limit 40 SAIFI and SAIDI limits applicable to disclosure year* N/A N/A 41 * not applicable to exempt EDBs SAIDI reliability limit Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 48 S10.Reliability (CR)

49 SCHEDULE 10: REPORT ON NETWORK RELIABILITY Network / Sub-network Name Central Region This schedule requires a summary of the key measures of network reliability (interruptions, SAIDI, SAIFI and fault rate) for the disclosure year. EDBs must provide explanatory comment on their network reliability for the disclosure year in Schedule 14 (Explanatory notes to templates). The SAIFI and SAIDI information is part of audited disclosure information (as defined in section 1.4 of the ID determination), and so is subject to the assurance report required by section (ii): Class C Interruptions and Duration by Cause Cause SAIFI SAIDI 45 Lightning Vegetation Adverse weather Adverse environment Third party interference Wildlife Human error Defective equipment Cause unknown (iii): Class B Interruptions and Duration by Main Equipment Involved Main equipment involved SAIFI SAIDI 58 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) Distribution cables (excluding LV) Distribution other (excluding LV) (iv): Class C Interruptions and Duration by Main Equipment Involved Main equipment involved SAIFI SAIDI 67 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) Distribution cables (excluding LV) Distribution other (excluding LV) (v): Fault Rate 74 Main equipment involved Number of Faults Circuit length (km) Fault rate (faults per 100km) 75 Subtransmission lines Subtransmission cables Subtransmission other Distribution lines (excluding LV) 520 1, Distribution cables (excluding LV) Distribution other (excluding LV) - 81 Total 592 Unison - Schedules 1 to 10 - Information Disclosures Schedule 9e - Amended 2017.xlsx 49 S10.Reliability (CR)

50 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Schedule 14 Mandatory Explanatory Notes 1. This schedule requires EDBs to provide explanatory notes to information provided in accordance with clauses 2.3.1, , , and subclauses 2.5.1(1)(f),and 2.5.2(1)(e). 2. This schedule is mandatory EDBs must provide the explanatory comment specified below, in accordance with clause Information provided in boxes 1 to 12 of this schedule is part of the audited disclosure information, and so is subject to the assurance requirements specified in section Schedule 15 (Voluntary Explanatory Notes to Schedules) provides for EDBs to give additional explanation of disclosed information should they elect to do so. Return on Investment (Schedule 2) 4. In the box below, comment on return on investment as disclosed in Schedule 2. This comment must include information on reclassified items in accordance with subclause 2.7.1(2). Box 1: Explanatory comment on return on investment There has been no material re-classification of items in the disclosure year. Regulatory Profit (Schedule 3) 5. In the box below, comment on regulatory profit for the disclosure year as disclosed in Schedule 3. This comment must include- 5.1 a description of material items included in other regulated income (other than gains / (losses) on asset disposals), as disclosed in 3(i) of Schedule information on reclassified items in accordance with subclause 2.7.1(2). Box 2: Explanatory comment on regulatory profit The other regulatory income includes recovery from damages to the network and connection fees. There has been no material re-classification of items in the disclosure year.

51 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Merger and acquisition expenses (3(iv) of Schedule 3) 6. If the EDB incurred merger and acquisitions expenditure during the disclosure year, provide the following information in the box below- 6.1 information on reclassified items in accordance with subclause 2.7.1(2) 6.2 any other commentary on the benefits of the merger and acquisition expenditure to the EDB. Box 3: Explanatory comment on merger and acquisition expenditure No merger and acquisition expenditure has been incurred during the disclosure year. Value of the Regulatory Asset Base (Schedule 4) 7. In the box below, comment on the value of the regulatory asset base (rolled forward) in Schedule 4. This comment must include information on reclassified items in accordance with subclause 2.7.1(2). Box 4: Explanatory comment on the value of the regulatory asset based (rolled forward) The value of the regulatory asset base has been determined by rolling forward the initial regulatory asset base with allowance made for additions, disposals, depreciation and revaluation in accordance with the Electricity Distribution Services Input Methodologies Determination There were some assets reclassified in the year with the implementation in SAP of the regulatory asset base. Regulatory tax allowance: disclosure of permanent differences (5a(i) of Schedule 5a) 8. In the box below, provide descriptions and workings of the material items recorded in the following asterisked categories of 5a(i) of Schedule 5a- 8.1 Income not included in regulatory profit / (loss) before tax but taxable; 8.2 Expenditure or loss in regulatory profit / (loss) before tax but not deductible; 8.3 Income included in regulatory profit / (loss) before tax but not taxable; 8.4 Expenditure or loss deductible but not in regulatory profit / (loss) before tax. Box 5: Regulatory tax allowance: permanent differences Entertainment Expenditure non-deductible $30k

52 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Regulatory tax allowance: disclosure of temporary differences (5a(vi) of Schedule 5a) 9. In the box below, provide descriptions and workings of material items recorded in the asterisked category Tax effect of other temporary differences in 5a(vi) of Schedule 5a. Box 6: Tax effect of other temporary differences (current disclosure year) Other temporary differences: Provision for Doubtful Debts $132k Provision for Employee Entitlements $428k Provision for ACC $(207)k Total $353k Related party transactions: disclosure of related party transactions (Schedule 5b) 10. In the box below, provide descriptions of related party transactions beyond those disclosed on Schedule 5b including identification and descriptions as to the nature of directly attributable costs disclosed under subclause 2.3.6(1)(b). Box 7: Related party transactions s wholly owned subsidiary Unison Contracting Services Limited (UCSL) provided electrical contracting services to maintain and develop the network during the 2017 disclosure year. UCSL related party transactions have been prepared on the basis of consolidating and UCSL according to guidance previously provided to Unison from the Commerce Commission, which has been disclosed in previous years. A detailed description of related party transactions has been disclosed in Schedule 5b. There have been no related party transactions within the disclosure year that require further disclosure under clause 2.3.6(1)(b). Cost allocation (Schedule 5d) 11. In the box below, comment on cost allocation as disclosed in Schedule 5d. This comment must include information on reclassified items in accordance with subclause 2.7.1(2). Box 8: Cost allocation Costs are allocated by applying ACAM. Expenses classified as not directly attributable are those which have been allocated to electricity and non-electricity activities.

53 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Asset allocation (Schedule 5e) 12. In the box below, comment on asset allocation as disclosed in Schedule 5e. This comment must include information on reclassified items in accordance with subclause 2.7.1(2). Box 9: Commentary on asset allocation There have been no reclassified items. Capital Expenditure for the Disclosure Year (Schedule 6a) 13. In the box below, comment on expenditure on assets for the disclosure year, as disclosed in Schedule 6a. This comment must include a description of the materiality threshold applied to identify material projects and programmes described in Schedule 6a; 13.2 information on reclassified items in accordance with subclause 2.7.1(2), Box 10: Explanation of capital expenditure for the disclosure year 13.1 Material projects are defined by Unison as those projects with significant strategic importance to the network as determined by Unison s engineers, or those projects with total Capital Costs of greater than $250, There have been no reclassified items. Operational Expenditure for the Disclosure Year (Schedule 6b) 14. In the box below, comment on operational expenditure for the disclosure year, as disclosed in Schedule 6b. This comment must include Commentary on assets replaced or renewed with asset replacement and renewal operational expenditure, as reported in 6b(i) of Schedule 6b; 14.2 Information on reclassified items in accordance with subclause 2.7.1(2); 14.3 Commentary on any material atypical expenditure included in operational expenditure disclosed in Schedule 6b, a including the value of the expenditure the purpose of the expenditure, and the operational expenditure categories the expenditure relates to.

54 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Box 11: Explanation of operational expenditure for the disclosure year 14.1 The predominant parts of Asset Replacement and Renewal operational expenditure are the costs required for replacing components of assets identified through Unison s planned asset inspection programmes. The major contributor to this category of expenditure is overhead line maintenance, and then zone substation grounds and graffiti removal There have been no reclassified items this disclosure year There was a significantly increased expenditure in Service Interruptions and Emergencies due to a snow storm in August. The cost impact of this storm to Service Interruptions and Emergencies was $340k. Variance between forecast and actual expenditure (Schedule 7) 15. In the box below, comment on variance in actual to forecast expenditure for the disclosure year, as reported in Schedule 7. This comment must include information on reclassified items in accordance with subclause 2.7.1(2).

55 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Box 12: Explanatory comment on variance in actual to forecast expenditure 7(ii) Expenditure on Assets (CAPEX) Network capital expenditure variance in the reporting period totalled 18% which is considered significant. There were some significant variances within categories of expenditure. The key variances were: - an overspend in Asset Replacement and Renewal due to the August snow storm, and - an increase in spend in Customer Connections due to increased demand from commercial and industrial growth. Growth occurred particularly in the agriculture and food processing sectors in Hawke s Bay, and the increase in subdivisions across Unison s network. Variances also occurred in System Growth due to some significant projects being completed under budget, and council roading projects requiring Asset Relocations. The carryover of work from previous years resulted in the variance for Reliability Safety and Environment. 7(iii) Operational Expenditure (OPEX) In respect to network opex, the variance in spend from the AMP forecast is 6%. Although 6% is not considered material, the categories Service Interruptions and Emergencies and Vegetation Management had variances of 15% and 16% respectively. The Service Interruption and Emergency variance was mainly the result of the August snow storm, and the variance in Vegetation Management was due to the additional volume of trees cut. Information relating to revenues and quantities for the disclosure year 16. In the box below provide a comparison of the target revenue disclosed before the start of the disclosure year, in accordance with clause and subclause 2.4.3(3) to total billed line charge revenue for the disclosure year, as disclosed in Schedule 8; and 16.2 explanatory comment on reasons for any material differences between target revenue and total billed line charge revenue. Box 13: Explanatory comment relating to revenue for the disclosure year Regulated Line Revenue is $1.1 million above budget due to a combination of growth in residential connections and higher than forecast residential electricity consumption.

56 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Network Reliability for the Disclosure Year (Schedule 10) 17. In the box below, comment on network reliability for the disclosure year, as disclosed in Schedule 10. Box 14: Commentary on network reliability for the disclosure year Unison did not comply with the annual reliability assessment for SAIDI for the assessment period 1/4/2016 to 31/3/2017. Non-compliance was due to the following factors: A significant increase in planned outages as a result of the electricity supply industry developing a guideline for live line work. The impact of the guideline is an increase in the number of tasks performed de-energised. Increased restoration times for transient faults due to the EEA s Guide for Manual Reclosing of High Voltage Circuits Following a Fault. This requires waiting 15 minutes before any manual reclose attempts are made. A substantial increase in the impact of external influence events such as motor vehicle accidents, vandalism and dig-ins. Significant increase in the number of trees that Unison defines as Fall Distance Zone trees. These are trees that are not in the Notice Zone or Growth Limit Zone of the overhead assets as defined by the Electricity (Hazards from Trees) Regulations Unison must negotiate with tree owners to remove these trees as there are no rights to address vegetation outside of the notice or growth limit zones defined by the regulations. Unison is currently undertaking a full review of its vegetation management strategy. This is expected to refocus resources on particularly poor performing feeders and address engagement with customers and stakeholders. Unison did comply with the annual reliability assessment for SAIFI for the assessment period 1/4/2016 to 31/3/2017. Insurance cover 18. In the box below, provide details of any insurance cover for the assets used to provide electricity distribution services, including The EDB s approaches and practices in regard to the insurance of assets used to provide electricity distribution services, including the level of insurance; 18.2 In respect of any self insurance, the level of reserves, details of how reserves are managed and invested, and details of any reinsurance.

57 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Box 15: Explanation of insurance cover Unison seeks to insure all its assets for material damage and business interruption cover. It employs two policies to achieve this. The MD & BI policy, placed in the retail market, covers all Ground-mounted distribution equipment, substation buildings and substation equipment as well as all corporate buildings and non-network assets. Total sum insured for the policy is $596M (for 2016/17) which includes a $41M component for business interruption cover. The deductible is $10,000 with a $100,000 deductible applying for ground mounted assets. Because no retail cover is available for Unison s T&D assets (poles and wires, pole mounted equipment and underground cables) Unison owns a captive insurance company, Unison Insurance Limited, which provides a self-insurance policy to the value of $15M. This figure includes $3M of business interruption cover. The policy is reviewed annually, along with any changes to the retail T&D market and carries a deductible of $5,000,000. Amendments to previously disclosed information 19. In the box below, provide information about amendments to previously disclosed information disclosed in accordance with clause in the last 7 years, including: 19.1 a description of each error; and 19.2 for each error, reference to the web address where the disclosure made in accordance with clause is publicly disclosed. Box 16: Disclosure of amendment to previously disclosed information [Insert text here]

58 Electricity Distribution Information Disclosure Determination 2012 (consolidated in 2015) Schedules Schedule 15 Voluntary Explanatory Notes 1. This schedule enables EDBs to provide, should they wish to- 1.1 additional explanatory comment to reports prepared in accordance with clauses 2.3.1, , , and 2.5.2; 1.2 information on any substantial changes to information disclosed in relation to a prior disclosure year, as a result of final wash-ups. 2. Information in this schedule is not part of the audited disclosure information, and so is not subject to the assurance requirements specified in section Provide additional explanatory comment in the box below. Box 1: Voluntary explanatory comment on disclosed information [Insert text below]

59

60 Independent Assurance Report To the directors of and the Commerce Commission The Auditor-General is the auditor of (the company). The Auditor-General has appointed me, Julian Tan, using the staff and resources of Audit New Zealand, to provide an opinion, on his behalf, on whether the information disclosed in schedules 1 to 4, 5a to 5g, 6a and 6b, 7, the system average interruption duration index ( SAIDI ) and system average interruption frequency index ( SAIFI ) information disclosed in Schedule 10 and the explanatory notes in boxes 1 to 12 in Schedule 14 ( the Disclosure Information ) for the disclosure year ended, have been prepared, in all material respects, in accordance with the Electricity Distribution Information Disclosure Determination 2012 (the Determination ). Directors responsibility for the Disclosure Information The directors of the company are responsible for preparation of the Disclosure Information in accordance with the Determination, and for such internal control as the directors determine is necessary to enable the preparation of the Disclosure Information that is free from material misstatement. Our responsibility for the Disclosure Information Our responsibility is to express an opinion on whether the Disclosure Information has been prepared, in all material respects, in accordance with the Determination. Basis of opinion We conducted our engagement in accordance with the International Standard on Assurance Engagements (New Zealand) 3000 (Revised) Assurance Engagements Other Than Audits or Reviews of Historical Financial Information and the Standard on Assurance Engagements 3100: Compliance Engagements issued by the External Reporting Board. Copies of these standards are available on the External Reporting Board s website. These standards require that we comply with ethical requirements and plan and perform our assurance engagement to provide reasonable assurance about whether the Disclosure Information has been prepared in all material respects in accordance with the Determination. We have performed procedures to obtain evidence about the amounts and disclosures in the Disclosure Information. The procedures selected depend on our judgement, including the assessment of the risks of material misstatement of the Disclosure Information, whether due to fraud or error or non-compliance with the Determination. In making those risk assessments, we considered internal control relevant to the company s preparation of the Disclosure Information in order to design procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company s internal control.

61 Use of this report This independent assurance report has been prepared solely for the directors of the company and for the Commerce Commission for the purpose of providing those parties with reasonable assurance about whether the Disclosure Information has been prepared, in all material respects, in accordance with the Determination. We disclaim any assumption of responsibility for any reliance on this report to any person other than the directors of the company or the Commerce Commission, or for any purpose other than that for which it was prepared. Scope and inherent limitations Because of the inherent limitations of a reasonable assurance engagement, and the test basis of the procedures performed, it is possible that fraud, error or non-compliance may occur and not be detected. We did not examine every transaction, adjustment or event underlying the Disclosure Information nor do we guarantee complete accuracy of the Disclosure Information. Also we did not evaluate the security and controls over the electronic publication of the Disclosure Information. The opinion expressed in this independent assurance report has been formed on the above basis. Independence and quality control When carrying out the engagement, we complied with the Auditor-General s: independence and other ethical requirements, which incorporate the independence and ethical requirements of Professional and Ethical Standard 1 (Revised): Code of Ethics for Assurance Practitioners issued by the New Zealand Auditing and Assurance Standards Board; and quality control requirements, which incorporate the quality control requirements of Professional and Ethical Standard 3 (Amended): Quality Control for Firms that Perform Audits and Reviews of Financial Statements, and Other Assurance Engagements issued by the New Zealand Auditing and Assurance Standards Board. We also complied with the independence requirements specified in the Determination. The Auditor-General, and his employees, and Audit New Zealand and its employees may deal with the company on normal terms within the ordinary course of trading activities of the company. Other than any dealings on normal terms within the ordinary course of business, this engagement and the engagements described below, we have no relationship with or interests in the company: annual audit of the company s financial statements; an agreed upon procedures engagement for the company in connection with the Price 2017/2018 and Quantity 2015/16 disclosure schedule for the assessment period ending 31 March 2017; and an assurance engagement for the company in respect of the company s compliance statement on the default price-quality path prepared under the Electricity Distribution

62 Opinion In our opinion: Services Default Price-Quality Path Determination 2015 NZCC 35 for the year ended. as far as appears from an examination of them, proper records to enable the complete and accurate compilation of the Disclosure Information have been kept by the company; as far as appears from an examination, the information used in the preparation of the Disclosure Information has been properly extracted from the company s accounting and other records and has been sourced, where appropriate, from the company s financial and non-financial systems; and the Disclosure Information has been prepared, in all material respects, in accordance with the Determination. In forming our opinion, we have obtained sufficient recorded evidence and all the information and explanations we have required. Julian Tan Audit New Zealand On behalf of the Auditor-General Palmerston North, New Zealand 18 August 2017