regulatory test final recommendation report - … recommendation report ... the study area 11kv...

DisclaimerWhile care was taken in preparation of the information in this discussion paper, and it is provided in good faith, Ergon Energy Corporation Limited accepts no responsibility or liability for any loss or damage that may be incurred by any person acting in reliance on this information or assumptions drawn from it. This discussion paper has been prepared for the purpose of inviting information, comment and discussion from interested parties. The document has been prepared using information provided by a number of third parties. It contains assumptions regarding, among other things, economic growth and load forecasts which may or may not prove to be correct. All information should be independently verified to the extent possible before assessing any investment proposals.

Regulatory Test – Final recommendation report Proposed establishment of a new 66/11kV substation at Ooralea 19 March 2014 Ergon Energy Corporation Limited

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TABLE OF CONTENTS EXECUTIVE SUMMARY ....................................................................................................................................................................................... 1 1. INTRODUCTION .......................................................................................................................................................................................... 2 2. BACKGROUND & REASONS AUGMENTATION IS REQUIRED .............................................................................................................. 3

2.1. Background ................................................................................................................................. 3

2.2. Purpose of this “Final Report” ..................................................................................................... 3

3. EXISTING SUPPLY SYSTEM TO The South Mackay AREA .................................................................................................................... 4

3.1. Geographic Region ..................................................................................................................... 4

3.2. Existing Supply System .............................................................................................................. 5

4. EMERGING NETWORK LIMITATIONS ...................................................................................................................................................... 6

4.1. Applied Service Standards ......................................................................................................... 6

4.2. Limitations of the Existing Network ............................................................................................. 6

4.3. Distribution Feeder Forecast ...................................................................................................... 6

4.4. Timeframes for Taking Corrective Action ................................................................................... 7

4.5. Known Future Network and Generation Development ............................................................... 8

5. OPTIONS CONSIDERED ............................................................................................................................................................................ 8

5.1. Consultation Summary ............................................................................................................... 8

5.2. Non-Distribution Options Identified ............................................................................................. 8

5.3. Distribution Options Identified ..................................................................................................... 8

6. FEASIBLE SOLUTIONS .............................................................................................................................................................................. 9

6.1. Option 1 – NNA Program and Establishment of a new 66/11kV Substation with 1x10MVA transformer by 2016/17 ............................................................................................................. 10

6.2. Option 2 – External Diesel Generation – Party A ..................................................................... 11

6.3. Option 3 – External Concentrated Solar/Diesel/Battery – Party B ............................................ 11

6.4. Option 4 – External Diesel Generation – Party C ..................................................................... 12

7. FINANCIAL ANALYSIS & RESULTS ....................................................................................................................................................... 13

7.1. Format and Inputs to Analysis .................................................................................................. 13

7.1.1 Regulatory Test Requirements ......................................................................................... 13 7.1.2 Inputs to Analysis .............................................................................................................. 13

7.2. Financial Analysis ..................................................................................................................... 14

7.2.1 Present Value Analysis ..................................................................................................... 14 7.2.2 Summary of Economic Analysis ....................................................................................... 14

7.3. Discussion of Results ............................................................................................................... 15

8. FINAL DECISION & RECOMMENDATION ............................................................................................................................................... 15

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EXECUTIVE SUMMARY

Ergon Energy Corporation Limited (Ergon Energy) is responsible (under its Distribution Authority) for electricity supply to the South Mackay area in Central Queensland. We have identified emerging limitations in the electricity distribution network supplying the South Mackay area, including the suburbs of Ooralea, Paget, and Bakers Creek (hereby known as the study area). The loads on Ergon Energy’s zone substation and 11kV network in the study area have progressively increased such that augmentation is required if reliable supply is to be maintained.

The study area 11kV supply is primarily supplied by the South Mackay 33/11kV substation, known as SOMA. T38 Mackay is the primary subtransmission supply at 33kV for SOMA. SOMA currently sources seven 11kV feeders in the Paget, Ooralea and Bakers Creek area and has N-1 substation rating of 20.7 MVA.

The load on SOMA 33/11 kV substation exceeded the substation N-1 rating over summer 2011/12. As there were no primary plant failures at the peak times of the year, then no further mitigation was required to maintain supply to customers. Ergon has a number of mitigation solutions in place for the possibility of a primary plant failure during a period when the 11kV loads exceed 20.7MVA which could include, but not limited to, call off load, call on generation, and network switching,. In order to manage the load at risk and maintain security of supply, demand reductions and/or supply-side capacity improvements totalling a minimum of 3.65MVA in the summer of 2014/15 and 4.75MVA in the summer of 2015/16 need to be achieved (subject to periodic review).

In order to ensure that supply to customers in the study area complies with Ergon Energy’s security of supply criteria, initial corrective action will be required to be completed prior to the summer of 2016/17. A decision about the selected option is required by March 2014 if any option involving significant construction is to be completed by September 2016.

Ergon Energy published a Request for Information relating to this emerging network constraint on 28 October 2013. Two submissions were received by the closing date of 23 December 2013.

Ergon Energy published a Consultation and Draft Recommendation on 30 January 2014. Two submissions to the Consultation and Draft Recommendation were received by the closing date of 27 February 2014.

The evaluation process has considered both external submissions, in conjunction with Ergon Energy’s internally identified distribution network option. The recommended solution has been identified as the implementation of small-scale NNA (non-network alternatives) from 2014/15, and the construction of a single-transformer skid-mounted substation by September 2016.

Four feasible solutions to the emerging network constraint have been identified:

Option 1 Undertake Small-Scale NNA and Establish a new 66/11kV Skid-Mounted Substation with a 1x10 MVA transformer at Ooralea by September 2016

Option 2 External Diesel Generation System – Party A

Option 3 External Concentrated Solar / Batteries / Diesel Backup – Party B

Option 4 External Diesel Generation System – Party C

In accordance with the requirements of the National Electricity Rules (NER), this is now a Final Report where Ergon Energy provides both economic and technical information about possible solutions, and the solution decided on, being Option 1, to implement a new substation on an Ergon Energy owned site at Ooralea.

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1. INTRODUCTION

Ergon Energy has identified emerging limitations in the electricity distribution network supplying the South Mackay area in Central Queensland.

When a distribution network service provider proposes to establish a new large distribution network asset to address such limitations, it is required under the National Electricity Rules (NER) clause 5.6.2(f) to consult with affected Registered Participants, AEMO and Interested Parties on possible options to address the limitations. These options may include but are not limited to demand side options, generation options, and market network service provider options.

Under clause 5.6.2(g) of the NER the consultation must include an economic cost effectiveness analysis of possible options to identify options that satisfy the Australian Energy Regulator’s (AER) Regulatory Test, while meeting the technical requirements of Schedule 5.1 of the NER.

This Final Report is based on:

• the assessment that a reliable power supply is not able to be maintained in the South Mackay area.

• the Request for Information consultation undertaken by Ergon Energy to identify potential solutions to address the emerging distribution network limitations; and

• an analysis of feasible options in accordance with the AER’s Regulatory Test.

This project has been considered under the reliability limb of the Regulatory Test as the service standards linked to the technical requirements of Schedule 5.1 of the NER and Ergon Energy’s licence conditions are unable to be met, as detailed in Section 4 of this report.

This project was included in the Ergon Energy Network Management Plan 2012/13 to 2016/17.

Information relating to the consultation about this project is provided on our web site:

https://www.ergon.com.au/community--and--our-network/network-management/regulatory-test-consultations

For further information, please email: [email protected]

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2. BACKGROUND & REASONS AUGMENTATION IS REQUIRED

2.1. Background

If technical limits of the distribution system will be exceeded and the rectification options are likely to exceed $10M, Ergon Energy is required under the NER1 to notify Registered Participants,2 AEMO and Interested Parties3 within the time required for corrective action and meet the following regulatory requirements:

• Consult with Registered Participants, AEMO and Interested Parties regarding possible solutions that may include local generation, demand side management and market network service provider options4.

• Demonstrate proper consideration of various scenarios, including reasonable forecasts of electricity demand, efficient operating costs, avoidable costs, costs of ancillary services and the ability of alternative options to satisfy emerging network limitations under these scenarios.

• Ensure the recommended solution meets reliability requirements while minimising the present value of costs when compared to alternative solutions5.

Ergon Energy is responsible for electricity supply to the South Mackay area (under its Distribution Authority) and has identified emerging limitations in the electricity distribution network supplying this area. Augmentation to the electricity distribution network supplying this area is required if reliable supply is to be restored.

2.2. Purpose of this “Final Report”

The purpose of this Final Report is to:

• Provide information about the existing distribution network in the South Mackay area.

• Provide information about emerging distribution network limitations and the expected time by which action must be taken to maintain the reliability of the distribution system.

• Provide information about options identified and considered.

• Explain the process (including approach and assumptions), and the AER’s Regulatory Test used to evaluate alternative solutions, including distribution options.

• Report the solution Ergon Energy has decided on.

.

1 Clause 5.6.2(f) 2 As defined in the NER 3 As defined in the NER 4 NER clause 5.6.2(f) 5 In accordance with the AER’s Regulatory Test Version 3, November 2007

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3. EXISTING SUPPLY SYSTEM TO THE SOUTH MACKAY AREA

3.1. Geographic Region

The geographic region covered by this Final Report is broadly described as the South Mackay area as shown on the map below.

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3.2. Existing Supply System

The broad scope of the study area is bounded by the Pioneer River to the north, the coastline to the east, Rosella Zone Substation to the South and the extent of the West Mackay Zone Substation supply area to the west.

This area includes five existing zone substations and one vacant zone substation site. These are listed below:

ALST – Alfred Street 33/11kV Zone Substation

ROSE – Rosella 33/11kV Zone Substation

SOMA – South Mackay 33/11kV Zone Substation

TEST – Tennyson Street 33/11kV Zone Substation

WEMA – West Mackay 33/11kV Zone Substation

OORA – Ooralea 66/11kV Zone Substation (Proposed).

The focus of this study is SOMA South Mackay Substation. The 2012/13 maximum demand on South Mackay substation was 20.1MVA. The N-1 capacity of SOMA is 20.7MVA.

The South Mackay area has been experiencing significant industrial growth in recent years, with several major industrial connection applications and large areas of proposed residential development. South Mackay Zone Substation (SOMA), which supplies the area, has exceeded its N-1 constraint. In addition, a number of the distribution feeders have become heavily loaded and others are forecast to become heavily loaded within two years.

The load on SOMA substation exceeded its N-1 capacity of 20.7MVA with a load of 21.3MVA in 2011/12. Since this time, the load has dropped back to 20.1MVA in 2012/13 due to permanent distribution network load transfers to ALST substation and WEMA substation, but is expected to exceed its N-1 capacity again in 2014/15. After that time any transformer contingency during summer daytime will result in customer load shedding and unsupplied energy.

There are seven 11kV feeders fed from South Mackay Substation. The substation customer load peaked at 20.1MVA during summer 2012/13. There is constraint in the distribution network, one feeder is at capacity and three feeders are currently above their 75% loading, and it is expected that another will hit this limit by 2014/15. Ergon Energy’s planning criteria requires that distribution feeder peak loads should be at or below the feeder 75% rating to allow for ‘4 into 3’ load transfer during feeder outages. It is expected that additional 11kV feeders will be required in the South Mackay area to comply with this criterion after summer 2016/17.

11kV Fault Levels

Subtransient Normal 11kV:

Positive Sequence Impedance (p.u.) Zero Sequence Impedance (p.u.)

0.1261 + j0.8897 0.0333 + j0.6666

Synchronous Normal 11kV:

Positive Sequence Impedance (p.u.) Zero Sequence Impedance (p.u.)

0.1337 + j0.9353 0.0333 + j0.6666

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4. EMERGING NETWORK LIMITATIONS

4.1. Applied Service Standards

The service standards that are applicable to a consideration of supply constraints affecting this area of study are summarised below:

Ergon Energy’s subtransmission network has a risk based planning model that takes into consideration the deterministic “N-1” security of supply criteria, the Value of Customer Reliability (VCR) and Safety Net. Safety Net will protect customers from high impact – low probability events where an upper limit is set for a customer outage consequence for a single contingency event on Ergon’s network. The Safety Net outage magnitude & duration thresholds have been developed to align with the System Average Interruption Duration Indices (SAIDI) consequence that scores the maximum consequence score in Ergon’s Network Risk Analysis.

The distribution network planning criteria threshold so that a 50PoE load should not exceed 0.75 x Normal Cyclic Capacity (NCC) rating of the feeder.

4.2. Limitations of the Existing Network

A load history and forecast for the South Mackay load, is shown in Table 2 below. .

TABLE 2 – South Mackay – Supply Substation Load History & Forecast

Year 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20

SOMA Substation Load (MVA)

Limitation @ N-1 Capacity is: 20.7 MVA

19.2 21.3 20.1 20.6

20.9

22.1

23.1

23.0

24.3

24.7

It is clear from the load data in Table 2 that:-

The loads on South Mackay zone substation exceeded N-1 capacity of 20.7 MVA during summer 2011/12. Given that this load is 20MVA, restoration of supply should occur within 6 hours.

In addition:-

A number of additional large customer loads have been proposed in the area. They have not yet been included in the forecast, as they are not certain, but may have impact on the substation load.

4.3. Distribution Feeder Forecast

The following distribution feeder load forecasts are based on the network configuration which was in place over the 2012/13 summer period. The growth rates which have been applied to each feeder are based on the growth rates from the 2012 Zone Substation Load Forecast. These particular forecasts do not include the proposed major customer connections and show a general forecast only. There are a number of significant customer applications in the area, which would add further load to the distribution network, particularly the Hastings Feeder.

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5 year 5-10 year 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22OH N/A N/AUG 265 199OH N/A N/AUG 265 199OH 269 201UG 300 225OH 353 265UG 300 225OH N/A N/AUG 340 255OH N/A N/AUG 340 255OH 319 239UG 340 255OH 493 370UG 340 255OH 531 398UG 340 255OH 643 482UG 340 255OH N/A N/AUG 310 233OH N/A N/AUG 310 233OH 491 368UG 340 255OH 595 446UG 340 255

425 Hastings

FeederGrowth Rate

Section Rating Security

Actual Forecast

Year

315 Industrial5.90% 4.60% SD UG

5.90% 4.60% SN UG

265 199 249 269 285 302 320 339 354 370 387 405 424 443

228 238265 199 136 145 153 162 172 182 190 199 208 218

316 Borthwicks5.90% 4.60% SD OH 269 201 223 236 250 264 280 297 310 325 339 355 371 388

5.90% 4.60% SN UG 300 225 142 131 139 147 155 165 172 180 188 197 206 216

317 Paget5.90% 4.60% SD UG 340 255 138 143 152 161 170 180 189 197 206 216 226 236

5.90% 4.60% SN UG 340 255 94 93 98 104 110 117 122 128 134 140 146 153

318 Planlands5.90% 4.60% SD OH 319 239 196 212 225 238 252 267 280 292 306 320 335 350

5.90% 4.60% SN UG 340 255 183 204 216 229 242 257 268 281 294 307 321 336

382 CONNORS ROAD5.90% 4.60% SD UG 340 255 200 246 261 276 292 309 324 339 354 370 387 405

5.90% 4.60% SN UG 340 255 88 102 108 115 122 129 135 141 147 154 161 169

383 FARRELLEYS LANE5.90%

5.90%

4.60%

4.60%

SD UG 310 233 201 243 258 273 289

109 115

306 320 335 350

122 130 135 142SN UG 310 233 99 103 148 155 162 170

366 383 401

4.40% 3.60% SD UG 340 255 0 0 137 143 149 156 162 167 173 180 186 193

4.40% 3.60% SN 0 340 255 0 0 62 64 67 70 73 75 78 81 84 87

While there are some distribution works planned to manage this load, capacity is still required to manage the risk in the area by 2014/15, as shown below.

4.4. Timeframes for Taking Corrective Action

In order to ensure that security of supply to customers in the study area complies with Ergon Energy’s planning and security criteria, corrective action should be commenced by summer 2014/15. However the earliest achievable completion date for the first stage of major network augmentation programme is 2016.

A decision about the selected option is required by March 2014 if any option involving significant construction is to be completed by 2016/17.

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4.5. Known Future Network and Generation Development

(i.e. projects that have been approved and are firm to proceed)

Ergon Energy is not aware of any other network augmentations or suitable continuous running generation developments in the study area that could relieve the emerging network limitations described in section 4.0 above.

5. OPTIONS CONSIDERED

5.1. Consultation Summary

During its planning process, Ergon Energy identified that action would be required to address an anticipated distribution network limitation related to supply to the South Mackay area.

On the 28 October 2013 Ergon Energy released a Request for Information providing details on the emerging network limitations in the South Mackay area. That paper sought information from Registered Participants, AEMO and Interested Parties regarding potential solutions to address the anticipated limitations.

Ergon Energy received two submissions by 23 December 2013, being the closing date for submissions to the Request for Information paper.

On 30 January 2014, Ergon Energy released a Consultation and Draft Recommendation Report. Ergon Energy received two submissions by 27 February 2014, being the closing date for submissions.

5.2. Non-Distribution Options Identified

In order to satisfy the Regulatory Test, Ergon Energy sought to identify demand side options or demand side/network combinations that address the network limitations at a lower total present value that the proposed network solution.

To be considered an alternative demand side option, the proposed solution was required to:

Have the capacity to defer the proposed network solution by reducing demand below the identified constraint limits;

Cost less than the savings gained by deferring or removing the proposed network solution; and

Meet all applied service standard requirements.

This analysis identified three feasible demand side alternative options.

5.3. Distribution Options Identified

In addition to the consultation process to identify possible non-network solutions, Ergon Energy carried out studies to determine the most appropriate distribution network solutions. It was considered that a “do nothing” approach was unacceptable. Four feasible corrective solutions were identified, details of which are contained in the following Section 6.

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6. FEASIBLE SOLUTIONS

This section provides an overview of the feasible solutions identified, with full details of the financial analysis contained in Section 0.

Solution Description Total Cost6 NPV Value7

Ergon Energy Internal Option –

Small-Scale Non-Network followed by a New Skid-Substation at Ooralea

$48.1M6 -$22.4M

External Option A –

5MVA Diesel Generation Plant

$64.0M6 -$28.4M

External Option B –

3.5MW Concentrated Solar Power/30MWh Battery/5MW Diesel Hybrid Generation Plant

$61.4M6 -$34.2M

External Option C –

5MVA Diesel Generation Plant

$60.9M6 -$22.9M

6 Figures include escalation of 3% 7 Excluding overheads

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6.1. Option 1 – NNA Program and Establishment of a new 66/11kV Substation with

1x10MVA transformer by 2016/17

Option 1 – Construct Ooralea Substation as a single-transformer skid-mount

Date Req’d Augmentation Capital Cost Operational Cost

2014/15 Commence small-scale non-network (NNA) comprising of demand management and demand response as required

$2,400,0008 over three years

2016/17 Construction of 66kV subtransmission to Ooralea site $ 1,607,000

2016/17 Construction of a 66/11kV single-transformer skid-mount substation and associated distribution feeders at Ooralea

$ 4,806,000

2021/22 Refurbishment of skid $ 2,459,000

2025/26 Construction of a 66/11kV 2x20MVA substation at Ooralea with two additional distribution feeders

$ 10,744,000

This option involves delivery of the following work:-

Utilise small-scale non-network alternatives to reduce load in the South Mackay area by 0.75MVA in 2013/14, 3.65MVA in 2014/15, and 4.75MVA in 2015/16

Establish a single-transformer 1x10MVA skid-mounted substation site already acquired in Ooralea

Install one 66kV feeder bay and upgrade the existing incoming 66kV feeder bay at Racecourse Mill substation

Build approximately 2.5km of 66kV single circuit concrete pole (SCCP) line over canefields from Racecourse Mill to the new Ooralea ZS

Develop three new 11kV feeders from the new Ooralea ZS into the Ooralea and South Mackay suburban area

As the load grows, establish a full 2x20MVA substation at Ooralea to replace the skid-mounted substation

The Option 1 programme of works as proposed will have the following benefits:

Flexibility; network infrastructure can be timed most closely to the load growth

Distribution capacity

Disadvantages of this option are:

Costs and some exposure to lost energy

8 Includes all costs for Empower Program

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6.2. Option 2 – External Diesel Generation – Party A

Option 3 – External Diesel Generation

Date Req’d

Augmentation Capital Cost Operational Cost

2016/17 5MVA of diesel generation – capacity charge $ 1,680,000 p.a. for ten years

2016/17 5MVA of diesel generation – energy charge

Starting at $28,000 in 2016/17, increasing to $1.5M by 2025/26

2025/26 Construction of a 66/11kV 2x20MVA substation at Ooralea with five distribution feeders

$ 31,419,000



Installation of 5MVA (5*1MVA) diesel generation units in the South Mackay Area for a cost of $1,680,000 per annum, plus usage charge of $205/MWh.

Includes $600,000 of network connection costs.

Includes land purchase of 600m2 at a price of $300/sqm

After the contract period, construction of a 2x20MVA substation, with five distribution feeders, at the existing Ooralea site


Minimal upfront capital cost


Lack of new distribution capacity

6.3. Option 3 – External Concentrated Solar/Diesel/Battery – Party B


Date Req’d


2016/17 Construction of 3.5MW Spectrum Concentrated Photovoltaic (CPV) Dish System, 30MWh Deep Cycle Battery Storage Bank and 5MW Diesel generation as backup

$ 1,500,000 p.a. for ten years

2016/17 Energy charge

Starting at $24,000 in 2016/17, increasing to $1.4M by 2025/26


$ 31,419,000



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External Party construction of Construction of 3.5MW Spectrum Concentrated Photovoltaic (CPV) Dish System, 30MWh Deep Cycle Battery Storage Bank and 5MW Diesel generation as backup


Includes land purchase of 56,656m2 at a price of $80/sqm9



Innovative system


High Cost


Large area of land required – 5.6 hectares (56,656m2) – this presents a significant additional cost, which has not been fully explored due to time constraints.

6.4. Option 4 – External Diesel Generation – Party C


Date Req’d


2016/17 5MVA of diesel generation – capacity charge $ 660,000 p.a. for ten years

2016/17 5MVA of diesel generation – energy charge $12/MWh plus fuel


$ 31,419,000



Installation of 5MVA (3*2MW) diesel generation units in the South Mackay Area for a cost of $660,000 per annum, plus usage charge of $12/MWh plus fuel.


Includes land purchase of 600m2 at a price of $300/sqm



Minimal upfront capital cost



9 It is assumed that due to the large land area, the land purchase price would be lower per sqm than a small site

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7. FINANCIAL ANALYSIS & RESULTS

7.1. Format and Inputs to Analysis

7.1.1 Regulatory Test Requirements

The requirements for the comparison of options to address an identified network limitation are contained in the Regulatory Test (version 3, November 2007) prescribed by the AER. The Regulatory Test requires that, for reliability augmentations, the recommended option be the one that “minimises the costs of meeting those requirements, compared with alternative option/s in a majority of reasonable scenarios”. To satisfy the Regulatory Test, the proposed augmentation must achieve the lowest cost in the majority of (but not necessarily all) credible scenarios. The Regulatory Test contains guidelines for the methodology to be used to identify the lowest cost option. Information to be considered includes construction, operating and maintenance costs and the costs of complying with existing and anticipated laws and regulations. The Regulatory Test specifically excludes indirect costs and costs that cannot be measured in terms of financial transactions in the electricity market.

7.1.2 Inputs to Analysis

A solution to address the future supply requirements for the South Mackay area as outlined in this document is required to satisfy reliability requirements linked to Schedule 5.1 of the NER and the requirements of the Queensland Electricity Act 1994. According to the AER’s Regulatory Test, this means that the costs of all options must be compared, and the least cost solution is considered to satisfy the Regulatory Test. The results of this evaluation, carried out using a discounted cash flow model to determine the present value costs of the various options, are shown in section 7.2.2. The cost to implement the network augmentations outlined in section 6 has been estimated by Ergon Energy. Sensitivity studies have been carried out using variations in capital cost estimates of plus or minus 20%. The operating and maintenance costs have been derived as a fixed proportion of capital cost. As a result, a variation in capital costs would be equivalent to separately varying the operating and maintenance cost. The financial analysis considers all foreseeable cost impacts of the proposed network augmentations to market participants as defined by the regulatory process. Estimated savings in the cost of network losses have been excluded from the analysis because they were not found to differ significantly between the four feasible options over the twenty year study period.

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7.2. Financial Analysis

The economic analysis undertaken considered the present value of cost of alternative options over the twenty year period from 2011/12 to 2031/32.

7.2.1 Present Value Analysis

Financial analysis was carried out to calculate and compare the Present Value (PV) of the costs of each option under the range of assumed scenarios. A twenty year analysis period was selected as an appropriate period for financial analysis. A discount rate of 9.99% was selected as a relevant commercial discount rate. The Base Case (Scenario A) was developed to represent the most likely market scenario. The remaining market scenarios were formulated to test the robustness of the analysis to variations in load forecast, capital costs and the discount rate. As required by the Regulatory Test, the lower boundary of the sensitivity testing was the regulated cost of capital. Under the Regulatory Test, it is the ranking of options which is important, rather than the actual present value results. This is because the Regulatory Test requires the recommended option to have the lowest present value cost compared with alternative projects. The following table is a summary of the economic analysis. It shows the present value cost of each alternative and identifies the best ranked option, for the range of scenarios considered. The summary shows that Option 1 – Conduct Non-Network Measures and Establish a Skid Substation at Ooralea has the lowest present value under the majority of scenarios.

7.2.2 Summary of Economic Analysis

Commercial Outcomes excl Overheads ($M) NNA + Skid

Ext A Ext B Ext C

Present Cost of Capex $18.82 $14.39 $18.26 $14.39

Present Cost of Opex $8.25 $19.26 $17.81 $10.43

Present Value of Benefits $4.68 $5.20 $1.88 $1.88

NET PRESENT VALUE / (COST) -$22.39 -$28.44 -$34.19 -$22.94

Value compared to best Option $0.00 -$6.05 -$11.80 -$0.55

Sensitivity Analysis excl Overheads ($M)

NNA + Skid

Ext A Ext B Ext C

Scenario - Base Case -$22.39 -$28.44 -$34.19 -$22.94

1 3 4 2

Scenario - Escalation Opex -High +20% -$24.04 -$32.29 -$37.75 -$25.03

1 3 4 2

Scenario - Escalation Opex -Low -20% -$20.74 -$24.59 -$30.63 -$20.86

1 3 4 2

Scenario - Discount Rate - High 12.00% -$20.01 -$24.77 -$29.55 -$19.40

2 3 4 1

Scenario - Discount Rate - Low [REG] 9.72% -$22.73 -$28.98 -$34.88 -$23.48

1 3 4 2

Scenario - Increased Capital costs +20% -$26.16 -$31.32 -$37.84 -$25.82

2 3 4 1

Scenario - Decreased Capital costs -20% -$18.63 -$25.56 -$30.54 -$20.07

1 3 4 2

Scenario - Commercial Benefits -20% -$23.33 -$29.48 -$34.56 -$23.32

2 3 4 1

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7.3. Discussion of Results

The following conclusions have been drawn from the analysis presented in this report:

• There is no acceptable ‘do nothing’ option. If the emerging network constraints are not addressed by

2016/17, Ergon Energy will not be able to meet its security criteria in the event of a transformer failure at South Mackay substation, resulting in likely loss of supply to network users.

• Economic analysis carried out in accordance with the Regulatory Test has identified that proposed

augmentation described in Option 1, is the least cost solution over the twenty year period of analysis in all scenarios considered.

• Sensitivity testing showed that the analysis is robust to variations in capital costs and the selected

discount rate. • As Option 1 is the lowest cost option in most scenarios, it is considered to satisfy the AER’s

Regulatory Test. It also provides a more viable option operationally.

8. FINAL DECISION & RECOMMENDATION

Based on the conclusions drawn from the analysis in sections 6 and 0 above, it is recommended that Ergon Energy proceeds with Option 1 to:-

Conduct small-scale NNA (non-network alternatives) from 2014/15

Establish a single-transformer Skid-mounted Single-Transformer Substation at Ooralea by 2016/17.

Technical details relevant to the proposed new large distribution asset are contained in section 6.1.

Ergon Energy will commence actions to progress the solution decided on to ensure system reliability is maintained.

regulatory test final recommendation report - … recommendation report ... the study area 11kv...

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