TRANSMISSION CONNECTION PLANNING REPORT

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					TRANSMISSION CONNECTION
    PLANNING REPORT




           Produced jointly by the
Victorian Electricity Distribution Businesses




                    2010
                                                                                  2010 Joint DB Transmission Connection Planning Report




                       TRANSMISSION CONNECTION PLANNING REPORT
          Produced jointly by the five Victorian Electricity Distribution Businesses
                                                   TABLE OF CONTENTS
EXECUTIVE SUMMARY..........................................................................................................2 
1      INTRODUCTION AND BACKGROUND.......................................................................12 
       1.1     Purpose of this report ........................................................................................................ 12 
       1.2     Victorian arrangements for transmission connection planning.......................................... 12 
       1.3     DBs’ obligations and liabilities as transmission connection planners................................ 13 
               1.3.1  Statutory obligations under Victorian regulatory instruments ............................... 13 
               1.3.2  Statutory obligations under the National Electricity Rules.................................... 16 
               1.3.3  Reliability incentive scheme (S factor).................................................................. 17 
               1.3.4  Arrangements to ensure that the availability of connection assets is optimised .. 18 
       1.4     Matters to be addressed by proponents of “non-network” alternatives ............................. 18 
       1.5     Implementing Transmission Connection Projects ............................................................. 20 
               1.5.1  Joint planning in Victoria....................................................................................... 20 
               1.5.2  Land Acquisition ................................................................................................... 20 
               1.5.3  Connection Application to AEMO ......................................................................... 20 
               1.5.4  Connection Application to SPI PowerNet ............................................................. 21 
               1.5.5  Contestable procurement of transmission connection works ............................... 21 
               1.5.6  Town Planning Permit........................................................................................... 21 
               1.5.7  Public Consultation Strategy................................................................................. 22 
               1.5.8  Project Implementation ......................................................................................... 22 
               1.5.9  Project lead times ................................................................................................. 23 
       1.6     Overview of Transmission Connection Planning Process................................................. 24 
2      PLANNING STANDARDS ............................................................................................25 
       2.1     Overall objective of transmission connection planning ..................................................... 25 
       2.2     Overall approach to transmission planning and investment evaluation ............................ 26 
       2.3     Valuing supply reliability from the customers’ perspective................................................ 26 
       2.4     Application of the probabilistic approach to transmission connection planning ................ 30 
       2.5     The connection augmentation criterion ............................................................................. 30 
3      HISTORIC AND FORECAST DEMAND .......................................................................32 
4      RISK ASSESSMENT AND OPTIONS FOR ALLEVIATION OF CONSTRAINTS........33 
       4.1     Preamble ........................................................................................................................... 33 
       4.2     Interpreting “energy at risk” ............................................................................................... 34 
       4.3     Assessing the costs of transformer outages ..................................................................... 35 
       4.4     Base reliability statistics for transmission plant ................................................................. 36 
       4.5     Availability of spare transformers ...................................................................................... 37 
       4.6     Treatment of Load Transfer Capability.............................................................................. 38 
       4.7     Detailed risk assessments and options for alleviation of constraints, by terminal station. 38 
APPENDIX: ESTIMATION OF BASIC TRANSFORMER RELIABILITY DATA AND SAMPLE
    OF EXPECTED TRANSFORMER UNAVAILABILITY CALCULATION ......................40 




                                                                    Page 1
                                                              2010 Joint DB Transmission Connection Planning Report




EXECUTIVE SUMMARY
In Victoria the five Distribution Businesses (“the DBs”) 1 have responsibility for planning and
directing the augmentation of the facilities that connect their distribution systems to the shared
transmission network 2 . The interface assets connecting the DBs’ distribution networks to the
shared transmission network are known as transmission connection assets. These assets are
located within terminal stations which are owned, operated, and maintained by the transmission
asset owner, SPI PowerNet.

This paper sets out a joint report on transmission connection asset planning in Victoria, prepared
by the DBs, in accordance with the requirements of their Distribution Licences and the Victorian
Distribution Code.

Pursuant to section 50C of the National Electricity Law (NEL), the Australian Energy Market
Operator (AEMO, formerly VENCorp) is responsible for planning, authorising, contracting for,
and directing augmentation of the Victorian shared transmission network. In accordance with
section 50C of the NEL, AEMO applies a probabilistic approach to planning the Victorian shared
transmission network. Under that approach, investment only proceeds when the expected
(probability-weighted) benefit exceeds the cost. The probabilistic approach involves estimating the
probability of a transmission plant outage occurring within the peak loading season, and weighting
the costs of such an occurrence by its probability. This calculation enables the assessment of:

•    the amount (and value) of energy that is expected not to be supplied if no augmentation is
     undertaken, and therefore
•    whether it is economic to augment terminal station capacity to reduce or limit expected supply
     interruptions.

The transmission connection assets for which the DBs have planning responsibility form part of
the Victorian Electricity Transmission System. Given that AEMO applies a probabilistic network
planning approach to the development of the Victorian shared transmission network, the Victorian
DBs consider it appropriate to adopt a similar approach by applying the following investment
criterion:

A project aimed at alleviating a transmission connection capacity constraint should proceed if it
maximises the net present value to customers, having regard to:
•   the relative costs and benefits, including changes in supply reliability, of network
    augmentation and non-network alternatives to augmentation;
•   the potentially high costs faced by customers if low-probability, high impact events occur
    and result in outages of key transmission connection assets at times of peak demand;
•   the expectations of customers and other stakeholders regarding the maintenance of reliable
    electricity supply;
•   the objective of minimising total life-cycle costs;
•   the strong scale economies that exist within the electricity transmission and distribution
    sectors; and
•   the need to comply with environmental and land-use planning standards, health and safety
    standards, and applicable technical standards.



1
       The five DBs are: Jemena Electricity Networks (Vic) Ltd, CitiPower, Powercor Australia, United Energy
       Distribution, and SPI Electricity. SPI Electricity is owned by SP AusNet, a business that is made up of the
       SPI PowerNet electricity transmission business, and the gas and electricity distribution assets formerly
       owned by TXU. Throughout this document “SPI PowerNet” refers to the transmission part of SP AusNet
       and “SPI Electricity” refers to the electricity distribution part of SP AusNet.
2
       The shared transmission network is the main extra high voltage network that provides or potentially
       provides supply to more than a single point. This network includes all lines rated above 66 kV and main
       system tie transformers that operate at two or three voltage levels above 66 kV.


                                                    Page 2
                                                      2010 Joint DB Transmission Connection Planning Report




The DBs’ regulatory obligations in relation to their transmission connection planning roles are
set out in the Victorian Electricity Distribution Code and the Distribution Licences issued by
the Essential Services Commission. Clause 3.4 of the Distribution Code requires the DBs to
publish each year a Transmission Connection Planning Report that provides, amongst other
things, the following information:

•   an assessment of the magnitude, probability and impact of loss of load for each
    transmission connection;

•   details of each distributor’s planning standards; and

•   a description of feasible options for meeting forecast demand at each transmission
    connection including opportunities for embedded generation and demand management.

The assessment presented in this report, and summarised in the table on the following pages
sets out the DBs’ Transmission Connection Planning Report for 2010. It is emphasised that
this report does not present detailed investment decision analyses. Rather, the report
presents a high-level indication of the expected balance between capacity and demand at
each terminal station over the forecast period.

Data presented in this report may indicate an emerging major constraint. Therefore, this
report provides a means of identifying those terminal stations where more detailed analyses of
risks and options for remedial action are required. This report also provides preliminary
information on potential opportunities to prospective proponents of alternatives to network
augmentations at stations where remedial action may be required. Providing this information
to the market should facilitate the efficient development of the network to best meet the needs
of end-customers.

Parties seeking further information about these potential opportunities, or any other matter
contained in this report should contact any one of the following people:

•   Neil Gascoigne, System Planning & Secondary Systems Manager, CitiPower / Powercor,
    phone 9683 4472.

•   Nilima Bapat, Senior Electrical Engineer, SP AusNet, phone 9695 6215 (for matters
    relating to SPI Electricity).

•   Din Mafaakher, Senior Planning Engineer, Jemena (the prime contractor for the electricity
    network owned by United Energy Distribution) phone 8544 9238 (for matters relating to
    United Energy Distribution).

•   Tan Bui, Senior Planning Engineer, Jemena, phone 8544 9589 (for matters relating to
    Jemena Electricity Networks (Vic) Ltd).

Any one of these contact officers will either be able to answer your queries or will direct you to
the organisation that is best placed to provide you with the information you are seeking.




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                                                               2010 Joint DB Transmission Connection Planning Report




As noted above, the distributors are required to provide, among other things, an indication of
the magnitude, and potential impact of loss of load for each transmission connection. This
information is provided in the table below, in the form of estimates of “expected unserved
energy” 3 for each terminal station in the year in which augmentation of the terminal station is
likely to be required, for two forecasts of demand: the first forecast has a 10% probability of
being exceeded, while the second forecast has a 50% probability of being exceeded.

For each terminal station, the table also identifies alternatives to network augmentation that
may alleviate constraints. Following the summary table is a map showing the approximate
locations of the SPI PowerNet-owned connection terminal stations.

Finally, it is noted that as conditions change and as new information becomes available, the
indicative timing of any remedial action required to address an emerging constraint may
change from one year to the next. For instance, changes in demand forecasts from one year
to the next may result in changes in the timing of remedial action at some stations. Further
details are set out in the individual risk assessments for each of the terminal stations.




3
       Throughout this report, the terms “energy at risk” and “expected unserved energy” are used to provide an
       indication of the magnitude, and potential impact of loss of load for each terminal station. In this report:
                “Energy at risk” is, for a given forecast of demand, the total energy that would not be supplied
                from a terminal station if: a major outage of a transformer occurs at that station in a specified
                year; the outage has a mean duration of 2.6 months; and no other mitigation action is taken.
                This statistic provides an indication of the magnitude of loss of energy that would arise in the
                unlikely event of a major outage of a transformer.
                “Expected unserved energy” is the energy at risk weighted by the probability of a major outage of
                a transformer, where a “major outage” is defined as one that has a mean duration of 2.6 months.
                This statistic provides an indication of the amount of energy, on average, that will not be supplied
                in a year, taking into account the very low probability that one transformer at the station will not
                be available because of a major outage.


                                                     Page 4
                                                                                                                           2010 Joint DB Transmission Connection Planning Report




Summary of risk assessment and options for alleviation of constraints
                       Indicative
                                         Expected unserved energy for the
                       timing for                                                                                       Indicative annual cost
                                        year shown in the column to the left                                                                         Potentially feasible non-
Terminal Station     completion of                                                   Preferred network solution          of preferred network
                                         (in MWh, and valued at customer                                                                                network solutions
                       preferred                                                                                               solution
                                                interruption cost)
                        network
                        solution        10th percentile       50th percentile
                                       demand forecast       demand forecast
Altona – Brooklyn   Not before 2016         37.2 MWh              9 MWh           Implement load transfers to ATS      Included in the cost of      Demand reduction; Local
(ATS/BLTS)                                 ($2 million)         ($493,000)        West following planned               works planned at ATS         generation
                                                                                  augmentation works there in 2018.    West
Altona no 3 & 4     Not before 2016    106 MWh in 2020       68 MWh in 2020       Install additional transformation           $1.3 million          Demand reduction; Local
(ATS West) 66 kV                          ($5 million)        ($3.2 million)      capacity and reconfigure 66 kV                                    generation
                                                                                  exits at ATS.
Ballarat (BATS)     Not before 2020         0.6 MWh             0.15 MWh          Install an additional transformer.          $1.2 million          Demand reduction; Local
                                            ($31,000)            ($8,200)                                                                           generation
Bendigo (BETS)         Late 2013           96.6 MWh              46 MWh           Install two new 75 MVA 230/22 kV            $2.5 million          No firm offers from
                                         ($5.8 million) in    ($2.8 million) in   transformers. This option will                                    proponents of non-network
                                              2013                 2013           separate the 66 kV and 22 kV                                      alternatives were received
                                                                                  points of supply and transfer load                                in relation to Powercor’s
                                                                                  from the existing transformers.                                   proposal (foreshadowed in
                                                                                                                                                    the 2008 and 2009
                                                                                                                                                    Transmission Connection
                                                                                                                                                    Planning Reports) so
                                                                                                                                                    Powercor is proceeding
                                                                                                                                                    with augmentation.
Brooklyn 22 kV           2020               6.3 MWh              3.9 MWh          Transfer 22 kV load away to          Not estimated at this time   Demand reduction; Local
(BLTS 22 kV)                               ($353,000)           ($217,000)        adjacent zone substations when                                    generation
                                                                                  capacity is available.
Brunswick 22 kV     Following completion of the station refurbishment by SPI PowerNet in early 2007, no augmentation of capacity is expected to be required within the ten year
(BTS 22 kV )        planning horizon.




                                                                                   Page 5
                                                                                                                             2010 Joint DB Transmission Connection Planning Report




                      Indicative
                                          Expected unserved energy for the
                      timing for                                                                                         Indicative annual cost
                                         year shown in the column to the left                                                                          Potentially feasible non-
Terminal Station    completion of                                                     Preferred network solution          of preferred network
                                          (in MWh, and valued at customer                                                                                 network solutions
                      preferred                                                                                                 solution
                                                 interruption cost)
                       network
                       solution          10th percentile      50th percentile
                                        demand forecast      demand forecast
Brunswick 66 kV          2014           BTS 66 kV will reinforce the security of supply to the northern and inner areas of the Central Business District (CBD) and hence reduce
(BTS 66 kV)                             the level of reliance of CBD supply from WMTS, which presently accounts for about 50% of the CBD load. BTS 66 kV will remove
                                        loading constraints at WMTS 66 kV, WMTS 22 kV and RTS 66 kV, and also provide future supply to local suburban areas. It is
                                        proposed that, 3x225 MVA 220/66 kV transformers will be installed at BTS 66 kV. CitiPower applied the Regulatory Test and published
                                        a Consultation Report on 26 May 2006, regarding the proposed upgrade of BTS. No submissions were received in response to that
                                        consultation paper. Accordingly the preliminary recommendation - to establish a new 66 kV point of supply at BTS - was adopted. In
                                        2010, the City of Moreland rejected the planning permit submitted by SPI PowerNet. A new planning proposal is being prepared for
                                        Council approval. A new Regulatory Test is to be undertaken in 2011 due to the expected increased cost of establishing BTS. Subject
                                        to the outcomes of the Regulatory Test and planning approval process, the revised date for the commissioning of BTS is 2014. Any
                                        further delays resulting from the planning process and increase in SPI PowerNet’s project delivery lead times will be beyond the control
                                        of CitiPower.
Cranbourne            Late 2013         67.6 MWh in 2014      48.3 MWh in 2014     Install a fourth transformer.               $1.5 million           Demand reduction; Local
66 kV (CBTS 66                             ($4 million)         ($2.9 million)                                                                        Generation. Any non-
kV)                                                                                                                                                   network proposal must be
                                                                                                                                                      submitted with detailed
                                                                                                                                                      plans to SPI Electricity or
                                                                                                                                                      United Energy Distribution
                                                                                                                                                      for consideration no later
                                                                                                                                                      than 31 March 2011.
East Rowville      Not before 2020          6.3 MWh               2.8 MWh          Off-load ERTS by transferring              Not estimated           Demand reduction; Local
(ERTS)             (following              ($424,000)            ($187,000)        Hampton Park zone substation                                       Generation. .
                   commissioning of                                                onto CBTS
                       th
                   a 4 transformer in
                   December 2011)
Fishermans Bend        2018/19              315 MWh              19.4 MWh          Implement auto-switching on the               $45,000              Demand reduction;
(FBTS)                                    ($28.8 million)       ($1.8.million)     66 kV bus tie CB to allow all 3                                    Local generation. Any non-
                                                                                   transformers to operate.                                           network proposal must be
                                                                                                                                                      submitted with detailed
                                                                                                                                                      plans to CitiPower for
                                                                                                                                                      consideration no later than
                                                                                                                                                      June 2013.




                                                                                    Page 6
                                                                                                                             2010 Joint DB Transmission Connection Planning Report




                      Indicative
                                        Expected unserved energy for the
                      timing for                                                                                         Indicative annual cost
                                       year shown in the column to the left                                                                           Potentially feasible non-
Terminal Station    completion of                                                    Preferred network solution           of preferred network
                                        (in MWh, and valued at customer                                                                                  network solutions
                      preferred                                                                                                 solution
                                               interruption cost)
                       network
                       solution         10th percentile       50th percentile
                                       demand forecast       demand forecast
Frankston (FTS)                            0.12 MWh                               Upgrade 66 kV circuits.                        $80,000              Demand reduction;
                   Not before 2020                                Minimal
                                            ($7,900)                                                                                                  Local Generation
Geelong (GTS)      In November 2008, Powercor published an Application Notice in relation to the proposed augmentation of Geelong Terminal Station. In accordance with
                   the Notice, a fourth 220/66 kV transformer, to be operated initially on “normal open, auto-close” duty has been installed. Powercor now proposes to
                   proceed with the second stage of this project, which involves works to enable the permanent switching of the fourth transformer on load. The latest analysis
                   of the magnitude, probability and impact of loss of load confirms that proposed works are required to be completed in 2012, to support the peak summer
                   demand for system normal conditions. The indicative annualised cost of these works is estimated to be $0.5 million. Proponents of non-network
                   alternatives should submit detailed proposals to Powercor no later than June 2011.
Glenrowan          Not before 2020         1.6 MWh               0.5 MWh          Install a 3rd 220/66 kV                      $1.3 million           Demand reduction;
(GNTS)                                    ($105,000)             ($30,000)        transformer.                                                        Local Generation
Heatherton (HTS)   Not before 2020        10.8 MWh                6.7 MWh         Install a fourth transformer.                $1.4 million           Demand reduction;
                                          ($760,000)             ($470,000)                                                                           Local Generation
Horsham (HOTS)     No augmentation of capacity is expected to be required within the ten year planning horizon.
Heywood (HYTS      A 22 kV point of supply was established in late 2009, by utilising the tertiary 22 kV on the existing 2 x 500/275/22 kV South Australian / Victorian
22 kV)             interconnecting transformers. The station presently supplies a single 22 kV customer. There is sufficient capacity at the station to supply all expected 22
                   kV load over the forecast period, even with one transformer out of service.
Keilor (KTS)             2013             167 MWh in           97.9 MWh in        Install a 100 MVAr capacitor bank          $600,000 for the         Any non-network proposal
                                            2016/17              2016/17          on the KTS(B34) group, then               capacitor bank and        must be submitted with
                                          ($10 million)        ($5.9 million)     proceed with the development of a        $7 million for the new     detailed plans to
                                                                                  new Terminal Station at Deer Park          Terminal Station.        Jemena EN or Powercor
                                                                                                                                                      for consideration no later
                                                                                                                                                      than December 2011.
Kerang (KGTS)      At the 50th percentile demand forecast, there is sufficient capacity to meet all demand at the station over the ten year planning horizon, even with one
                                                                                          th
                   transformer out of service. From 2018, there is load at risk at the 10 percentile temperature for the loss of a transformer and it is planned to use mobile
                   generation to provide network support in the event that a transformer outage would otherwise lead to load shedding..
Malvern 22 kV      SPI PowerNet completed the replacement of ageing transformers and switchgear including protection and control equipment in December 2007. Following
(MTS 22 kV)        completion of that work no augmentation of capacity is expected to be required at MTS 22 kV within the ten year planning horizon.
Malvern 66 kV      Not before 2020          1 MWh                0.1 MWh          Install a third transformer                   $1.6 million          Demand reduction;
(MTS 66 kV)                                ($60,800)             ($7,700)                                                                             Local Generation




                                                                                   Page 7
                                                                                                                               2010 Joint DB Transmission Connection Planning Report




                   Indicative timing      Expected unserved energy for the
                                                                                                                            Indicative annual cost
   Terminal        for completion of     year shown in the column to the left                                                                           Potentially feasible non-
                                                                                       Preferred network solution            of preferred network
    Station             preferred          (in MWh, and valued at customer                                                                                 network solutions
                                                                                                                                   solution
                        network                    interruption cost)
                        solution          10th percentile      50th percentile
                                         demand forecast demand forecast
Morwell            2012 (assuming        44.9 MWh in 2011     27.2 MWh in 2011      Install a new fourth 220/66 kV           $1.5 million (for fourth   Continued availability of
(MWTS)             Bairnsdale Power         ($3 million)        ($1.8 million)      transformer at MWTS.                          transformer)          Bairnsdale and Morwell
                   Station is                                                                                                                           Power Stations will defer
                   unavailable and                                                                                                                      the need for network
                   Morwell Power                                                                                                                        augmentation.
                   Station output is
                   50 MVA)
Mount Beauty       At times of high demand and with low output from Clover Power Station a transformer outage at MBTS could result in the loss of some customer load for a
(MBTS)             period of no more than 4 hours. The corresponding value of expected unserved energy is approximately $6,500 in 2020. Installation of full switching of the
                   hot spare transformer at MBTS to eliminate this risk is estimated to cost around $1.6 million so it would not be economic to carry out this work during the 10
                   year planning horizon.
Red Cliffs 22 kV   There is sufficient capacity at the station to supply all expected load over the forecast period, even with one transformer out of service. Therefore, the need
(RCTS 22 kV)       for augmentation or other corrective action is not expected to arise over the next ten years.
Red Cliffs 66 kV   Once load is transferred to WETS in early 2011, there will be sufficient capacity at the station to supply all demand expected until 2019, even with one
(RCTS 66 kV)       transformer out of service. Any load at risk in 2009 for the 10th percentile demand scenario will be managed by transferring load to RCTS 22 kV. Therefore,
                   the need for augmentation or other corrective action is not expected to arise at RCTS 66 over the next ten years. Prior to the commissioning of WETS, load
                   at risk at RTCS 66 kV will be reduced through a contingency plan to transfer load to the RCTS 22 kV bus in the event of an outage at RCTS 66 kV.
Richmond           No augmentation of capacity is expected to be required within the ten year planning horizon.
22 kV (RTS
22 kV)
Richmond              2014 - 2015        184 MWh in 2014       54.7 MWh in 2014     Permanently transfer load away to      $3.5 million for terminal    Demand reduction;
66 kV (RTS                                ($16.6 million)        ($4.9 million)     the proposed BTS 66 kV via both        station and                  Local generation.
66 kV)                                                                              the high voltage distribution and      subtransmission works        CitiPower and United
                                                                                    subtransmission networks from          required to effect           Energy Distribution would
                                                                                    2014 and 2015 respectively.            subtransmission load         welcome proposals from
                                                                                                                           transfers (based on 2009     potential providers of
                                                                                                                           Transmission                 network support to reduce
                                                                                                                           Connection Planning          the load at risk at RTS 66
                                                                                                                           Report).                     kV over the period to
                                                                                                                                                        2014– 2105. Please
                                                                                                                                                        contact CitiPower or United
                                                                                                                                                        Energy Distribution for
                                                                                                                                                        further information. .



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                                                                                                                           2010 Joint DB Transmission Connection Planning Report




   Terminal     Indicative timing     Expected unserved energy for the
                                                                                                                        Indicative annual cost
    Station     for completion of    year shown in the column to the left                                                                             Potentially feasible non-
                                                                                   Preferred network solution            of preferred network
                     preferred        (in MWh, and valued at customer                                                                                    network solutions
                                                                                                                               solution
                network solution               interruption cost)
                                      10th percentile      50th percentile
                                     demand forecast demand forecast
Ringwood              2020                2.5 MWh              0.7 MWh          Install a third transformer            $1.2 million                   Demand reduction;
22 kV (RWTS                              ($138,000)            ($39,000)                                                                              Local generation.
22 kV)
Ringwood              2016                70 MWh               24MWh            Further investigate the following         Not yet determined.         Demand Reduction;
66 kV (RWTS                              ($4 million)       ($1.35 million)     options: installation of a fifth         (The indicative cost of      Embedded generation.
66 kV)                                                                          220/66 kV transformer at RWTS;                installing a 5th        Any non-network proposal
                                                                                installation of a fourth transformer    transformer at RWTS is        must be submitted with
                                                                                at TSTS; installation of new 66 kV        estimated to be $1.4        detailed plans to SPI
                                                                                capacitor banks at RWTS; or                million per annum)         Electricity or United Energy
                                                                                development of a new terminal                                         Distribution for
                                                                                station at Doncaster or                                               consideration no later than
                                                                                Coldstream.                                                           June 2011.
Shepparton      No augmentation of capacity is expected to be required within the ten year planning horizon.
(SHTS)
South Morang          2015                80.3 MWh            42.7 MWh         Install a third 225 MVA 220/66 kV       $1.7 million (including the    Demand Reduction
(SMTS) .                                 ($5 million)        ($2.7 million)    transformer at SMTS.                    cost of three fault limiting   Embedded generation
                                                                                                                                reactors)
Springvale       Not before 2020          13.3 MWh             8.6 MWh         Install 3rd transformer at MTS to         $1.6 million excluding       Demand reduction;
(SVTS)                                   ($1 million)         ($675,000)       enable SVTS to be offloaded.                66 kV line works           Local generation
Templestowe      Not before 2020         15.1 MWh              7.7 MWh         Install an additional transformer at           $1.4 million            Demand reduction;
(TSTS)                                   ($798,000)           ($409,000)       the station.                                                           Local generation
Thomastown       Not before 2019         11.7 MWh              0.7 MWh         Develop a new terminal station at               $6 million             Demand reduction;
(TTS)                                    ($700,000)            ($39,000)       either Donnybrook or Somerton.                                         Local generation
Terang (TGTS)         2020               10.9 MWh              4.2 MWh         Install an additional transformer.             $1.3 million            Demand reduction;
                                         ($840,000)           ($325,000)       Impact of embedded wind                                                Local generation
                                                                               generation may defer timing.




                                                                                 Page 9
                                                                                                                    2010 Joint DB Transmission Connection Planning Report




  Terminal     Indicative timing    Expected unserved energy for the          Preferred network solution        Indicative annual cost of       Potentially feasible
   Station     for completion of   year shown in the column to the left                                            preferred network           non-network solutions
                    preferred        (in MWh, and valued at customer                                                     solution
               network solution              interruption cost)
                                    10th percentile      50th percentile
                                   demand forecast demand forecast
Tyabb (TBTS)         2013            46.1 MWh              40.3 MWh        Installation of 3rd transformer.             $1.5 million           Demand reduction;
                                    ($2.6 million)        ($2.2 million)                                                                       Local Generation. Any
                                                                                                                                               non-network proposal
                                                                                                                                               must be submitted with
                                                                                                                                               detailed plans to United
                                                                                                                                               Energy Distribution for
                                                                                                                                               consideration no later
                                                                                                                                               than 31 March 2011.
Wemen                2020              12 MWh              8.9 MWh         Installation of a second                     $1.2 million           Demand reduction;
(WETS)                               ($1.1 million)       ($816,000)       transformer.                                                        Local generation
West Melb            2015              3.4 MWh             0.5 MWh         Transfer load permanently to the     Costs of this project relate   Demand reduction;
22 kV (WMTS                           ($305,000)           ($45,000)       BTS 66 kV (which is expected to      principally to replacement     Local generation
22 kV)                                                                     be commissioned in 2014) in          and upgrading of
                                                                           conjunction with the existing        distribution assets. Refer
                                                                           Distribution System Plan, under      to CitiPower’s Distribution
                                                                           which the capacity of a local zone   System Planning Report
                                                                           substation will be upgraded.         for details.
West Melb        2013 - 2014          5795 MWh            164 MWh          Permanently transfer load away to    Refer to the Distribution      Demand management,
66 kV (WMTS                          ($581 million)     ($16.4 million)    BTS 66 kV via both the high          System Planning Report.        until the new BTS 66 kV
66 kV)                                                                     voltage distribution and                                            station is completed.
                                                                           subtransmission networks.
Wodonga              2014            22.3 MWh             15.1 MWh         SPI Electricity is currently                  $1 million            Demand management,
(WOTS)                              ($1.5 million)       ($1 million)      negotiating arrangements for                                        until network support
                                      excluding           excluding        network support with a proponent                                    arrangements are in
                                   generation from     generation from     who is expected to establish a                                      place.
                                   Hume PS or any      Hume PS or any      new power station at Wodonga.
                                    other source        other source       An agreement for network support
                                                                           will allow installation of a third
                                                                           transformer to be deferred for at
                                                                           least 4 to 5 years.




                                                                           Page 10
      2010 Joint DB Transmission Connection Planning Report




Page 11
                                                        2010 Joint DB Transmission Connection Planning Report




1 INTRODUCTION AND BACKGROUND

1.1   Purpose of this report

This paper sets out a joint report on transmission connection asset planning in Victoria,
prepared by the five Victorian electricity Distribution Businesses (the DBs) 4 , in
accordance with the requirements of their distribution licences, the Victorian Distribution
Code and, where applicable, the National Electricity Rules.

1.2   Victorian arrangements for transmission connection planning

Transmission connection assets are those parts of the transmission system which are
dedicated to the connection of generator(s) or customer(s) at a single point within the
transmission system. In Victoria:

•     the DBs have responsibility for planning and directing the augmentation of the
      facilities that connect their distribution systems to the Victorian shared transmission
      network; 5 and

•     The Australian Energy Market Operator (AEMO, formerly VENCorp) 6 is responsible
      for planning and directing the augmentation of the shared transmission network.

Figure 1 below illustrates the distinction between the shared transmission network and
transmission connection assets.




       Figure 1: Shared network and connection assets in a notional network
             (Source: VENCorp Electricity Annual Planning Review, 2009, page 17)



4
       The five DBs are: Jemena Electricity Networks (Vic) Ltd, CitiPower, Powercor Australia, United
       Energy Distribution, and SPI Electricity. SPI Electricity is owned by SP AusNet, a business that is
       made up of the SPI PowerNet electricity transmission business, and the gas and electricity
       distribution assets formerly owned by TXU. Throughout this document “SPI PowerNet” refers to the
       transmission part of SP AusNet and “SPI Electricity” refers to the distribution part of SP AusNet.
5
       The shared transmission network is the main extra high voltage network that provides or potentially
       provides supply to more than a single point. This network includes all lines rated above 66 kV and
       main system tie transformers that operate at two or three voltage levels above 66 kV.
6
       VENCorp’s responsibilities for planning and directing the augmentation of the Victorian electricity
       transmission shared network were transferred to AEMO on 1 July 2009.




                                               Page 12
                                                        2010 Joint DB Transmission Connection Planning Report




These planning arrangements are aimed at fostering efficient and coordinated
development of transmission connection facilities and the downstream sub-transmission
and distribution systems. The DBs are best placed to determine the optimum level of
investment in, and configuration of, distribution system capacity and transmission
connection capacity, having regard to:

•       the needs and preferences of the end consumers of electricity;

•       the relative costs and benefits associated with alternative distribution, sub-
        transmission and transmission connection development strategies, and alternative
        strategies that would deliver a level of supply reliability in accordance with
        consumers’ needs; and

•       the direct and indirect incentives (and penalties) faced by the DBs in relation to the
        reliability of their distribution networks and the transmission connection facilities
        that they plan.

The present arrangements and responsibilities for transmission connection planning were
reviewed by the VPX Board 7 in 1997. That review sought input from the Office of the
Regulator-General (ORG), 8 the Energy Policy Division of the Department of Treasury and
Finance, the DBs and PowerNet Victoria 9 , on the issue of responsibility for connection
planning. Following the review, the present arrangements were affirmed, and the
Victorian Distribution licences were amended to clarify the transmission connection asset
planning responsibilities of the DBs.

The transmission planning responsibilities of VENCorp’s successor (AEMO) are set out in
section 50C(1) of the National Electricity (South Australia) (National Electricity Law—
Australian Energy Market Operator) Amendment Act 2009. Under that act, AEMO’s
functions include: “to plan, authorise, contract for, and direct, augmentation of the
declared shared network”, where the declared shared network is defined as “the adoptive
jurisdiction’s [in this case, Victoria’s] declared transmission system excluding any part of it
that is a connection asset within the meaning of the Rules”.

1.3     DBs’ obligations and liabilities as transmission connection planners

1.3.1   Statutory obligations under Victorian regulatory instruments

Clause 14 of each DB’s Distribution Licence states:

        “The Licensee is responsible for planning, and directing the augmentation of,
        transmission connection assets to assist it to fulfil its obligations [to offer connection
        services and supply to customers] under clause 6.”


The licence defines “transmission connection assets” as:




7
        The electricity transmission network planning and related responsibilities of the former VPX were
        transferred to VENCorp in 1999.
8
        On 1 January 2002, the regulatory functions of the Office of the Regulator-General were subsumed
        by the Essential Services Commission (“ESC”).
9
        PowerNet Victoria was the Victorian transmission network owner at the time.




                                                Page 13
                                                     2010 Joint DB Transmission Connection Planning Report



       “those parts of an electricity transmission network which are dedicated to the connection of
       customers at a single point, including transformers, associated switchgear and plant and
       equipment.”


Clause 3.1(b) of the Distribution Code states:

       “A distributor must use best endeavours to develop and implement plans for the
       acquisition, creation, maintenance, operation, refurbishment, repair and disposal of its
       distribution system assets and plans for the establishment and augmentation of
       transmission connections:

       •   to comply with the laws and other performance obligations which apply to the
           provision of distribution services including those contained in this Code;

       •   to minimise the risks associated with the failure or reduced performance of assets;
           and

       •   in a way which minimises costs to customers taking into account distribution losses.”

In the Distribution Code, the terms:

•   “distribution losses” means electrical energy losses incurred in distributing electricity
    over a distribution system; and

•   “distribution system” in relation to a distributor, means a system of electric lines and
    associated equipment at nominal voltage levels of 66 kV or below.

In accordance with their obligations to plan their distribution systems to minimise costs to
customers taking into account distribution losses, the DBs also apply the same approach
in the planning and development of transmission connection assets. That is to say, the
DBs plan and direct the augmentation of the transmission connection assets in a way
which minimises costs to customers taking into account distribution losses and
transmission losses.

Clause 3.4 of the Distribution Code states:

       “3.4.1   Together with each other distributor, a distributor must submit to the Commission
                a joint annual report called the ‘Transmission Connection Planning Report’
                detailing how together all distributors plan to meet predicted demand for electricity
                supplied into their distribution networks from transmission connections over the
                following ten calendar years.

       3.4.2    The report must include the following information:
                (a)     the historical and forecast demand from, and capacity of, each
                        transmission connection;
                (b)     an assessment of the magnitude, probability and impact of loss of load for
                        each transmission connection;
                (c)     each distributor’s planning standards;
                (d)     a description of feasible options for meeting forecast demand at each
                        transmission connection including opportunities for embedded generation
                        and demand management and information on land acquisition where the
                        possible options are constrained by land access or use issues;
                (e)     the availability of any contribution from each distributor including where
                        feasible, an estimate of its size, which is available to embedded




                                              Page 14
                                                    2010 Joint DB Transmission Connection Planning Report



                       generators or customers to reduce forecast demand and defer or avoid
                       augmentation of a transmission connection; and
               (f)     where a preferred option for meeting forecast demand has been identified,
                       a description of that option, including its estimated cost, to a reasonable
                       level of detail.

      3.4.3   Each distributor must publish the Transmission Connection Planning Report on its
              website and, on request by a customer, provide the customer with a copy. The
              distributor may impose a charge (determined by reference to its Approved
              Statement of Charges) for providing a customer with a copy of the report.”


The Distribution Code was amended in March 2008 to include an additional provision
(clause 3.1A) relating to the security of supply of the Melbourne CBD. This provision
describes the circumstances in which the Melbourne CBD distributor (currently CitiPower)
is required to prepare a CBD security of supply upgrade plan and also sets out the
required scope of that plan. In particular, the CBD security of supply upgrade plan must:

(a) specify strengthened security of supply objectives for the Melbourne CBD and a date
    or dates by which those objectives must be met;

(b) specify the capital and other works proposed by the Melbourne CBD distributor in
    order to achieve the security of supply objectives for the Melbourne CBD that are
    specified in the plan; and

(c) meet the regulatory test (which is discussed in further detail in section 1.3.2 below).

This provision establishes a separate planning process that applies to the Melbourne
CBD only.

Given that this transmission connection planning report covers the whole of Victoria, it
should acknowledge the existence of any CBD security of supply upgrade plan without
unnecessarily duplicating that plan and the supporting analysis. In this regard, it is noted
that in July 2008, CitiPower announced that it is investing $52 million to upgrade
substations, sub-transmission lines and feeder cables that service the Melbourne CBD as
part of the CBD Security of Supply Upgrade. This announcement followed a Final
Decision by the ESC which stated:

       “The Commission has considered CitiPower’s application [for pass-through of the costs of
       the CBD security of supply upgrade] and is satisfied that the required information has been
       provided, is accurate and sufficiently comprehensive and complies with the conditions set
       out in the EDPR. The Commission’s review of the information provided affirms that the
       application addresses the issues raised by the Commission in the EDPR and in the Code
       change process.

       Consequently, the Commission considers that the pass through application should be
       approved. CitiPower will be entitled to recover its costs associated with the pass through
       over the course of the current EDPR decision to 31 December 2010. The recovery will
       commence from 1 August 2008.”

The upgrade will protect Melbourne's electricity supply from a prolonged blackout should
there be major failures (i.e. the loss of two or more major connections) within the
electricity networks supplying this area. The relevant transmission connection works
(namely, the establishment of a new 66 kV source of supply at Brunswick Terminal
Station) are a separate project, but are related to the CBD upgrade project. These
proposed connection works are identified in this Transmission Connection Planning




                                            Page 15
                                                          2010 Joint DB Transmission Connection Planning Report




Report. It is noted however that the Brunswick Terminal Station (BTS) investment is now
subject to a re-application of the regulatory test, which was initially applied in 2008 10 .

In December 2009, an application for a planning permit was submitted to the Moreland
City Council for the Stage 1 works at BTS. This application was unanimously rejected by
the Council in June 2010, mainly on the basis of non-conformance with local government
planning requirements. The Council received in excess of 200 objections from the local
community over the visual impact from the number of tall structures proposed for the site.
After the Council’s decision, CitiPower, SP AusNet and AEMO commenced work on
developing solutions to the forecast limitations that would also address the local
government planning requirements. The re-application of the regulatory test will assess
these new solutions in light of the latest available information on the costs of each
alternative solution.

Further details on this regulatory test re-application are available from the BTS project
website, www.brunswickts.com.au, or by contacting the CitiPower officer listed on page 5
of this report.

1.3.2   Statutory obligations under the National Electricity Rules

Clause 5.6 of the National Electricity Rules (the Rules) 11 sets out provisions governing
the planning and development of networks. These provisions require, amongst other
things, Transmission and Distribution Network Service Providers to:

•    prepare and publish annual planning reports;

•    consult with interested parties on the possible options, including but not limited to
     demand side options, generation options and market network service options to
     address the projected network limitations;

•    undertake analysis of proposed network investments using the regulatory test or the
     Regulatory Investment Test for Transmission (as appropriate).

These provisions apply to new network investment, where network is defined in the Rules
as:

        “The apparatus, equipment, plant and buildings used to convey, and control the
        conveyance of, electricity to customers (whether wholesale or retail) excluding any
        connection assets.”

In August 2009, the Victorian DBs lodged a submission to the AEMC’s review of the
national framework for electricity distribution network planning and expansion 12 . The
submission noted that at present, while some NSPs voluntarily apply the regulatory test

10
        On 26 May 2006 CitiPower issued a Consultation Report recommending an upgrade to the
        220/22 kV terminal station at Brunswick to relieve constraints at West Melbourne terminal station
        (WMTS 66 kV and WMTS 22 kV) that supply the northern and western inner central business district
        and surrounding areas. The upgrade will also help alleviate constraints at the heavily loaded
        Richmond Terminal Station. No submissions were received in response to the Consultation Report.
        Accordingly the preliminary recommendation has been adopted. The Final Report on the proposed
        Brunswick Terminal Station was published on NEMMCO’s website on 14 August 2008. Copies are
        available on request from the CitiPower contact officer listed on page 5 of this report.
11
        Version 39 of the Rules was in force at the time of preparing this report (October 2010).
12
        A copy of the submission is available from the AEMC’s web page at the following address:
        http://www.aemc.gov.au/Media/docs/United%20Energy%20Distribution-41484fe7-af5b-4c89-8471-
        f9aebf4a01f2-0.pdf




                                                  Page 16
                                                         2010 Joint DB Transmission Connection Planning Report




(and the associated consultation procedures) to transmission connection investment
decisions, this is not required under the framework set out in clause 5.6 of the Rules. The
DBs also noted that there is a sound public policy case for requiring the application of a
Regulatory Investment Test to assets that connect a distribution network to a
transmission network.

In its Final Report on the review of national framework for electricity distribution network
planning and expansion, the AEMC recommended that 13 :

     “Where the necessity for augmentation or a non-network alternative is identified by the
     process under the joint planning provisions, including for transmission [to] distribution network
     to network connections services, NSPs:
         •   would jointly determine plans that can be considered by relevant stakeholders;
         •   would carry out the Regulatory Investment Test for Transmission (RIT-T) for the
             options identified.”


The AEMC’s Final Report also noted that implementation of this particular
recommendation would require changes to the Rules, including possible changes to
clause 5.6.2 of the Rules, which were recently amended under the RIT-T Rule. 14

The AEMC provided its Final Report to the Ministerial Council on Energy (MCE) on
23 September 2009. The MCE published its policy response 15 to the AEMC’s Final
Report on 8 October 2010. The MCE advised that:

•    it will develop specific Rules to introduce the national framework in accordance with
     its response; and

•    Draft Rule changes (to be subject to the usual Rule change process including public
     consultation) are proposed to be submitted to the AEMC by December 2010.

Until the Rule changes proposed by the MCE come into effect – expected to be some
time in 2011 - under the current version of the Rules, the investment decision analysis
and consultation framework set out in clause 5.6 does not apply to transmission
connection assets. Notwithstanding this, the approach to investment decision analysis
and stakeholder consultation outlined in this Transmission Connection Planning Report is
consistent with the principles underpinning clause 5.6 of the Rules.

1.3.3    Reliability incentive scheme (S factor)

Under the price control that applies until 31 December 2010, each DB’s tariffs are
adjusted, through the application of a factor (the “S factor”) in the price control formulae,
to reflect any improvement or deterioration in the DB’s network performance. The
operation of the S factor scheme predominantly relates to the distribution network, and

13
         AEMC, Final Report: Review of National Framework for Electricity Distribution Network Planning and
         Expansion, September 2009, page 24.
14
         As noted on page 7 of the DBs’ submission to the AEMC, the RIT-T is not readily applicable by the
         DBs in their capacity as transmission connection planners because: under clause 5.6.5C, the
         obligation to apply the RIT-T applies to TNSPs and the DBs are not TNSPs; and clause 5.6.5C(a)(8)
         states clearly that the RIT-T does not apply to connection assets.
15
         http://www.ret.gov.au/Documents/mce/_documents/2010%20bulletins/Bulletin%20No.%20184%20-
         %20MCE%20Response%20to%20AEMC%20Review%20Oct%202010.pdf




                                                 Page 17
                                                   2010 Joint DB Transmission Connection Planning Report




therefore is not directly relevant to the reliability of the transmission system. However,
supply interruptions due to inadequate transmission connection planning are included
within the incentive scheme. This financial incentive reinforces the DBs’ responsibilities
with respect to transmission connection planning, which are set out in the Distribution
Licences and the Distribution Code.

From 1 January 2011, the DBs will be subject to the Electricity Distribution Network
Service Providers’ Service Target Performance Incentive Scheme administered by the
AER. Under clause 3.3(a)(6) of that scheme, the DBs are exposed to financial penalties
if load interruptions are caused by a failure of transmission connection assets where the
interruptions are due to inadequate planning of transmission connections and the DNSP
is responsible for transmission connection planning. This provision is consistent with the
incentive arrangements under the present S factor scheme.

1.3.4    Arrangements to ensure that the availability of connection assets is
         optimised

The DBs have limited direct control over the performance of connection assets under
their connection agreements with SPI PowerNet. However, the revenue cap applied to
SPI PowerNet (which is administered by the ACCC’s successor, the Australian Energy
Regulator or “AER”) contains a service target performance incentive scheme (STPIS)
developed in accordance with clause 6A.7.4 of the National Electricity Rules. The STPIS
aims to balance the incentive for SPI PowerNet to minimise expenditure with the need to
maintain and improve reliability for customers, by providing SPI PowerNet with a financial
incentive to maintain or improve service levels. This scheme was introduced from 1 July
2008.

1.4     Matters to be addressed by proponents of “non-network” alternatives

One of the purposes of this document is to provide information to proponents of non-
network solutions (such as embedded generation or demand management) to emerging
network constraints. As noted in further detail in Chapter 2 below, the DBs aim to
develop their networks and the associated transmission connection assets in a manner
that minimises total costs (or maximises net economic benefit). To this end, proponents
of non-network solutions to the emerging network constraints identified in this report are
encouraged to lodge expressions of interest with the relevant DB(s).

Proponents of non-network proposals should make initial contact with the relevant DB as
soon as possible, to ensure that sufficient time is available to the DB to fully assess
feasible network and non-network potential solutions, having regard to the lead times
associated with the evaluation, planning and implementation of various options.
Indicative timeframes for the network solutions are provided in the summary table of the
Executive Summary.

To assist in the assessment of non-network solutions, proponents are invited to lodge a
detailed submission to the relevant DB. This submission should be informed by earlier
discussions with the relevant DB, and should include all of the following details about the
proposal:

1. proponent name and contact details;
2. a detailed description of the proposal;
3. electrical layout schematics;




                                             Page 18
                                                        2010 Joint DB Transmission Connection Planning Report




4. a firm nominated site;
5. the capacity to be provided;
6. fault level contribution, load flows, and stability studies (if applicable);
7. a commissioning date with contingency specified;
8. availability and reliability performance benchmarks;
9. network interface requirements (as agreed with the relevant DBs);
10. the economic life of the proposal;
11. banker / financier commitment;
12. proposed operational and contractual arrangements that the proponent would be
    prepared to enter into with the relevant DBs;
13. any special conditions to be included in a contract with the responsible DBs; and
14. evidence of a planning application having been lodged, where appropriate.

All proposals must satisfy the requirements of any applicable Codes and Regulations.

In addition, as a general rule of thumb, any network reinforcement costs required to
accommodate the non-network solution will typically be borne by the proponent(s) of the
non-network project. Some non-network alternatives such as embedded generation may
raise issues relating to fault level control. In relation to this particular issue, it is noted that
connection of additional embedded generators will result in an increase in fault levels.
Therefore fault level mitigation measures may be required because of the installation of
embedded generation, in which case it would be equitable and efficient for the
proponents of such projects to bear the costs of fault level mitigation works.

It is noted that regulatory arrangements governing the terms and conditions for
connection to the distribution network are subject to change. In particular:

•    As the transition to a national framework for the regulation of distribution networks
     continues, the status of Guideline 15 (Connection of Embedded Generation) 16 issued
     by the Victorian Essential Services Commission is uncertain. It is expected that over
     the next year or so, as the proposed national framework for distribution network
     planning and expansion is implemented, the on-going status of State-based
     instruments such as Guideline 15 will be clarified.

•    Draft changes to the National Electricity Rules relating to the distribution network
     connections framework, along with connection arrangements for micro embedded
     generation (including solar photo-voltaics) were included in the Second Exposure
     Draft of the National Energy Customer Framework (NECF) for consultation on
     27 November 2009 17 . The Ministerial Council on Energy published its response to
     submissions on the NECF Second Exposure Draft on 10 September 2010. MCE
     Bulletin number 183 stated that the NECF legislative package will be introduced to the


16
        Guideline 15 (Connection of Embedded Generation) can be downloaded from the ESC’s web site at
        the following address:
        http://www.esc.vic.gov.au/NR/exeres/ED979458-AA36-43BE-BA25-DFA5B40E416C.htm
17
        See MCE Bulletin 170 at: http://www.ret.gov.au/Documents/mce/quicklinks/bulletins.html




                                                Page 19
                                                         2010 Joint DB Transmission Connection Planning Report




      South Australian Parliament in the Spring session 2010. Further details are available
      at the MCE’s web page at: http://www.mce.gov.au/.
1.5     Implementing Transmission Connection Projects

In the absence of any commitment by interested parties to offer “non-network” solutions
(such as embedded generation or demand side management), the process to implement
the preferred network solution will commence. A brief description of the implementation
process for network solutions and the issues involved is presented below.

1.5.1    Joint planning in Victoria

Under the present regulatory arrangements, the Victorian DBs and AEMO coordinate
their respective plans to ensure efficient development of the shared transmission network,
transmission connection assets and the distribution networks.

The proposed national framework for electricity distribution network planning and
expansion (referred to in section 1.3.2 above) is expected to contain provisions relating to
joint planning between Distribution and Transmission Network Service Providers which
are aimed at facilitating and streamlining joint planning, for the purpose of:

•     identifying the most economic solution to any common problems on the networks and
      the related connection assets; and

•     providing for the timely delivery of those solutions.

In addition, AEMO and the Victorian DBs are presently working together to develop a
memorandum of understanding to establish an agreed framework for cooperation and
liaison for the purposes of joint planning.

1.5.2    Land Acquisition

Network solutions may require land acquisition. The process of land acquisition for new
terminal stations may be complex especially in metropolitan areas. Land acquisition
issues and processes are beyond the scope of this document.

A limited number of vacant sites, currently owned by SPI PowerNet, have been reserved
for possible future terminal station development in Victoria. DBs would need to seek
SPI PowerNet’s consent to use any reserved land for transmission connection
development. 18

The granting of a town planning permit on lands reserved for future terminal station
development is by no means certain. In some municipalities, town planning approval may
also be required for network augmentation on existing developed sites.

1.5.3    Connection Application to AEMO

In accordance with the requirements of Chapter 5 of the National Electricity Rules, a
connection application to AEMO for new transmission connection points is required. As
noted in section 1.2, the 220 kV assets that form part of the Victorian shared transmission
network would fall under the planning jurisdiction of AEMO. Hence, issues associated

18
         Electricity Industry Guideline No. 18 (Augmentation and Land Access Guidelines) issued by the ESC
         on 1 April 2005 may govern access to such sites, in some circumstances.



                                                 Page 20
                                                   2010 Joint DB Transmission Connection Planning Report




with 220 kV switching arrangements and connection to the shared transmission system
would need to be clarified at the connection application stage so that the requirements of
the DBs and AEMO can both be met.

For augmentations to existing connection points, a connection application to AEMO may
still be required so that the effect on the shared transmission network, if any, can be
taken into consideration. In some cases, AEMO may undertake a public consultation
process in relation to the proposed development. In addition, AEMO’s requirements
regarding any augmentation of shared transmission network assets must be finalised
through a joint planning process involving AEMO and the relevant DBs. These activities
can increase the lead time for delivery of augmentations by some months. As noted in
section 1.5.1 above:

    •   the proposed national framework for electricity distribution network planning and
        expansion is expected to contain provisions aimed at facilitating and streamlining
        joint planning; and

    •   AEMO and the Victorian DBs are presently working together to develop a
        memorandum of understanding to establish an agreed framework for cooperation
        and liaison for the purposes of joint planning.

1.5.4   Connection Application to SPI PowerNet

It is most likely that establishment of new transmission connections, or augmentation of
existing transmission connections will require interface to transmission assets owned by
SPI PowerNet. In accordance with the negotiating framework issued by SPI PowerNet,
an initial “Connection Inquiry” outlining the broad scope of service sought should be
submitted to SPI PowerNet, followed by a “Connection Application” when the scope of the
service has been accurately defined in consultation with AEMO and the relevant DB(s).

1.5.5   Contestable procurement of transmission connection works

In relation to the question of the DBs’ obligations to competitively procure transmission
connection services, page 3 of the ESC’s June 2002 Information Paper- Cost Recovery
Issues for the Proposed Cranbourne Terminal Station, states:

        “Distributors have no specific regulatory obligation to conduct competitive tendering of
        transmission connection asset augmentations. However, in meeting their Electricity
        Distribution Code obligation to minimise costs to customers, distributors would normally
        competitively tender such works.”


1.5.6   Town Planning Permit

For greenfield sites, DBs may need to engage the services of experienced town planning
consultants, because very extensive planning requirements are generally laid down by
local planning authorities. In most cases, the town planning permit application would
need to be accompanied by extensive support documents such as:
•   flora and fauna study;
•   archaeological and cultural assessment;
•   noise study;




                                            Page 21
                                                        2010 Joint DB Transmission Connection Planning Report




•    electromagnetic field (EMF) assessment;
•    traffic analysis;
•    layouts and elevation plans; and
•    landscaping and fencing.

The choice of appropriate town planning consultants is very important, as they may need
to provide expert witness statements to the Victorian Civil and Administrative Tribunal
(VCAT) if objections to the transmission connection application are received. Due to the
possibility of simultaneous shared network development by AEMO on the same site, it
may become necessary to invite AEMO to participate in the town planning process at the
same time so that both the council and the public are made aware of the entire proposed
development on the site.

For augmentation to existing transmission connection assets, the requirement for a town
planning permit varies from council to council, and depends on the extent of the proposed
work. SPI PowerNet is likely to be the initiator of the planning permit application for
augmentation work at an existing terminal station.

1.5.7    Public Consultation Strategy

A key aspect of the public consultation strategy is the positive engagement of various
stakeholders in the project from the initial stages of the development. The strategy may
include:

•    distribution of leaflets that provide information on the proposal in clear, concise, non-
     technical language to every nearby resident;

•    presentations to the councillors of the local municipality and the local members of
     parliament; and

•    public consultation such as display stands in local shopping centres to highlight the
     need for such a project and the resultant benefits to the community, and invitation of
     public comments on the proposal.

Feedback from stakeholders is then considered in the design of the transmission
connection work to ensure the resultant project is acceptable to the local community.

1.5.8    Project Implementation

As noted in section 1.3.1, the DBs are required by the Distribution Code to augment the
transmission connections in a way which minimises costs to customers taking account of
distribution losses. This can be achieved by a variety of means, including competitive
tendering and cost benchmarking.

Transmission connection augmentation works will be arranged by the relevant DBs in
accordance with the requirements of any applicable guidelines in force 19 .


19
         As already noted, page 3 of the ESC’s June 2002 Information Paper- Cost Recovery Issues for the
         Proposed Cranbourne Terminal Station, states:




                                                Page 22
                                                      2010 Joint DB Transmission Connection Planning Report




1.5.9   Project lead times

The lead-time required for the implementation of connection asset augmentation projects
depends on the number of interdependent activities involved in the project, and varies
from between 3 to 5 years.

The critical path activities in the delivery of such projects include the following:

   •    Finalisation of any requirements for shared network augmentation due to planned
        connection asset augmentation works. These requirements are assessed through
        the existing joint planning process, which involves AEMO and the DBs in Victoria.

   •    Procurement of a planning permit in relation to the proposed works. In order to
        obtain planning consent for proposed works, the statutory planning requirements
        of the local council(s) must be met, and community expectations must be
        addressed. For connection asset augmentations involving either major
        augmentations on an established site or the development of new terminal
        station(s) on new site(s), a period of at least 24 months is required for land
        planning and associated community issues to be resolved. The timely completion
        of this task requires effective coordination and cooperation between AEMO and
        the DBs through the joint planning process in Victoria.

   •    After completing the above two tasks successfully, the next important tasks are:

           o   Finalisation of the scope of works;

           o   Preparation of cost estimates (including invitation to tender if the project is
               contestable); and

           o   Finalisation and execution of all contracts and agreements between
               distribution and transmission network service providers after obtaining all
               the necessary internal business approvals.

Once the project contracts are signed, then the next important task is the delivery of the
project itself, including installation and commissioning of the assets into service. Recent
experience indicates that the lead-time required for the delivery of a connection asset
augmentation involving power transformers has increased substantially. In particular, the
timeframe for transformer delivery and installation has increased from 12 to up to 24
months over the last few years as a consequence of high demand for these items
worldwide, with only a few local suppliers available in Australia. In some recent cases,
issues identified during testing of completed units have resulted in further delays. In light
of these considerations, for planning purposes it is assumed that approximately
24 months would now be required from the time that a commercial contract is signed
between the parties to complete the project works.




               “Distributors have no specific regulatory obligation to conduct competitive tendering of
               transmission connection asset augmentations. However, in meeting their Electricity
               Distribution Code obligation to minimise costs to customers, distributors would normally
               competitively tender such works.”



                                              Page 23
                                                            2010 Joint DB Transmission Connection Planning Report




1.6    Overview of Transmission Connection Planning Process

The flow chart below provides a summary of the transmission connection planning and
augmentation process under the regulatory framework which presently applies to the
Victorian DBs. As noted in section 1.3.2 above, the MCE is presently developing new
National Electricity Rules provisions to introduce a national framework for distribution
planning. The new Rules (which are expected to come into effect some time in 2011) will
result in changes to the process shown below.


      PROCESS FLOW CHART: TRANSMISSION CONNECTION PLANNING
 Joint Transmission Connection Planning Report                      Process after publication of report
                                                                   (undertaken individually by each DB
                                                                           for each constraint)


         Plant ratings         Demand f orecasts                Proponents of non-network solutions
                                                                respond to Transmission Connection
                                                                Planning Report


                  Identify constraint
      • Nature of constraint and limiting plant                 Detailed economic and technical
      • Summer and / or Winter load at risk                     evaluation of f easible options:
      • Required timing of remedial action                      • Environmental and land planning issues
      • Nature of load and customers at risk                    • Further consultation with electricity
                                                                  market / industry participants
                                                                • Local community consultation
      Identify potential options through joint                  • Detailed economic assessment
      planning between DBs and AEMO
      • Network augmentation (optimise
        investment across distribution network,
        transmission shared network and                          Selection of pref erred option by DB
        transmission connection)
      • Demand management
      • Local generation                                        Review of compliance with Licence and
      • Risk mitigation / contingency programs                  Distribution Code requirements, by ESC.
      • Other
                                                                (Provides all stakeholders with assurance
                                                                that a prudent and ef f icient investment
                                                                decision is being made, on the basis of the
      Consider feasibility of options
                                                                best available inf ormation at the time, and
      • Optimise investment across distribution
                                                                having regard to the relative costs and
        and transmission networks (including
                                                                benef its of alternatives)
        connection)
      • Locational requirements
      • Operating / perf ormance requirements
      • Means of implementation
      • Indicative cost (Is it reasonably likely to             DB Board approves implementation of
         be potentially economic?)                              pref erred option
      • Lead time required f or development

                                                                Implementation of pref erred option.
       Preferred network augmentation                           (DB enters into contract with transmission
       • Describe the pref erred network-                       connection service provider, eg SPI
          based solution                                        PowerNet )
       • Budget cost
       • Lead time
       • Not necessarily the pref erred option                  DB passes transmission connection
         (depends on timing of emergence of                     charges through to end users via network
          other options)                                        charges




                                                      Page 24
                                                       2010 Joint DB Transmission Connection Planning Report




2 PLANNING STANDARDS

2.1    Overall objective of transmission connection planning

The planning standards and criteria applied in network development are a significant
determinant of network-related costs. Costs associated with transmission connection
facilities can be considered to be comprised of two parts:

•     the direct cost of the service (as reflected in network charges and the costs of
      losses); and

•     indirect costs borne by customers as a consequence of supply interruptions caused
      by network faults.

In establishing and applying their planning standards and investment criteria, the DBs aim
to develop transmission connection facilities in an efficient manner that minimises the
total (direct plus indirect) life-cycle cost of network service borne by customers. This
basic concept is illustrated in Figure 2 below.



                                                              Total cost

                      Cost                                            Cost of providing
                                                                         reliability




                      Minimum
                      total cost


                                                                      Cost to customer of
                                                                      supply interruptions



                                         Optimum level of
                                         supply reliability
                                                               Supply reliability



                     Figure 2: Balancing the direct cost of service
                          and the indirect cost of interruption


In addition, the DBs’ transmission connection investment decisions aim to maximise the
net present value to customers, having regard to the costs and benefits of non-network
alternatives to augmentation. Such alternatives include, but are not necessarily limited to,
demand-side management and embedded generation.




                                          Page 25
                                                          2010 Joint DB Transmission Connection Planning Report




2.2   Overall approach to transmission planning and investment evaluation

In some Australian jurisdictions, deterministic planning standards (for instance, “N-1”) are
applied in transmission system development. In Victoria however, AEMO applies a
probabilistic approach 20 to planning the shared transmission network 21 .

Under the probabilistic approach, the deterministic N-1 criterion is relaxed, and simulation
studies are undertaken to assess the amount of energy that would not be supplied if an
element of the network is out of service. The application of this approach can lead to the
deferral of transmission capital works that might otherwise proceed if a deterministic
standard were strictly applied. This is because:

•      in a network planned in accordance with the probabilistic approach, there may be
       conditions under which all the load cannot be supplied with a network element out
       of service (hence the N-1 criterion is not met); however

 •     under these conditions, the value of the energy that is expected to be not supplied
       is not high enough to justify additional investment, taking into account the
       probability of a forced outage of a particular element of the transmission network.

The transmission connection assets for which the DBs have planning responsibility form
part of the Victorian electricity transmission system 22 . Given that AEMO applies a
probabilistic network planning approach to the development of the shared transmission
network, the Victorian DBs consider it appropriate to adopt a similar approach to
transmission connection planning and investment decision analysis 23 .

2.3   Valuing supply reliability from the customers’ perspective

In order to determine the economically optimal level and configuration of connection
capacity (and hence the supply reliability that will be delivered to customers), it is
necessary to place a value on supply reliability from the customer’s perspective.

Estimating the marginal value to customers of reliability is inherently difficult, and
ultimately requires the application of some judgement. Nonetheless, there is information
available (principally, surveys designed to estimate the costs faced by consumers as a
result of electricity supply interruptions) that provides a guide as to the likely value.

The most recent information published regarding the estimation of the value of unsupplied
energy (the “value of customer reliability” or “VCR”) appeared in the 2010 Victorian


20
       A copy of the Victorian transmission network planning criteria can be obtained from AEMO’s web
       site at: http://www.aemo.com.au/planning/0400-0006.pdf
21
       The “shared transmission network” is the Victorian transmission system, excluding the transmission
       facilities that connect the distribution networks and the generators to the high voltage network. The
       distribution businesses and the generators, respectively, are responsible for planning and
       development of the relevant transmission connection facilities. These arrangements are set out in
       the transmission and distribution licences issued by the ESC.
22
       The transmission and distribution licences issued in Victoria define the term “electricity transmission
       system” as “a transmission system in Victoria (generally at nominal voltage levels of 66 kV or above)
       which the holder of a transmission licence may use to transmit electricity.”
23
       In some cases (for instance, the upgrading of circuit-breakers due to fault levels) the DBs may
       continue to apply a deterministic standard. The application of such standards will be justified on the
       basis of their economic costs and benefits.




                                                 Page 26
                                                      2010 Joint DB Transmission Connection Planning Report




Annual Planning Report, which was published in July of this year 24 . Pages 154 and 155
of that report stated:

       “The VCR is a measure of the cost of unserved energy that aims to capture the value of
       energy to users. In simple terms it represents the cost to consumers of being without
       electricity, and is an important input for regulatory test assessments of planned electricity
       transmission augmentations in Victoria…

       A survey to determine the VCR for electricity in Victoria was last conducted in 2007.
       AEMO applies an index to these survey results between survey periods. This ensures that
       the VCR value is updated to reflect current income and economic growth for the various
       identified sectors of the economy (Residential, Agricultural, Commercial, and Industrial),
       enabling the production of a headline figure reflecting a weighted average.

       The index uses data from the Australian National Accounts: State Accounts data series,
       updated by the Australian Bureau of Statistics (ABS). The data for the 2008/09 year was
       released on 22 December 2009. The new data has been used to calculate the 2010 VCR
       numbers for Victoria. Table 8-1 summarises the 2010 VCR results




                                                                                                        ”

The current version of the Regulatory Test (Version 3), along with the accompanying
Regulatory Test Application Guidelines provide guidance on how the value of customer
reliability is to be taken into account in valuing the benefits of network augmentations.
Page 7 of the Regulatory Test Application Guidelines states:

       “A particular transmission option may, compared to the base case state of the world, lead
       to… a reduction in load shedding (valued at VCR or a comparable estimate of the value
       consumers place on electricity).”

The approach to valuing supply reliability applied to date by both VENCorp (AEMO’s
predecessor) and the DBs in their respective transmission planning roles is consistent
with the approach described on page 7 of the AER’s Regulatory Test Application
Guidelines, and set out in clause 4(c) of Version 3 of the Regulatory Test.

It is noted, however, that from 1 August 2010, the Regulatory Test ceased to apply to
transmission (although it still currently applies to distribution investment). A new
Regulatory Investment Test for Transmission (RIT-T) now applies to transmission
investment, and it is expected that the Rule changes that will implement the proposed
national framework for electricity distribution network planning and expansion 25 will
extend the application of the RIT-T to transmission connection assets that are planned by
DBs.


24
       The report is available from AEMO’s website at: http://www.aemo.com.au/planning/apr.html
25
       See section 1.3.2 above.




                                              Page 27
                                                            2010 Joint DB Transmission Connection Planning Report




Clause 5(c) of the current RIT-T 26 states:

       “the market benefit must include … changes in involuntary load shedding, with the market
       benefit to be considered using a reasonable forecast of the value of electricity to
       consumers”.

The accompanying RIT-T Application Guidelines published by the AER do not prescribe a
particular value of electricity to consumers. However, page 63 of the Guidelines states:

       “Examples of reasonable estimates of the value of electricity to consumers include:
       •   The market price cap (or Value of Lost Load, VoLL) – at 1 June 2010 VoLL is
           $10,000/MWh but will increase to $12,500/MWh from 1 July 2010.
       •   The Value of Customer Reliability (VCR) used by AEMO for network planning in
           Victoria. The VCR used by AEMO in the 2009 Victorian Annual Planning Report
           (VAPR) is $55,000/MWh.”

In considering the appropriate VCR to apply in network investment evaluation, the
Victorian DBs favour the application of the VCR estimate as opposed to the VoLL
wholesale market price cap. This is because the VCR attempts to reflect the marginal
value of supply reliability to customers, whereas the VoLL applies in the wholesale
market, and its rationale is more closely linked to management of risk in that market.
In applying the VCR, it should be recognised that VCR is a composite (or weighted
average) measure of customer interruption costs:
• for a wide range of different customers; and
• across a wide range of interruption durations (up to 24 hours).

Customer surveys of interruption costs clearly indicate that the estimated value of
unsupplied energy per MWh declines as outage duration increases. This is because
there is a significant component of the cost to consumers that does not vary with outage
duration. This is illustrated in Figure 3 below.




                   Interruption                         VCR
                     Cost ($)
                                                        ($/MWh)




                              Interruption duration             Interruption duration


                        Figure 3: Impact of interruption duration on
                            Value of Customer Reliability (VCR)




26
       The RIT-T (version 1) was published by the AER in June 2010 and came into effect on 1 August
       2010. Further details are available at: http://www.aer.gov.au/content/index.phtml/itemId/730920




                                                      Page 28
                                                     2010 Joint DB Transmission Connection Planning Report




This illustrates the limitations associated with the overall concept of VCR. VCR is a
simple single ratio derived from an estimate of interruption costs and a notional quantity
of energy not consumed as a result of the interruption. The single VCR number attempts
to represent a very complex, multi-dimensional set of variables.

A further limitation of the concept of the “composite” or average VCR is the variability of
the marginal value of unsupplied energy across different customer groups. This is
illustrated in the sector VCR values that underpin the Victorian composite VCR of
$60,178 per MWh adopted in the 2010 Victorian Annual Planning Report. For
convenience, these sector values are shown in Table 1 below.



                                                               VCR ($/MWh)
                          Sector
                                                   (Source: AEMO Victorian APR for 2010)

           Residential                                            $16,326

           Commercial                                            $114,679

           Agricultural                                         $134,149

           Industrial                                             $45,945

           Composite- all sectors                                 $60,178

                   Table 1: 2010 Victorian VCR estimates by sector

The wide range of sector VCR values has potentially significant implications for
transmission connection investment decisions, especially where the composition of the
load supplied from a potentially constrained terminal station is dominated by a particular
sector.

For instance, the load within the Melbourne CBD is comprised predominantly of
commercial sector load, which has an estimated VCR of around $114,000 per MWh.
That VCR is nearly twice the composite VCR for Victoria as a whole.

These observations suggest there is a reasonable case for the application of sector-
specific VCR values in transmission connection investment analysis, where a constraint
affects a readily identifiable group of consumers 27 . In addition, these observations
indicate that:

•    There may be situations where it would be appropriate for the DB(s) involved in an
     augmentation proposal to collect further specific data in relation to the value of
     reliability to the customers affected by the proposal.

•    Where VCR is applied in the economic evaluations of constraint alleviation options,
     careful judgment is required in interpreting the decision signals provided by those
     evaluations, and in reaching a final investment decision.




27
       It is noted that page 7 of VENCorp’s November 2009 Victorian Electricity Transmission Network
       Planning Criteria also foreshadows the application of a sector specific VCR. This document is
       available from AEMO’s web page at: http://www.aemo.com.au/planning/0400-0006.pdf




                                             Page 29
                                                         2010 Joint DB Transmission Connection Planning Report




This report provides details of the VCR values used for each terminal station, based on
the sector VCR estimates provided by AEMO and set out in Table 1 above.

2.4     Application of the probabilistic approach to transmission connection
        planning

The probabilistic planning approach involves estimating the probability of a plant outage
occurring within the peak loading season, and weighting the costs of such an occurrence
by its probability to assess:

•     the expected cost that will be incurred if no action is taken to address an emerging
      constraint, 28 and therefore

•     whether it is economic to augment terminal station capacity to reduce expected
      supply interruptions.

The quantity and value of energy at risk is a critical parameter in assessing a prospective
network investment or other action in response to an emerging constraint. Probabilistic
network planning aims to ensure that an economic balance is struck between:

•     the cost of providing additional network capacity to remove constraints; and

•     the cost of having some exposure to loading levels beyond the network’s capability.

In other words, recognising that very extreme loading conditions may occur for only a few
hours in each year, it may be uneconomic to provide additional capacity to cover the
possibility that an outage of an item of network plant may occur under conditions of
extreme loading. The probabilistic approach requires expenditure to be justified with
reference to the expected benefits of lower unserved energy.

This approach provides a sound actuarial estimate of the expected net present value to
consumers of terminal station augmentation. However, implicit in its use is acceptance of
the risk that there may be circumstances when the available terminal station capacity will
be insufficient to meet actual demand. The extent to which investment should be
committed to mitigate that risk is ultimately a matter of judgment, having regard to:

•       the results of studies of possible outcomes, and the inherent uncertainty of those
        outcomes;

•       the potential costs and other impacts that may be associated with very low
        probability events, such as single or coincident transformer outages at times of
        peak demand, and catastrophic plant failure leading to extended periods of plant
        non-availability; and

•       the availability and technical feasibility of cost-effective contingency plans and
        other arrangements for management and mitigation of risk.

2.5     The connection augmentation criterion

In accordance with the requirements of clause 3.1 of their Distribution Licences, the DBs
apply the following investment criterion:
28
         The energy that would not be supplied in the event of an interruption is valued in accordance with
         the approach outlined in Section 2.3 above.




                                                 Page 30
                                           2010 Joint DB Transmission Connection Planning Report




A project aimed at alleviating a transmission connection capacity constraint should
proceed if it maximises the net present value to customers, having regard to:
•   the relative costs and benefits, including changes in supply reliability, of
    network augmentation and non-network alternatives to augmentation;
•   the potentially high costs faced by customers if low-probability, high impact
    events occur and result in outages of key transmission connection assets at
    times of peak demand;
•   the expectations of customers and other stakeholders regarding the
    maintenance of reliable electricity supply;
•   the objective of minimising total life-cycle costs;
•   the strong scale economies that exist within the electricity transmission and
    distribution sectors; and
•   the need to comply with environmental and land-use planning standards,
    health and safety standards, and applicable technical standards.




                                    Page 31
                                               2010 Joint DB Transmission Connection Planning Report




3 HISTORIC AND FORECAST DEMAND

In its capacity as the planner of the Victorian shared transmission network, AEMO
produces consolidated terminal station demand forecasts each year, based on data
provided by the DBs. The forecasts that form the basis of this report are consistent with
those published by AEMO in October 2010 in its report titled Terminal Station Demand
Forecasts 2010/11 - 2019/20. A copy of the report is available from AEMO’s web site at
the following address:
http://www.aemo.com.au/planning/0400-0014.pdf




                                         Page 32
                                                          2010 Joint DB Transmission Connection Planning Report




4      RISK ASSESSMENT AND
       OPTIONS FOR ALLEVIATION OF CONSTRAINTS

4.1    Preamble

This Section presents an overview of the magnitude, probability and impact of loss of load
at each transmission connection, in accordance with the requirements of clause 3.4.2(b)
of the Distribution Code.

The assessment presented is not a detailed planning analysis, but a high-level
description of the expected balance between capacity and demand over the forecast
period. Data presented in this high-level analysis may indicate an emerging major
constraint. Therefore, this high-level assessment provides a means of identifying those
terminal stations where more detailed analyses of risks and options for remedial action
are required.

It is emphasised that this high-level analysis focuses on risks to supply reliability that
relate to the capacity and reliability of transformers only. There are typically risks to
supply reliability associated with the performance and capacity of smaller plant items.
However, these smaller items involve relatively low capital expenditure, the deferral of
which is unlikely to entail a sufficiently high avoided cost to justify the employment of non-
network alternatives.

In addition, capital expenditure is required from time to time to address fault level issues.
This expenditure is driven chiefly by mandatory health and safety standards, and does
not relate to terminal station capacity, per se. Fault level issues are therefore not within
the scope of this report, however, the analysis of feasible and preferred options for
increasing capacity will, where appropriate have due regard to issues relating to fault
level control 29 .

The following key data are presented in this section for each Terminal Station:

•     Energy at risk: For a given demand forecast, this is the amount of energy that
      would not be supplied from a terminal station if a major outage 30 of a transformer
      occurs at that station in that particular year, the outage has a mean duration of 2.6
      months (as discussed in section 4.4 below), and no other mitigation action is taken.
      This statistic provides an indication of the magnitude of loss of load that would arise
      in the unlikely event of a major outage of a transformer.

•     Expected unserved energy: For a given demand forecast, this is the energy at risk
      weighted by the probability of a major outage of a transformer. This statistic provides
      an indication of the amount of energy, on average, that will not be supplied in a year,
      taking into account the very low probability that one transformer at the station will not
      be available for 2.6 months because of a major outage.

Risk assessments for each individual terminal station provide estimates of energy at risk
and expected unserved energy based on the 50th percentile and 10th percentile demand

29
         Some non-network alternatives such as embedded generation may raise issues relating to fault level
         control. A further discussion of this issue is set out in Section 1.4 of this report.
30
         The term “major outage” refers to an outage that has a mean duration of 2.6 months, typically due to
         a significant failure within the transformer. The actual duration of an individual major outage may
         vary from under 1 month up to 9 months. Further details are provided in section 4.4 below.




                                                  Page 33
                                                       2010 Joint DB Transmission Connection Planning Report




forecasts set out in Section 3. Consideration of energy at risk and expected unserved
energy at these two demand forecast levels provides:

•     an indication of the sensitivity of these two parameters to temperature over the
      Summer peak period; and

•     an indication of the level of exposure to supply interruption costs at more extreme
      temperature and demand conditions (namely, 10th percentile levels).

As already noted, this information provides an aid to identifying the likely timing of
economically-justified augmentations or other actions. However, the precise timing of
augmentation or any other non-network solutions aimed at alleviating emerging
constraints will be a matter for more detailed analysis that takes into account all relevant
factors, including the uncertainty of temperature outcomes and the impact of temperature
on demand at the particular terminal station.

In interpreting the information set out in this report, it is important to recognise that the
50th percentile demand forecast relates to a maximum average temperature that will be
exceeded, on average, once every two years. By definition therefore, actual demand in
any given year has a 50% probability of being higher than the 50th percentile demand
forecast. 31

4.2    Interpreting “energy at risk”

As noted above, “energy at risk” is an estimate of the amount of energy that would not be
supplied if one transformer was out of service due to a major failure during the critical
loading season(s), for a given demand forecast.

The capability of a terminal station with one transformer out of service is referred to as its
“N minus 1” rating. The capability of the station with all transformers in service is referred
to as its “N” rating. The relationship between the N and N-1 ratings of a station and the
energy at risk is depicted is the diagram below.




31
        Conversely, there is also a 50% chance that actual demand will be lower than the forecast in any
        one year.




                                               Page 34
                                                      2010 Joint DB Transmission Connection Planning Report




             Relationship between N rating, N-1 rating and energy at risk

           Demand

             N rating
                                                        Energy at risk is
                                                        represented by
                                                        the shaded area

           N-1 rating

                                                                            Full “N” capacity expected to
                                                                            be available, on average, for
                                    Demand forecast
                                                                                  99.7% of the time




                    Today                                                         In 10 years
                                                                    Time

4.3     Assessing the costs of transformer outages

As noted in Section 4.1, for a given demand forecast:

•     “energy at risk” denotes the amount of energy that would not be supplied from a
      terminal station if a major outage of a single transformer occurs at that station in that
      particular year, and no other mitigation action is taken; and

•     “expected unserved energy” is the energy at risk weighted by the probability of a
      major outage of a single transformer.

In estimating the expected cost of connection plant outages, this report considers the first
order contingency condition (“N minus 1”) only. It is recognised that in the case of
terminal stations that consist of two transformers, there is a significant amount of energy
at risk if both transformers are out of service at the same time, due to a major outage.
Some interested parties have therefore suggested that the analyses presented in this
report should be expanded to include consideration of the costs of major outages under
N-1 (first order contingency) and N-2 (second order contingency) conditions.

The DBs have carefully considered these suggestions, and concluded that it is not
necessary for the analyses presented in this report to be extended to include
consideration of second order contingency conditions. The principal reason for this is that
the value of expected unserved energy associated with second order contingencies
would be unlikely to be sufficiently high to justify the advancement of any major
augmentation, compared to the augmentation timing that is economically justified by an
analysis that is limited to considering first order contingencies. The Appendix contains a
detailed example which illustrates this point.

However, in undertaking a detailed economic evaluation of network investment, the DBs
agree that the quantity and value of energy at risk associated with higher order
contingencies should be considered. These higher order contingencies are unlikely to
affect the likely timing of the required investment, which is the primary focus of this report.




                                             Page 35
                                                  2010 Joint DB Transmission Connection Planning Report




4.4    Base reliability statistics for transmission plant

Estimates of the expected unserved energy at each terminal station must be based on
the expected reliability performance of the relevant transformers. The basic reliability
data for terminal station transformers has been established and agreed with the asset
owner, SPI PowerNet. The base data focuses on:
•     the availability of the connection point main transformers; and
•     the probability of a major problem forcing these plant items out of service for an
      average period of 2.6 months. This does not include minor faults that would result in
      a transformer being unavailable for a short period of time (ranging from a few hours
      up to no more than two days).

The basic reliability data adopted for the purpose of producing this report has been
refined as summarised in the following table. It is derived from the statistical data
collected in a survey carried out in 1995 for the Australian CIGRE Panel 12 on
Transformer Reliability, with support from SPI PowerNet, the owner of the connection
assets.



    Major plant item: Terminal station transformer                       Interpretation

 Major outage rate for        1.0%                        A major outage is expected to occur
 transformer                                              once per 100 transformer-years.
                                                          Therefore, in a population of 100
                                                          terminal station transformers, you
                                                          would expect one major failure of
                                                          any one transformer per year.
 Weighted average of          2.6 months                  On average, 2.6 months is required
 major outage duration                                    to repair the transformer and return it
                                                          to service, during which time, the
                                                          transformer is not available for
                                                          service.
 Expected transformer         0.01 x 2.6/12 = 0.217%      On average, each transformer would
 unavailability due to a      approximately               be expected to be unavailable due to
 major outage per                                         major outages for 0.217% of the
 transformer-year                                         time, or 19 hours in a year.


In October 2010, SPI PowerNet confirmed that the transformer outage data adopted in
this report are reasonable, for the purpose of preparing the transmission connection asset
risk assessments. SPI PowerNet also advised that the use of average transformer
outage data may not accurately represent the specific outage risks associated with
individual transformers at particular locations over particular time periods.

Further details regarding the estimation of the weighted average duration of “major
outages” are provided in the Appendix. The Appendix also sets out an example
demonstrating the calculation of the “Expected Transformer Unavailability” for a terminal
station with two transformers, using the basic reliability data contained in this section.




                                           Page 36
                                                       2010 Joint DB Transmission Connection Planning Report




4.5     Availability of spare transformers

In July 2002, SPI PowerNet confirmed that it had procured two spare transformers (one
for the metropolitan network and one for the rural network) to mitigate the risk of a
transformer failure that results in a prolonged outage, or to allow for transformer
maintenance or refurbishment.

In a letter to the DBs in July 2002, SPI PowerNet stated:

         “SPI PowerNet took the initiative to purchase these spares in part to ensure consistency
         with good Electricity Industry practice. This assessment was made on the basis of
         considering similar integrated transmission utilities, and their approach to transformer
         spares holding to cover both periodic maintenance activities and forced transformer
         outages. As a consequence these spares have been purchased to allow the provision of
         connection services according to our obligations. This service is achieved through an
         integrated asset management approach that includes not only providing an alternative for
         transformers which are unavailable for service, but also to support essential maintenance
         activities including refurbishment programs.
         SPI PowerNet confirms that it will aim to install the spare transformers to replace a unit
         exposed to long term outage within one calendar month. It must be stressed that while it
         is considered that such a time frame can generally be achieved it is not appropriate to
         provide a guaranteed time for the temporary replacement. The individual and unique
         circumstances of each transformer failure have the potential to result in either a greater or
         lesser time requirement. More importantly a timeframe of this order could only be
         achieved if the spare transformer is not being used at another location at the time of the
         failure."


SPI PowerNet has advised that, subject to the availability of the relevant spare
transformer:

•     The metropolitan spare transformer is suitable for use at the following stations:
      Altona, Brooklyn, Cranbourne, East Rowville, Fishermans Bend, Geelong,
      Heatherton, Keilor, Malvern, Richmond, Ringwood, South Morang, Springvale, Tyabb,
      Thomastown, Templestowe, and West Melbourne.

•     The rural spare transformer is suitable for use at the following stations: Ballarat,
      Bendigo, Geelong, Glenrowan, Horsham, Kerang, Mount Beauty, Morwell, Red Cliffs,
      Shepparton, and Terang.

At the time of writing this report, the DBs have confirmed that the undertakings described
above remain in place. Given the uncertainty regarding the availability of spare
transformers at any particular time, the DBs have decided that for the purpose of this
report, the potential availability of the spare transformers will not be directly taken into
account in the (probabilistic) estimation of expected unserved energy. Instead, the
detailed risk assessment for each terminal station will:

•     estimate the expected unserved energy for a major outage of a single transformer
      (namely an outage with an average outage of 2.6 months); and

•     where a spare transformer can be deployed to replace the out-of-service transformer,
      this option will be identified as one of the operational solutions to mitigate the severity
      of a major outage.




                                               Page 37
                                                   2010 Joint DB Transmission Connection Planning Report




4.6   Treatment of Load Transfer Capability

For many terminal stations there is some capability to transfer load from one terminal
station to adjacent terminal stations using the distribution network. The amount of load
that can be transferred varies from minimal amounts at most country terminal stations to
significant amounts at some urban terminal stations. Load transfers are able to be made
at 66 kV and/or 22 kV and lower voltage levels.

In the event of a transformer failure at a terminal station load could be transferred away
(where short-term transfer capability is available) and this would reduce the unserved
energy and the impact of an outage. Following careful consideration, the DBs have
decided that for the purpose of this report, short-term load transfer capability will not be
taken into account directly in the estimation of expected unserved energy in the event of a
major failure of a transformer. Instead, where short-term load transfer capability is
available at an individual terminal station, the risk assessment for that station will identify
this as one of the operational solutions to mitigate the severity of a major outage. If
investment can be undertaken to provide permanent load transfer capability to reduce risk
at the station, then this will be identified in the risk assessment as an option for alleviating
constraints at the station. Therefore whilst the risk assessments set out in this report
adopt a simplified analytical approach in terms of considering load transfer capability, the
more detailed system studies and economic evaluations that are undertaken by DBs prior
to committing to a particular project do explicitly consider load transfer capability.

Consistent with the approach outlined in section 4.5 above the analytical approach
applied in relation to transfer capability reduces the complexity of the initial analysis of
expected unserved energy prepared for this report.

4.7   Detailed risk assessments and options for alleviation of constraints, by
      terminal station

Set out on the following pages are the detailed risk assessments and a description of the
options available for alleviation of constraints, for each individual terminal station. The
assessments, by station, are set out in alphabetical order. For each station, the network
augmentation requirements (if any) and the estimated annual costs of the augmentation
works are identified. This cost estimate provides a broad indication of the maximum
potential value available to proponents of non-network solutions in deferring or avoiding
network augmentation.

However, it should be noted that the value of a non-network solution depends on the
extent to which it defers or avoids a network augmentation, and the expected timing of
the network augmentation. For example, a non-network solution that defers a network
augmentation from 2013 to 2016 is less valuable today than one which defers a network
augmentation from, say, 2012 to 2015. These issues should be considered by
proponents of non-network solutions in assessing the implications of this report.

In addition, any potential proponents of non-network solutions to emerging constraints
should note that the lead time for completion of a major network augmentation (such as
the development of a new station, or the installation of a new transformer) can easily be
up to two to three years, taking into account the need to obtain local authority planning




                                            Page 38
                                                     2010 Joint DB Transmission Connection Planning Report




consent 32 . In view of this consideration, the individual risk assessment commentaries for
each terminal station will:

•    identify the estimated lead time for delivery of the preferred network solution; and/or

•    identify the latest date by which the relevant DB(s) will generally require a firm
     commitment from proponents of non-network alternatives, in order to be confident that
     the network augmentation can be displaced or deferred without compromising supply
     reliability in the future.




32
        Section 1.7 provides a more detailed description of the processes and timeframes involved in
        implementing transmission connection projects.




                                              Page 39
                                                       2010 Joint DB Transmission Connection Planning Report




APPENDIX: ESTIMATION OF BASIC TRANSFORMER
RELIABILITY DATA AND SAMPLE OF EXPECTED
TRANSFORMER UNAVAILABILITY CALCULATION

1.     Estimation of basic transformer reliability data

The basic transformer reliability data adopted for the risk assessment is estimated as
follows:



                                              FAILURE RATE                   MEAN OUTAGE
                                                                              DURATION

Costly Major Failures 33                             0.4%                        5.0 months

Other Major Failures                                 0.6%                         1.0 month

Overall Major Failure Rate &                         1.0%                   (0.4*5.0 + 0.6*1.0) /
Weighted Average of Mean Outage                                                  (0.4+0.6)
Duration
                                                                               = 2.6 months


2.     Sample of expected transformer unavailability calculation


This appendix sets out an example demonstrating the calculation of the “Expected
Transformer Unavailability” for a terminal station with two transformers, using the basic
reliability data contained in Section 4.4.


Expected transformer unavailability due to major outage per                       A          0.217%
transformer-year (Refer to Section 4.4 for the base reliability
statistics

Number of transformers                                                            B              2

Expected unavailability of one transformer (probability of                    C=A*B          0.434%
being in state N-1)

Expected unavailability of both transformers (probability of                  D=A*A         0.00047%
being in state N-2) 34




33
       The costly major failures are those that would result in repair costs greater than 2% of the
       replacement value of the failed transformer, with a relatively long duration of outage for repair.
34
       The coincident outages of two transformers are considered to be “independent events”. This means
       that the failure of one transformer is assumed to not affect the availability of the other.




                                               Page 40
                                                                 2010 Joint DB Transmission Connection Planning Report




Example Calculation
The following example is used to illustrate the methodology to calculate “Expected
Unserved Energy” for a 2-transformer terminal station, given the following data and the
load duration curve shown below:

Required Data:
•    Maximum Demand = 80 MW
•    (N-1) Rating = 70 MW
•    (N-2) Rating = 0 MW
•    Annual Maximum Demand Growth Rate = 3.0%
•    Annual Energy Growth Rate = 1.5%
•    VCR = $30,000 per MWh 35

Risk assessment results for first and second order contingencies (i.e. one and two
transformers out of service, respectively) over 10 years are presented for this example. It
is assumed that the shape of the load duration curve will not change over the forecast
period. Detail calculations are shown for the first year.


                                            Annual Load Duration Curve

     90.0

                      Enegy above (N-1) rating
     80.0
                                                                                      (N-1) Rating = 70 MW

     70.0


     60.0


     50.0


     40.0


     30.0


     20.0


     10.0                                                                         (N-2) Rating = 0 MW

      0.0
            0       1000        2000         3000    4000        5000      6000        7000             8000   9000

                                                     Time of the Year


Risk Assessment Calculations for the first year

Energy at risk for an N-1 contingency is determined as the area below the load duration
curve, but in excess of the N-1 rating, as shown above. For this example, this is given by:

•    Energy above N-1 Rating in year 1 = 132 MWh




35
            A VCR of $30,000 per MWh is used for illustrative purposes only.




                                                        Page 41
                                                         2010 Joint DB Transmission Connection Planning Report




Similarly, energy at risk for an N-2 contingency is determined as the area below the load
duration curve, but in excess of the N-2 rating:

•    Energy above N-2 Rating in year 1 = 367,877 MWh


First Order Contingency (N-1):

Expected Unserved Energy = (Energy above N-1 Rating) * (N-1 Probability)
                         = (132 MWh) * (0.434%) = 0.6 MWh

Customer Value                    = (Expected Unserved Energy) * (VCR)
                                  = (0.6 MWh) * ($30,000 per MWh 36 ) = $18,000

Second Order Contingency (N-2)

Expected Unserved Energy = (Energy above N-2 Rating) * (N-2 Probability)
                         = (367,877 MWh) * (0.00047%) = 1.7 MWh

Customer Value                    = (Expected Unserved Energy) * (VCR)
                                  = (1.7 MWh) * ($30,000 per MWh) = $51,000

Based on the data set out above, the expected unserved energy and corresponding
customer value can be calculated for each year over the next 10 years. The results of
these calculations are summarised and presented in the table and chart below. The
following conclusions can be drawn from the results:

•    The value of expected unserved energy for a 2nd order contingency is comparable to
     the value of expected unserved energy for a 1st order contingency in the earlier years
     (when the peak demand is roughly the same as the N-1 rating at the station).
     However, the combined total value of unserved energy for first and second order
     contingencies in those early years is highly unlikely to economically justify a large
     capital investment, such as the installation of a new transformer.

•    Over the ten year planning horizon, the value of expected unserved energy for a 1st
     order contingency grows at a much faster rate than the value of expected unserved
     energy for a 2nd order contingency.

•    The value of expected unserved energy associated with 2nd order contingencies only
     would be unlikely to be sufficiently high to economically justify any major
     augmentation. Hence, if a terminal station was expected to remain within its N-1
     rating over the planning period, major augmentation (such as the installation of a third
     transformer) would not be economically justified.

•    In undertaking a detailed economic evaluation of network investment, the quantity and
     value of energy at risk associated with higher order contingencies should be
     assessed. However, for the purpose of providing an indication of the likely timing of
     the need for new investment, it is sufficient to consider the expected unserved energy
     associated with first order contingencies only.




36
        A VCR of $30,000 per MWh is used for illustrative purposes only.




                                                Page 42
                                                                                2010 Joint DB Transmission Connection Planning Report




                                        Customer Value of Risk for 1st and 2nd Order Contingency

                                  Customer Value (1st Order Contingency)                   Customer Value (2nd Order Contingency)

                 $1,000,000




                  $800,000
Customer Value




                  $600,000




                  $400,000




                  $200,000




                        $0
                              1          2           3          4          5          6       7          8          9          10
                                                                               Year




                                                                       Page 43
                                                                                                     2010 Joint DB Transmission Connection Planning Report




Summary of Risk Assessment Results for a 2-Transformer Terminal Station Example

                        Year 1     Year 2     Year 3     Year 4     Year 5     Year 6     Year 7      Year 8        Year 9        Year 10

Maximum Demand           80.0       82.4       84.9       87.4       90.0       92.7       95.5        98.4          101.3         104.4

N-1 Risk Assessment

•   Rating               70.0       70.0       70.0       70.0       70.0       70.0       70.0        70.0          70.0           70.0

•   Demand above         10.0       12.4       14.9       17.4       20.0       22.7       25.5        28.4          31.3           34.4
    Rating

•   Energy above          132        231        374        565        838       1,253      1,914      3,003          4,759         7,393
    Rating

•   Probability         0.433%     0.433%     0.433%     0.433%     0.433%     0.433%     0.433%     0.433%         0.433%        0.433%

•   Expected Unserved     0.6        1.0        1.6        2.4        3.6        5.4        8.3        13.0          20.6           32.0
    Energy

•   Customer Value       $18k       $30k       $48k       $72k       $108k      $162k      $249k      $390k         $618k          $960k

N-2 Risk Assessment

•   Rating                0.0        0.0        0.0        0.0        0.0        0.0        0.0         0.0           0.0           0.0

•   Demand above         80.0       82.4       84.9       87.4       90.0       92.7       95.5        98.4          101.3         104.4
    Rating

•   Energy above        367,877    373,395    378,996    384,681    390,452    396,308    402,253    408,287       414,411        420,627
    Rating

•   Probability         0.00047%   0.00047%   0.00047%   0.00047%   0.00047%   0.00047%   0.00047%   0.00047%      0.00047%      0.00047%

•   Expected Unserved     1.7        1.8        1.8        1.8        1.8        1.9        1.9         1.9           1.9           2.0
    Energy

•   Customer Value       $51k       $54k       $54k       $54k       $54k       $57k       $57k        $57k          $57k           $60k




                                                                    Page 44
2010 Transmission Connection Planning Report                                                                       Risk Assessment: ATS West



ALTONA TERMINAL STATION No 3 & 4 (ATS West) 66kV

Magnitude, probability and impact of loss of load

Altona Terminal Station 66 kV comprises three 1 150 MVA 220/66 kV transformers. Due to fault
level issues with the combined ATS/BLTS system, the station is configured so that one
transformer operates in parallel with the BLTS system, and is isolated from the other two
transformers. These two transformers are isolated via the permanently open 2-3 bus tie CB at
ATS, which electrically separates the two systems and effectively creates two separate terminal
stations. These stations are now called ATS/BLTS and ATS West (ATS bus 3 & 4).

The ATS West 66 kV supply area includes Laverton, Laverton North, Altona Meadows,
Werribee, Wyndham Vale, Mount Cottrell, Eynesbury, Tarneit, Hoppers Crossing and Point
Cook. The station supplies Powercor customers, as well as Air Liquide, a company supplied
directly from the 66 kV bus at ATS.

The 66 kV system between ATS and BLTS was re-configured throughout 2007. As a result,
growth in summer peak demand on the 66 kV network at ATS West is expected to be an
average of around 6.4 MVA (3%) per annum over the next 10 years. The peak load demand on
the entire ATS/BLTS 66 kV network reached 415.6 MW in summer 2007 (prior to the system
re-configuration). After the system reconfiguration ATS West MD was reduced to 175.5 MVA
(summer 2008 MD). During last summer (2009/10) the station peaked at 195.6 MVA.

ATS West 66 kV demand is summer peaking but the high demand is now extended over a four
month period. The graph below depicts the 10th and 50th percentile summer maximum demand
forecast together with the station’s operational “N” rating (all transformers in service) and the N-
1” rating at 35°C ambient temperature. Note that the dip in demand in 2016 is due to the
transfer of approx 21 MW from LV Zone Substation (ATS West) to a new AC22 Zone
Substation (supplied from Brooklyn Terminal Station). In 2018 the ATS West load increases
when a new Truganina Zone Substation is established with transfers of approximately 23.5 MW
from LVN Zone Substation (Brooklyn Terminal Station).

                                                             ATS West Summer Peak Forecasts


              600.0




              500.0




              400.0

                                                                                                                         (N) rating @ 35 deg C
                                                                                                     10% Weather Probability Forecast
        MVA




              300.0




              200.0
                                                                                                                         (N-1) Rating @ 35 deg C

                                                                                                         50% Weather Probability Forecast

              100.0
                                           Actuals             Forecasts




                0.0
                      2006   2007   2008       2009   2010    2011     2012   2013    2014    2015      2016      2017      2018        2019     2020
                                                                              Year




1
        The 3rd (No 4) transformer at ATS has been in service since March 2008.


                                                                                                                                                   Page 1 of 5
2010 Transmission Connection Planning Report                                                                                            Risk Assessment: ATS West



The historical data shown represents the entire ATS/BLTS system, prior to the system re-
configuration and ATS 3rd transformer works. In 2007, Altona Terminal Station was effectively
split into two separate terminal stations, as described earlier. Due to these re-configuration
works, the station peaks from 2008 to 2010 were significantly lower than the previous MDs.

The “N” rating on the chart indicates the maximum load that can be supplied from ATS West
with all transformers in service. The “N-1” rating on the chart is the load that can be supplied
from ATS West with one 150 MVA transformer out of service.

The graph above shows that from 2008 onwards, there is insufficient capacity to supply the
forecast demand at 50th percentile temperature at ATS West if a forced outage of a transformer
occurs. The substation summer load is slightly above its N-1 rating in 2008 but increasing to
23.6% above N-1 in 2011, 41% in 2015 and 67% in 2020.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast is
expected to exceed the N-1 capability rating. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast. As already
noted, the dip in forecast ATS West demand in 2016 is due to transfer of approx 21 MW from
LV Zone Substation (ATS West) to a new AC22 Zone Substation (supplied from Brooklyn
Terminal Station). In 2018 the ATS West load increases when a new Truganina Zone
Substation is established with transfers of approximately 23.5 MW from LVN Zone Substation
(Brooklyn Terminal Station).


                                                Annual Energy and Hours at Risk and Expected Customer Value at ATS West under transformer outage condition


                                              Hours at risk (LH Scale)           Energy at risk (MWh) (LH Scale)             Customer Value (RH Scale)

                               17000                                                                                                                                 $3,500,000
                               16000
                               15000
                                                                                                                                                                     $3,000,000
                               14000
                               13000
                               12000                                                                                                                                 $2,500,000
  MWhr at Risk/Hours at Risk




                               11000
                               10000
                                                                                                                                                                     $2,000,000
                               9000
                               8000
                                                                                                                                                                     $1,500,000
                               7000
                               6000
                               5000                                                                                                                                  $1,000,000
                               4000
                               3000
                                                                                                                                                                     $500,000
                               2000
                               1000
                                  0                                                                                                                                  $0
                                       2011          2012          2013       2014         2015          2016       2017         2018        2019            2020
                                                                                                  Year




Comments on Energy at Risk

For an outage of one transformer at ATS West 66 kV, there will be insufficient capacity at the
station to supply all demand at the 50th percentile temperature for about 761 hours in summer
2020. The energy at risk at the 50th percentile temperature under N-1 conditions is estimated
to be 15,697MWh in 2020. The estimated value to consumers of the 15,697MWh of energy at

                                                                                                                                                                    Page 2 of 5
2010 Transmission Connection Planning Report                                        Risk Assessment: ATS West



risk is approximately $739.1 million (based on a value of customer reliability of $47,089/MWh). 2
In other words, at the 50th percentile demand level, and in the absence of any other operational
response that might be taken to mitigate the impact of a forced outage, a major outage of one
transformer at ATS West in 2020 would be anticipated to lead to involuntary supply
interruptions that would cost consumers $739.1 million.

It is emphasised however, that the probability of a major outage of one of the two 150 MVA
transformers occurring over the year is very low (0.217% per transformer). When the energy at
risk (15,697 MWh for 2020) is weighted by this low probability, the expected unsupplied energy
is estimated to be around 68.02 MWh. This expected unserved energy is estimated to have a
value to consumers of around $3.2 million (based on a value of customer reliability of
$47,089/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each year.
Under more extreme summer temperature conditions (that is, at the 10th percentile level), the
energy at risk in 2020 is estimated to be 24,350 MWh. The estimated value to consumers of
this energy at risk in 2020 is approximately $1,147 million. The corresponding value of the
expected unserved energy is $5 million.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the table
below.

                                                                       MWh           Valued at consumer
                                                                                      interruption cost
Energy at risk, at 50th percentile demand forecast                   15,697               $739.1 million

Expected unserved energy at 50th percentile demand                        68               $3.2 million

Energy at risk, at 10th percentile demand forecast                   24,350               $1,147 million

Expected unserved energy at 10th percentile demand                      106                 $5 million



If one of the 150 MVA 220/66 kV transformers at ATS West is taken off line during peak loading
times and the N-1 station rating is exceeded, the OSSCA 3 load shedding scheme which is
operated by SPI PowerNet’s TOC 4 will act swiftly to reduce the loads in blocks to within safe
loading limits. Any load reductions that are in excess of the minimum amount required to limit
load to the rated capability of the station would be restored at zone substation feeder level in
accordance with Powercor’s operational procedures after the operation of the OSSCA scheme.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:


2
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in
        accordance with the composition of the load at this terminal station.
3
        Overload Shedding Scheme of Connection Asset.
4
        Transmission Operation Centre.


                                                                                                        Page 3 of 5
2010 Transmission Connection Planning Report                                       Risk Assessment: ATS West



1. Install additional transformation capacity and reconfigure 66 kV exits at ATS. This means
   that the station will be configured so that three transformers are supplying the ATS West
   load, and one transformer will continue to provide capacity to the ATS/BLTS system.

2. Establish a new Deer Park terminal station with proposed Truganina zone substation
   connected to this station instead of to ATS West. This option is subject to a planning study
   underway for Keilor Terminal station.

3. Demand reduction: There is an opportunity to develop a number of innovative customer
   schemes to encourage voluntary demand reduction during times of network constraint. The
   amount of potential demand reduction depends on the customer uptake and would be taken
   into consideration when determining the optimum timing of any network capacity
   augmentation.

4. Embedded generation, connected to the ATS 66 kV bus, may substitute or defer the need
   for capacity augmentations.

Preferred option for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at ATS, it is proposed to install additional transformation capacity and reconfigure 66 kV
exits at ATS or to connect Truganina zone substation to the proposed Deer Park terminal
station.

On the basis of the 50th percentile demand forecast scenario, the preferred works would not be
expected to be needed before 2016 to support the peak summer demand for an N-1 condition.

The capital cost of installing additional transformation capacity and reconfiguring 66 kV exits at
ATS is estimated to be in excess of $13 million. The cost of establishing, operating, and
maintaining the new transformer and reconfigured subtransmission lines would be recovered
from network users through network charges, over the life of the assets. The estimated total
annual cost of the preferred network option is $1.3 million.

This cost provides a broad upper bound indication of the maximum contribution from
distributors which may be available to embedded generators or customers to reduce forecast
demand and defer or avoid the transmission connection component of this augmentation. 5 Any
non-network solution that defers this augmentation for say 1-2 years, will not have as much
potential value (and contribution available from distributors) as a solution that eliminates or
defers the augmentation for, say, 10 years. Sections 1.4 and 1.5 of this report provide further
background information to proponents of non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




5
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments and
        recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-
        recovery-of-transmission-related-charges.html). The Rule change, if accepted, would replicate the previous
        regulatory arrangements in Victoria.

                                                                                                       Page 4 of 5
2010 Transmission Connection Planning Report                                          Risk Assessment: ATS West



Altona Terminal station (ATS West) 66kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                Powercor (98%) & Air Liquide (2%)
                                                                 MW      MVA
Normal cyclic rating with all plant in service                           340 via 2 transformers
Summer N-1 Station Rating:                                       158     170 [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       176     187

Station: ATS West 66kV                                      2011         2012        2013         2014         2015        2016         2017        2018         2019            2020
50th percentile Summer Maximum Demand (MVA)                210.6        217.1        224.3       231.8        239.7       224.8        232.6        264.9       274.2            283.9
Summer % Overload [See Note 2 below]                       23.86        27.73        31.95       36.37        40.99       32.22        36.81        55.81       61.30            66.98
50th percentile Winter Maximum Demand (MVA)                148.1        153.2        158.4       163.8        169.6       153.9        159.4        202.8       210.2            217.7
Winter % Overload [See Note 2 below]                         Nil          Nil          Nil         Nil          Nil         Nil          Nil         8.47       12.41            16.41
Annual energy at risk (MWh) [See Note 3 below]             694.5       1092.1      1676.3       2424.4      3385.6       1717.9       2510.3      8231.3     11374.7           15696.5
Annual hours at risk [See Note 4 below]                     63.8         91.3       117.5        147.3       182.8        118.5        150.5       412.5       570.3             761.3
Expected Annual Unserved Energy (MWh) [See
Note 5 below]
                                                             3.01        4.73         7.26       10.51        14.67         7.44       10.88        35.67       49.29            68.02
Expected Annual Unserved Energy valued at in
accordance with the value of customer reliability as
                                                        $141,715     $222,847    $342,055     $494,708     $690,844    $350,544     $512,236 $1,679,627 $2,321,049        $3,202,928
estimated in the September 2009 study
commissioned by VENCorp. [See Note 6 below]

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy that may not be supplied in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating, if
    there is a major outage of a transformer (see Note 5 below), and no other mitigation action is taken.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
    outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
    station.
7. The "N" and "N-1" rating is estimated and to be confirmed by SPI PowerNet.




                                                                                                                                                                     Page 5 of 5
2010 Transmission Connection Planning Report                          Risk Assessment: ATS-BLTS



ALTONA/BROOKLYN TERMINAL STATION (ATS/BLTS) 66kV

Magnitude, probability and impact of loss of load

Altona/Brooklyn Terminal Station (ATS/BLTS) 66 kV comprises two terminal stations in close
proximity, connected by strong subtransmission ties. The ATS/BLTS 66 kV supply area
includes Altona, Brooklyn, Laverton North, Tottenham, Footscray and Yarraville. The stations
supply both Jemena Electricity Network and Powercor customers.

ATS consist of three 150 MVA 220/66 kV transformers with the 2-3 66 kV bus tie circuit breaker
locked open to manage fault levels. Under these arrangements, only one ATS 150 MVA
220/66 kV transformer operates in parallel with the BLTS system. BLTS consists of two 55
MVA 220/66 kV transformers and one 150 MVA 220/66 kV transformer supplying the 66 kV
buses. One 60 MVA 220/66 kV transformer (standby transformer) operates in a normally open
auto-close scheme to manage fault levels.

A 66/22 kV transformer and 35 MVA phase angle regulator connects the BLTS 66 kV bus to the
BLTS 22 kV bus. A synchronous condenser connected to the BLTS 66 kV bus controls the
220 kV voltage.

The 66 kV system between ATS and BLTS was re-configured during 2007. Growth in summer
peak demand on the 66 kV network at ATS/BLTS is expected to rise at an average of around
2.7% per annum over the next five years. The peak load demand on the entire ATS/BLTS 66
kV network reached 301.6 MW in summer 2010.

ATS/BLTS 66 kV demand is summer peaking but the high demand occurs over a four month
period. The graph below depicts the 10th and 50th percentile summer maximum demand
forecast together with the stations operational “N” rating (all transformers in service) and the
“N-1” rating at 35°C ambient temperature.

The load characteristic for ATS/BLTS substation is of a mixed nature, consisting of residential
and industrial applications. The rate of load growth is seen to be lower than the previous year’s
forecast. This is due to the slowdown in industrial activity in the area following the economic
downturn triggered by the global financial crisis. The economic outlook for the immediate
future remains uncertain; however economic recovery will increase the rate of load growth at
the station. Any such increase would result in an increase in the forecast load at risk.




                                                                                       Page 1 of 6
2010 Transmission Connection Planning Report                          Risk Assessment: ATS-BLTS




The “N” rating on the chart indicates the maximum load that can be supplied from ATS-BLTS
with all transformers in service. The “N-1” rating on the chart is the load that can be supplied
from ATS-BLTS with one 150 MVA transformer out of service.

The graph above shows that from 2015 onwards, there is insufficient capacity to supply the
forecast demand at 50th percentile temperature at ATS-BLTS if a forced outage of a
transformer occurs.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast is
expected to exceed the N-1 capability rating. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.

The peak energy at risk is in the year 2017. Then, there is drop in energy at risk in 2018 due to
planned load transfers from Laverton North zone substation to the proposed Truganina zone
substation, resulting in ATS-BLTS being offloaded to the adjacent ATS/West terminal station. It
is noted that future augmentation plans for Keilor Terminal Station involve a new terminal
station at Deer Park and the proposed Truganina zone substation may be connected to that
station in the future. Under either option, ATS-BLTS will be off loaded by 2018.




                                                                                       Page 2 of 6
2010 Transmission Connection Planning Report                                        Risk Assessment: ATS-BLTS




Comments on Energy at Risk

For a major outage of one transformer at ATS-BLTS 66 kV, there will be insufficient capacity at
the station to supply all demand at the 50th percentile temperature for about 131 hours in
summer 2017, which will then reduce to 116.5 in 2020 due to 22 kV load transfer to a proposed
new Zone substation. The energy at risk at the 50th percentile temperature under N-1
conditions is estimated to be 1390 MWh in 2017 and 1246 in 2020. The estimated value to
consumers of the 1390 MWh of energy at risk is approximately $76.0 million (based on a value
of customer reliability of $54,658/MWh). 1 In other words, at the 50th percentile demand level,
and in the absence of any other operational response that might be taken to mitigate the impact
of a forced outage, a major outage of one transformer at ATS-BLTS in 2017 would be
anticipated to lead to involuntary supply interruptions that would cost consumers approximately
$76.0 million.

It is emphasised however, that the probability of a major outage of one of the two 150 MVA
transformers occurring over the year is very low at about 1% per annum, while the expected
unavailability per transformer per annum is 0.217% per transformer. When the energy at risk
(1390 MWh for 2017) is weighted by this low probability, the expected unsupplied energy is
estimated to be around 9.0 MWh. This expected unserved energy is estimated to have a value
to consumers of around $493,763 (based on a value of customer reliability of $54,658/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each year.
Under more extreme summer temperature conditions (that is, at the 10th percentile level), the
energy at risk in 2017 is estimated to be 5726 MWh. The estimated value to consumers of this
energy at risk in 2017 is approximately $313.0 million. The corresponding value of the
expected unserved energy is approximately $1,910,922.



1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in
        accordance with the composition of the load at this terminal station.
                                                                                                        Page 3 of 6
2010 Transmission Connection Planning Report                            Risk Assessment: ATS-BLTS



These key statistics for the year 2017 & 2020 under N-1 outage conditions are summarised in
the table below.


                                                   2017                         2020
                                         MWh           Valued at       MWh         Valued at
                                                       consumer                    consumer
                                                   interruption cost           interruption cost
Energy at risk, at 50th percentile      1390            $76 million    1246       $68 million
demand forecast

Expected unserved energy at               9.0            $493,000      8.1         $442,000
50th percentile demand

Energy at risk, at 10th percentile      5726            $313 million   5379       $294 million
demand forecast

Expected unserved energy at             37.2             $2 million    35.0       $1.9 million
10th percentile demand



If one of the 150 MVA 220/66 kV transformers at ATS-BLTS is taken off line during peak
loading times and the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme
which is operated by SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to
within safe loading limits. Any load reductions that are in excess of the minimum amount
required to limit load to the rated capability of the station would be restored at zone substation
feeder level in accordance with Jemena Electricity Networks and Powercor’s operational
procedures after the operation of the OSSCA scheme.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Transfer loads from ATS-BLTS when extra capacity becomes available to either the
   adjacent ATS West terminal station or the proposed Deer Park terminal station (which is
   subject to a planning study underway in relation to Keilor terminal station).

2. Establishment of a new terminal station in the Tarneit area and reconfiguration of the
   subtransmission network. This option is more expensive than option 1.

3. Demand reduction: There is an opportunity for voluntary demand reduction to contribute to
   a reduction in demand at the station during times of network constraint. The amount of
   potential demand reduction would be taken into consideration when determining the
   optimum timing of any network capacity augmentation.

4. Embedded generation, connected to the ATS-BLTS 66kV bus, may substitute capacity
   augmentations.

2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre.
                                                                                        Page 4 of 6
2010 Transmission Connection Planning Report                        Risk Assessment: ATS-BLTS



Preferred option for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at ATS-BLTS, it is proposed to transfer loads from ATS-BLTS system to adjacent stations
when extra capacity becomes available at ATS West or a possible future Deer Park terminal
station. This work is not expected to be needed before 2016 (refer also to the risk assessment
for ATS West). The cost associated with these load transfers will be part of the ATS West
augmentation or a possible future Deer Park terminal station project.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                    Page 5 of 6
2010 Transmission Connection Planning Report                                            Risk Assessment: ATS-BLTS

 Altona/Brooklyn Terminal station
 Detailed data: Magnitude and probability of loss of load

 Distribution Businesses supplied by this station:                     Powercor-55.34% Jemena Electricity Network-44.36%
                                                                         MW         MVA
                                                                                                via BLTS-1, 2 & 4 (3A OOS) and ATS-4 transformers (Summer peaking)
 Normal cyclic rating with all plant in service                                      447         [See Note 7 below for interpretation of N]
 Summer N-1 Station Rating:                                                          340        [See Note 1 & 7 below for interpretation of N-1]
 Winter N-1 Station Rating:                                                          509


 Station: ATS-BLTS                                                         2011       2012          2013            2014          2015         2016          2017       2018       2019       2020

 50th percentile Summer Maximum Demand (MVA)                               330.3      333.0        331.0           337.7          343.8       371.8          376.9      362.7      368.2      376.0

 Summer % Overload [See Note 2 below]                                         Nil       Nil           Nil             Nil          1.13            9.35      10.84       6.68        8.3       10.5

 50th percentile Winter Maximum Demand (MVA)                               320.4      316.1        319.5           319.5          325.6       332.0          358.6      363.8      350.0      355.4

 Winter % Overload [See Note 2 below]                                         Nil       Nil           Nil             Nil            Nil            Nil        Nil        Nil        Nil           Nil

 Annual energy at risk (MWh) [See Note 3 below]                              0.0        0.0          0.0              0.5          21.7       858.8         1389.8      752.9      664.9     1245.8

 Annual hours at risk [See Note 4 below]                                     0.0        0.0          0.0              1.3           7.0            76.3      131.0      108.3       66.5      116.5

 Expected Annual Unserved Energy (MWh) [See Note 5 below]                   0.00       0.00         0.00             0.00          0.14            5.58       9.03       4.89       4.32       8.10

 Expected Annual Unserved Energy valued at VoLL wholesale market
                                                                              $0           $0         $0             $33        $1,411      $55,822        $90,337    $48,939    $43,219    $80,977
 price cap of $10,000/MWh

 Expected Annual Unserved Energy valued at in accordance with the
 value of customer reliability as estimated in the August 2008 study          $0           $0         $0            $178        $7,710     $305,112       $493,763   $267,488   $236,223   $442,604
 commissioned by VENCorp. [See Note 6 below]


 1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
 2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
 3. “Annual energy at risk” is the amount of energy that may not be supplied in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating, if there is
    a major outage of a transformer (see Note 5 below), and no other mitigation action is taken.

 4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.

 5. “Expected annual unserved energy” means “Annual Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
 6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.
 7. The "N" and "N-1" rating is estimated and to be confirmed by SPI Powernet

                                                                                                                                                                                     Page 6 of 6
      2010 Transmission Connection Planning Report                                                              Risk Assessment: BATS



      BALLARAT TERMINAL STATION (BATS) 66 kV

      Ballarat Terminal Station (BATS) 66 kV consists of two 150 MVA 220/66 kV transformers
      and is the main source of supply for over 63,000 customers in Ballarat and the surrounding
      area. The station supply area includes Ballarat CBD and Ararat via the interconnected
      66 kV tie with Horsham Terminal Station (HOTS).

      Magnitude, probability and impact of loss of load

      Demand at BATS 66 kV is summer peaking. Growth in summer peak demand at BATS has
      averaged around -0.4 MW (-0.3%) per annum over the last 5 years. The peak load on the
      station reached 162 MW in summer 2010.

      The graph below depicts the 10th and 50th percentile maximum demand forecasts together
      with the station’s operational “N” rating (all transformers in service) and the “N-1” rating at
      35°C ambient temperature. The 10th and 50th percentile demand forecasts are assumed to
      be similar because historical data has shown that the overall peak demand is not driven by
      temperature sensitive load.
                                                       BATS 66kV Summer Peak Forecast

      400.0



      350.0      (N) rating @ 35 deg C

                                                                                 Actuals            Forecasts
      300.0

                                                                     10% and 50% Weather Probability Forecast

      250.0
MVA




      200.0      (N-1) Rating @ 35 deg C


      150.0

                                                                                           30 min interval data used from 2010, as
      100.0                                                                                per AEMO revised standard.
                                           Drop in forecast due to transfer of
                                           BMH z/sub from BATS to BLTS
       50.0



        0.0
              1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
                                                                                   Year


      The (N) rating on the chart indicates the maximum load that can be supplied from BATS with
      all transformers in service.

      There has been a transfer of BMH zone substation from BATS to BLTS which has resulted
      in a reduction in demand at BATS, as shown in the above chart.

      The bar chart below depicts the energy at risk with one transformer out of service for the 50th
      percentile demand forecast, and the hours per year that the 50th percentile demand forecast
      is expected to exceed the N-1 capability rating. The line graph shows the value to
      consumers of the expected unserved energy in each year, for the 50th percentile demand
      forecast.

                                                                                                                                     Page 1 of 5
                              2010 Transmission Connection Planning Report                                                          Risk Assessment: BATS




                                                                         Annual Energy and Hours at Risk at BATS

                                              Hours at risk (LH Scale)            Energy at risk (MWh) (LH Scale)          Customer Value (RH Scale)

                             40                                                                                                                                $9,000


                             35                                                                                                                                $8,000


                                                                                                                                                               $7,000
                             30
MWhr at Risk/Hours at Risk




                                                                                                                                                               $6,000
                             25

                                                                                                                                                               $5,000
                             20
                                                                                                                                                               $4,000

                             15
                                                                                                                                                               $3,000

                             10
                                                                                                                                                               $2,000


                             5                                                                                                                                 $1,000


                             0                                                                                                                                 $0
                                  2011         2012          2013          2014        2015          2016           2017    2018         2019          2020
                                                                                              Year




                              Comments on Energy at Risk

                              For a major outage of one transformer at BATS during the critical loading period, there will
                              be insufficient capacity at the station to supply all demand at the 50th percentile temperature
                              for about 10.3 hours in 2020. The energy at risk at the 50th percentile temperature for a
                              major outage of one transformer is approximately 0.15 MWh in 2020. The estimated value
                              to customers of this energy at risk is approximately $1.89 million (based on a value of
                              customer reliability of $55,902/MWh). 1 In other words, at the 50th percentile demand level,
                              and in the absence of any other operational response that might be taken to mitigate the
                              impact of a forced outage, a major outage of one transformer at BATS in 2020 would be
                              anticipated to lead to involuntary supply interruptions that would cost consumers
                              $1.89 million.

                              It is emphasised however, that the probability of a major outage of one of the two
                              transformers occurring over the year is very low at about 1.0% per transformer per annum,
                              while the expected unavailability per transformer per annum is 0.217%. When the energy at
                              risk (0.15 MWh for 2020) is weighted by this low unavailability, the expected unsupplied
                              energy is estimated to be around 0.15 MWh. This expected unserved energy is estimated to
                              have a value to consumers of around $8,200 (based on a value of customer reliability of
                              $55,902/MWh). These estimates of energy at risk and expected unserved energy apply to
                              the 10th percentile and 50th percentile demand forecasts.

                              It should also be noted that the above estimates of energy at risk and expected unserved
                              energy are based on an assumption of moderate summer temperatures occurring in each
                              year. Under more extreme summer temperature conditions (that is, at the 10th percentile

                              1
                                         The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3,
                                         weighted in accordance with the composition of the load at this terminal station.


                                                                                                                                                       Page 2 of 5
2010 Transmission Connection Planning Report                             Risk Assessment: BATS



level), the energy at risk in 2020 is estimated to be 127 MWh. The estimated value to
consumers of this energy at risk in 2020 is approximately $7.1 million. The expected
unsupplied energy is estimated to be around 0.6 MWh, which has an estimated value of
approximately $31,000.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                            MWh         Valued at consumer
                                                                         interruption cost
Energy at risk, at 50th percentile demand forecast           33.8            $1.9 million

Expected unserved energy at 50th percentile demand           0.15               $8,200

Energy at risk, at 10th percentile demand forecast            127            $7.1 million

Expected unserved energy at 10th percentile demand            0.6              $31,000


If one of the 220/66 kV transformers at BATS is taken off line during peak loading times and
the N-1 station rating is exceeded, the OSSCA 2 automatic load shedding scheme which is
operated by SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe
loading limits. Any load reductions that are in excess of the minimum amount required to
limit load to the rated capability of the station would be restored at zone substation feeder
level in accordance with Powercor’s operational procedures after the operation of the
OSSCA scheme.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

•        A contingency plan to transfer load to the Horsham Terminal Station is available
         using the 66 kV tie network between BATS and HOTS. This transfer capacity is up
         to 10 MVA. Due to the geographical location of the Ballarat Terminal Station, no
         other transfer capability is available.

•        An additional 150 MVA 220/66 kV transformer could be installed at BATS. Installing
         an additional transformer at BATS is technically feasible and is likely to be the most
         cost-effective network solution.

•        Demand reduction: There is an opportunity for voluntary demand reduction to
         contribute to a reduction in loading at the terminal station during times of network
         constraint.

•        Embedded generation, connected to the BATS 66 kV network, may defer the need
         for installation of an additional 220/66 kV transformer at BATS. Challicum Hills wind
         farm (52.5 MW) was commissioned in July 2003 and is connected to the 66 kV tie
         system between BATS and HOTS. When generating, this wind farm off-loads both
         BATS & HOTS 220/66 kV transformers. Additional wind generation in the area is


2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre.


                                                                                     Page 3 of 5
2010 Transmission Connection Planning Report                                         Risk Assessment: BATS



         being investigated. However, wind generation does not provide reliable generating
         capacity at times of peak local network loading.

Preferred option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at BATS, it is proposed to:

1. Install an additional 150 MVA 220/66 kV transformer at BATS. On the basis of the
   medium growth scenario, the new transformer at the terminal station is unlikely to be
   required before 2020 to support the peak demand for an N-1 condition.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at BATS under critical loading conditions before a 3rd transformer is
   commissioned:

    •   maintain contingency plans to transfer load quickly to the Horsham Terminal Station
        utilising the 66 kV tie line between BATS and HOTS. This option has limited transfer
        capability, in the order of 10 MVA;

    •   subject to the availability of the SPI PowerNet spare 220/66 kV transformer for rural
        areas (refer to Section 4.5), this spare transformer can be used to temporarily
        replace a failed transformer to minimise the transformer outage period.

The capital cost of installing a new 220/66kV transformer at BATS is estimated to be
$12 million. The cost of establishing, operating and maintaining a new transformer would be
recovered from network users through network charges, over the life of the asset. The
estimated total annual cost of the preferred network option is around $1.2 million. This cost
provides a broad upper bound indication of the network support payment which may be
available 4 to embedded generators or customers to reduce forecast demand and defer or
avoid the transmission connection component of this augmentation. Any non-network
solution that defers this augmentation for say 1-2 years, will not have as much potential
value (and contribution available from distributors) as a solution that eliminates or defers the
augmentation for, say, 10 years. Sections 1.4 and 1.5 of this report provide further
background information to proponents of non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see    http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.


                                                                                                    Page 4 of 5
   2010 Transmission Connection Planning Report                                            Risk Assessment: BATS



   Ballarat Terminal Station
   Detailed data: Magnitude and probability of loss of load
   Distribution Businesses supplied by this station:                Powercor (100%)
                                                                    MW          MVA
   Normal cyclic rating with all plant in service                               341         via 2 transformers
   Summer N-1 Station Rating:                                       167         185         [See Note 1 below for interpretation of N-1]
   Winter N-1 Station Rating:                                       186         198

Station: BATS 66kV                                         2011       2012        2013         2014        2015        2016        2017          2018         2019           2020
50th percentile Summer Maximum Demand
                                                          183.5      185.8        187.5       188.8       190.2       191.5        192.8        193.2         194.5         195.8
(MVA)
Summer % Overload [See Note 2 below]                          Nil       0.5         1.4          2.0         2.8         3.5          4.2          4.4          5.1            5.8
50th percentile Winter Maximum Demand (MVA)               173.0      176.1        178.5       180.1       181.3       182.8        184.0        185.2         185.6         186.9
Winter % Overload [See Note 2 below]                          Nil       Nil          Nil          Nil        Nil         Nil          Nil          Nil           Nil           Nil
Annual energy at risk (MWh) [See Note 3
                                                             0.0        0.0         0.0          1.2         4.2         8.9        14.9         17.3          25.0          33.8
below]
Annual hours at risk [See Note 4 below]                      0.0        0.5         1.5          2.8         4.0         4.5          6.5          7.3          8.3          10.3
Expected Annual Unserved Energy (MWh) [See
                                                            0.00      0.00         0.00         0.01       0.02        0.04         0.06         0.08          0.11          0.15
Note 5 below]
Expected Annual Unserved Energy valued at
VoLL wholesale market price cap of                            $0         $0          $2         $51        $181        $388        $647          $750       $1,084         $1,465
$10,000/MWh
Expected Annual Unserved Energy valued at
Consumer interruption cost based on Monash                    $0         $0          $9        $287      $1,011      $2,168      $3,618        $4,194       $6,058         $8,191
study [See Note 6 below]
   Notes:
   1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
                                                th
   2.   This is the percentage by which the 50 percentile forecast maximum demand exceeds the N-1 capability rating.
   3.   “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
   4.   “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
   5.   “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
        outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
   6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
        station.

                                                                                                                                                                        Page 5 of 5
2010 Transmission Connection Planning Report                                                                                       Risk Assessment: BETS



BENDIGO TERMINAL STATION (BETS) 66 kV & 22 kV

Magnitude, probability and impact of loss of load

Bendigo Terminal Station (BETS) 66 kV and 22 kV consists of three 230/66/22 kV
transformers; two are rated 70/57/51 MVA and one is rated 125/125/40 MVA. These are the
main source of supply for over 77,660 customers in Bendigo and the surrounding area. The
station supply area includes Bendigo CBD, Eaglehawk, Charlton, St. Arnaud, Maryborough
and Castlemaine.

Growth in summer peak demand at BETS has averaged around 12.6 MW (5.5%) per annum
over the last 5 years. The peak load on the station reached 230.3 MW (66 kV and 22 kV
networks) in summer 2010.

BETS 66 kV and 22 kV demand is summer peaking. The graph below depicts the 10th and
50th percentile summer maximum demand forecast together with the station’s operational
“N” rating (all transformers in service) and the “N-1” rating at 35°C ambient temperatures.


                                                          BETS 66&22kV Summer Peak Forecasts

        400.0
                                                                        Actuals                  Forecasts
                          (N) rating @ 35 deg C
        350.0

                                                                          10% Weather Probability Forecasts

        300.0



        250.0
  MVA




                                                                                                                      50% Weather Probability Forecasts
        200.0             (N-1) Rating @ 35 deg C


        150.0



        100.0



         50.0



          0.0
                2000   2001   2002   2003   2004   2005   2006   2007   2008   2009   2010   2011   2012      2013   2014   2015   2016   2017   2018     2019   2020
                                                                                      Year




The (N) rating on the chart indicates the maximum load that can be supplied from BETS with
all transformers in service. Exceeding this level will initiate automatic load shedding by
SPI PowerNet’s automatic load shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.




                                                                                                                                                        Page 1 of 5
2010 Transmission Connection Planning Report                                                                                                  Risk Assessment: BETS



                                                                           Annual Energy and Hours at Risk at BETS66&22

                                                Hours at risk (LH Scale)               Energy at risk (MWh) (LH Scale)          Customer Value (RH Scale)

                                 70000                                                                                                                         $16,000,000


                                                                                                                                                               $14,000,000
                                 60000


                                                                                                                                                               $12,000,000
                                 50000
    MWhr at Risk/Hours at Risk




                                                                                                                                                               $10,000,000
                                 40000

                                                                                                                                                               $8,000,000

                                 30000
                                                                                                                                                               $6,000,000

                                 20000
                                                                                                                                                               $4,000,000


                                 10000
                                                                                                                                                               $2,000,000


                                    0                                                                                                                          $0
                                         2011        2012         2013          2014         2015          2016          2017   2018        2019        2020
                                                                                                    Year



Comments on Energy at Risk

For a major outage of one transformer at BETS during the summer period, there will be
insufficient capacity at the station to supply all demand at the 50th percentile temperature for
about 279 hours in 2014. The energy at risk at the 50th percentile temperature under N-1
conditions is estimated to be 10,620 MWh in 2014. The estimated value to consumers of
the 10,620 MWh of energy at risk is approximately $635.4 million (based on a value of
customer reliability of $59,833/MWh). 1 In other words, at the 50th percentile demand level,
and in the absence of any other operational response that might be taken to mitigate the
impact of a forced outage, a major outage of one transformer at BETS in 2014 would be
anticipated to lead to involuntary supply interruptions that would cost consumers
approximately $635.4 million.

It is emphasised however, that the probability of a major outage of one of the two
transformers occurring over the year is very low at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (10,620 MWh for 2014) is weighted by this low unavailability, the expected unsupplied
energy is estimated to be around 46.02 MWh. This expected unserved energy is estimated
to have a value to consumers of around $2.8 million, (based on a value of customer
reliability of $59,833/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2014 is estimated to be 22,296 MWh. The estimated value to
consumers of this energy at risk in 2014 is approximately $1,334.0 million. The
corresponding value of the expected unserved energy is approximately $5.8 million.



1
                                     The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3,
                                     weighted in accordance with the composition of the load at this terminal station.



                                                                                                                                                               Page 2 of 5
2010 Transmission Connection Planning Report                              Risk Assessment: BETS



These key statistics for the year 2014 under N-1 outage conditions are summarised in the
table below.

                                                              MWh        Valued at consumer
                                                                          interruption cost
Energy at risk, at 50th percentile demand forecast         10,620            $635.4 million

Expected unserved energy at 50th percentile demand            46.0             $2.8 million

Energy at risk, at 10th percentile demand forecast         22,296            $1,334 million

Expected unserved energy at 10th percentile demand            96.6             $5.8 million



If one of the 230/66/22 kV transformers at BETS is taken off line during peak loading times
and the N-1 station rating is exceeded, the OSSCA 2 automatic load shedding scheme which
is operated by SPI PowerNet’s TOC 3 will act swiftly to reduce the loads in blocks to within
safe loading limits. Any load reductions that are in excess of the minimum amount required
to limit load to the rated capability of the station would be restored at zone substation feeder
level in accordance with Powercor’s operational procedures after the operation of the
OSSCA scheme.

Feasible options for alleviation of constraints

Due to the geographical location of the Bendigo terminal station less than 1 MVA of transfer
capability at 22 kV is available. In light of this, the following options to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint have been considered by
Powercor:

1.      Install two new 75 MVA 230/22 kV transformers. This option will separate the 66 kV
        and 22 kV points of supply and transfer load from the existing transformers. This
        option is being implemented.

2.      In conjunction with SP AusNet’s asset replacement plans to replace the two 70 MVA
        230/66/22 kV transformers by 2014, replace all three 230/66/22 kV transformers with
        two, 225 MVA 230/66 kV transformers and two, 60 MVA 66/22 kV transformers. This
        option will separate the 66 kV and 22 kV points of supply. This option has been
        found to be uneconomic due to its high cost.

3.      Installation of a new 230/66 kV terminal Station at Castlemaine. The terminal station
        would transfer load away from BETS and is being considered due to load growth
        around the Castlemaine and surrounding areas, and the potential for savings in
        additional 66 kV line construction from BETS. This option has been found to be
        uneconomic due to its high cost.

4.      Demand reduction: There is an opportunity for voluntary demand reduction to
        reduce peak demand during times of network constraint. The amount of demand
        reduction would be taken into consideration when determining the optimum timing for
        the capacity augmentation. However, no firm offers from proponents of non-network
        alternatives were received in relation to Powercor’s proposal (foreshadowed in the

2
        Overload Shedding Scheme of Connection Asset.
3
        Transmission Operation Centre.



                                                                                       Page 3 of 5
2010 Transmission Connection Planning Report                          Risk Assessment: BETS



        2008 and 2009 Transmission Connection Planning Reports) so Powercor is
        proceeding with option 1.

5.      Embedded generation, connected to the BETS 66 kV bus, may defer the need for an
        additional 230/66/22 kV transformer at BETS. However, no firm offers from
        proponents of non-network alternatives were received in relation to Powercor’s
        proposal (foreshadowed in the 2008 and 2009 Transmission Connection Planning
        Reports) so Powercor is proceeding with option 1.

Preferred option(s) for alleviation of constraints

As noted above, Powercor is now proceeding with the preferred option, which is to install
two new 75 MVA 230/22kV transformers at BETS.

The application notice explains the rationale for the proposed augmentation at BETS with
reference to the requirements of the regulatory test. It also provides a more detailed
description of the proposed works. The Application Notice can be downloaded from the
AEMO website at: http://www.aemo.com.au/consultations/0179-0004.pdf

On the basis of the 50th percentile demand forecast scenario, it is expected that the
additional capacity would not be required before 2014. However, the level of expected
unserved energy under the 10th percentile demand forecast scenario suggests that
installation of additional capacity by 2012 is justified. Powercor is presently negotiating
contracts with SPI PowerNet for the provision of the augmentation. On the basis of
SPI PowerNet’s advice regarding the lead time for works of this type, Powercor expects the
new transformers to be installed by November 2013. Powercor will work closely with
SPI PowerNet to achieve the earliest possible commissioning date for the augmentation.

Subject to the availability of the SPI PowerNet spare 220/66 kV transformer for rural areas
(refer to Section 4.5), that spare transformer can be used to temporarily replace a failed
transformer to minimise the transformer outage period, prior to the augmentation being
completed.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                  Page 4 of 5
2010 Transmission Connection Planning Report                                              Risk Assessment: BETS



Bendigo Terminal Station
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                Powercor (100%)
Normal cyclic rating with all plant in service                   350 MVA via 2 transformers (Summer peaking)
Summer N-1 Station Rating:                                       155.0 MW (180.0 MVA) [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       182.0 MW (188.0 MVA)

Station: BETS Sum 66&22kV                            2011          2012          2013          2014         2015         2016          2017         2018          2019            2020
50th percentile Summer Maximum
                                                     236.8         242.7         248.2         254.6        260.3        266.1         272.1        278.3         284.6           291.1
Demand (MVA)
Summer % Overload [See Note 2
                                                     31.54         34.85         37.88         41.42        44.60        47.85         51.19        54.60         58.11           61.70
below]
50th percentile Winter Maximum
                                                     177.4         180.9         183.9         187.5        190.7        194.0         197.4        200.8         204.3           207.9
Demand (MVA)
Winter % Overload [See Note 2 below]                    Nil           Nil           Nil          Nil         1.45          3.21         5.00         6.83          8.69           10.59
Annual energy at risk (MWh) [See
                                                    5242.4        6789.4        8409.2       10620.4     13039.3       16199.3      20676.3       27784.9      39954.3          58548.9
Note 3 below]
Annual hours at risk [See Note 4
below]                                               174.0         203.3         233.5         279.3        346.8        458.5         676.8       1135.5       1875.3           2703.3
Expected Annual Unserved Energy
                                                     22.72         29.42         36.44         46.02        56.50        70.20         89.60       120.40       173.14           253.71
(MWh) [See Note 5 below]
Expected Annual Unserved Energy
                                               $1,359,226     $1,760,326 $2,180,300 $2,753,610 $3,380,772 $4,200,083 $5,360,860 $7,203,946 $10,359,174 $15,180,300
value [See Note 6 below]
Notes:
1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.   This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
                                                                                    th
3.   “Annual energy at risk” is the amount of energy in a year during which the 50 percentile demand forecast exceeds the N-1 capability rating.
4.   “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5.   “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
     outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
     station.




                                                                                                                                                                     Page 5 of 5
2010 Transmission Connection Planning Report                         Risk Assessment: BLTS22 kV



BROOKLYN TERMINAL STATION (BLTS) 22kV

Magnitude, probability and impact of loss of load

Brooklyn Terminal Station (BLTS) 22 kV consists of two 60 MVA 220/22 kV transformers plus a
35 MVA 66/22 kV tie transformer/phase angle regulator (PAR), supplying the 22 kV network ex-
BLTS. This configuration is the main source of supply for 6,600 customers in Brooklyn and the
surrounding area. The station supply area includes Brooklyn and extends to the Altona and
Laverton North areas. The station supplies both Jemena and Powercor customers.

A terminal station rebuild project by SPI PowerNet has commenced and the two existing 60
MVA transformers will be replaced by two 75 MVA units in 2012. The 35 MVA tie
transformer/PAR will be retired which will reduce the reactive power compensation. In view of
this, the load estimates may differ from the values published in this report.

The peak load in summer 2010 has been recorded as 61.88 MW. This decrease in load
compared to 2009 is mainly due to 22 kV load transfers from BLTS to SU Zone substation.

BLTS 22 kV demand is summer peaking. The graph below depicts the 10th and 50th percentile
summer maximum demand forecast together with the station’s operational “N” rating (all
transformers in service) and the “N-1” rating at 35°C ambient temperature.




The “N” rating on the chart indicates the maximum load that can be supplied from BLTS with all
transformers in service. The “N-1” rating on the chart is the load that can be supplied from
BLTS with one 60 MVA transformer out of service.

The graph above shows that from 2012 onwards, the substation capacity will increase as a
result of the BLTS rebuild project under construction, which is due to be completed by 2012.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast is



                                                                                      Page 1 of 4
2010 Transmission Connection Planning Report                                       Risk Assessment: BLTS22 kV



expected to exceed the N-1 capability rating. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.




Comments on Energy at Risk

For a major outage of one transformer at BLTS 22 kV, there will be insufficient capacity at the
station to supply all demand at the 50th percentile temperature for about 23.8 hours in summer
2012 which will rise to 282 hrs in 2020. The energy at risk at the 50th percentile temperature
under N-1 conditions is estimated to be 40.0 MWh in 2012 and will rise to 899.4 MWh in 2020.
The estimated value to consumers of the 899.4 MWh of energy at risk is approximately $50.1
million (based on a value of customer reliability of $55,758/MWh). 1 In other words, at the 50th
percentile demand level, and in the absence of any other operational response that might be
taken to mitigate the impact of a forced outage, a major outage of one transformer at BLTS in
2020 would be anticipated to lead to involuntary supply interruptions that would cost consumers
approximately $50.1 million.

It is emphasised however, that the probability of a major outage of one of the two BLTS
220/22kV transformers occurring over the year is very low (0.217% per transformer). When the
energy at risk (899.4 MWh for 2020) is weighted by this low probability, the expected
unsupplied energy is estimated to be around 3.9 MWh. This expected unserved energy is
estimated to have a value to consumers of around $217,312 (based on a value of customer
reliability of $55,758/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each year.
Under more extreme summer temperature conditions (that is, at the 10th percentile level), the
energy at risk in 2020 is estimated to be 1459.1 MWh. The estimated value to consumers of

1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in
        accordance with the composition of the load at this terminal station.


                                                                                                       Page 2 of 4
2010 Transmission Connection Planning Report                         Risk Assessment: BLTS22 kV



this energy at risk in 2020 is approximately $81.4 million. The corresponding value of the
expected unserved energy is approximately $352,553.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the table
below.


                                                          MWh         Valued at consumer
                                                                       interruption cost
Energy at risk, at 50th percentile demand forecast        899.4           $50.1 million

Expected unserved energy at 50th percentile demand          3.9             $217,000

Energy at risk, at 10th percentile demand forecast      1459.1            $81.4 million

Expected unserved energy at 10th percentile demand          6.3             $353,000



Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Transfer loads from BLTS 22 to adjacent stations when extra capacity becomes available.

2. Demand reduction: There is an opportunity for voluntary demand reduction to contribute to
   a reduction in demand at the station during times of network constraint. The amount of
   potential demand reduction would be taken into consideration when determining the
   optimum timing of any network capacity augmentation.

3. Embedded generation.

Preferred option for alleviation of constraints

The preferred option for alleviation of future constraints is to transfer 22 kV load away to
adjacent zone substations when capacity is available.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                      Page 3 of 4
2010 Transmission Connection Planning Report                                                     Risk Assessment: BLTS22


Brooklyn Terminal Station
Detailed data: Magnitude and probability of loss of load

Distribution Businesses supplied by this               Powercor (97.5%) & Jemena (2.5%)
station:
                                                          MVA             2012           2013
Normal cyclic rating with all plant in service                             150            180        via 2 transformers (Summer peaking)
Summer N-1 Station Rating:                                                 74             90         [See Note 1 below for interpretation of
                                                                                                     N-1]
Winter N-1 Station Rating:                                                  74             90


Station: BLTS 22kV                                        2011             2012           2013          2014           2015            2016            2017            2018              2019            2020

50th percentile Summer Maximum Demand (MVA)                80.9            82.9           89.5          91.9           94.4            97.0             99.7           102.5            105.3            108.4
Summer % Overload [See Note 2 below]                       9.32           12.03            Nil          2.11           4.89             7.78           10.78           13.89            17.00            20.44
50th percentile Winter Maximum Demand (MVA)                70.5            75.1           77.0          83.2           85.4            87.7             90.1            92.6             95.1            97.9
Winter % Overload [See Note 2 below]                        Nil            1.49            Nil           Nil            Nil             Nil             0.11            2.89             5.67            8.78
Annual energy at risk (MWh) [See Note 3 below]             40.0           101.8            0.0           1.0            5.3             29.2            86.4           191.5            412.4            899.4
Annual hours at risk [See Note 4 below]                    23.8            41.0            0.0           1.0            4.5             17.3            33.3            66.0            137.3            282.0
Expected Annual Unserved Energy (MWh) [See
                                                           0.17            0.44           0.00          0.00           0.02             0.13            0.37            0.83             1.79            3.90
Note 5 below]

Expected Annual Unserved Energy valued at in
accordance with the value of customer reliability as
                                                          $9,656         $24,604           $0           $252          $1,291          $7,064          $20,865         $46,281          $99,633         $217,312
estimated in the December 2002 study
commissioned by VENCorp. [See Note 6 below]
                                                          $2,228,211      $5,677,853          $0          $58,171        $297,849     $1,630,195     $4,814,988     $10,680,128        $22,992,253    $50,148,871
Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy that would not be supplied in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating, if there is
    a major outage of a transformer (see Note 5 below), and no other mitigation action is taken.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                                        Page 4 of 4
2010 Transmission Connection Planning Report                                                         Risk Assessment: BTS 22 kV


BRUNSWICK TERMINAL STATION 22 kV (BTS 22 kV)

BTS 22 kV is a terminal station shared by Jemena Electricity Networks (58%) and CitiPower
(42%). It is located in an inner northern suburb of Melbourne, operating at 220/22 kV and
supplying areas including Brunswick, Fitzroy, Northcote, Fairfield, Essendon, Ascot Vale and
Moonee Ponds.

Magnitude, probability and impact of loss of load

BTS 22 kV is a summer critical station. Following completion of the station refurbishment by
SPI PowerNet in early 2007, BTS 22 kV has three 75 MVA transformers operating in parallel.

The graph below depicts the BTS 22 kV operational “N-1” rating 1 (for an outage of one
transformer) at ambient temperatures of 35°C and 40°C, and the 50th and 10th percentile
summer maximum demand forecasts.


                                             BTS 22kV Summer Peak Forecasts

                          (N-1) Rating @ 35 deg C
          150

                              (N-1) Rating @ 40 deg C
          140

                                                               10% Probability Demand Forecast
          130


          120
    MVA




          110


          100                                                                 50% Probability Demand Forecasts


           90

                                       Actuals             Forecasts
           80
                2006   2007     2008    2009     2010   2011   2012    2013     2014   2015   2016    2017   2018   2019   2020
                                                                       Year




The graph shows there is sufficient station capacity to supply all anticipated loads and that
no customers would be at risk if a forced transformer outage occurred at BTS 22 kV over the
forecast period. Accordingly, no capacity augmentation is planned at BTS 22 kV over the
next ten years.




1
           The station’s operational “N-1” rating will be confirmed by SPI Powernet.

                                                                                                                           Page 1 of 1
2010 Transmission Connection Planning Report                   Risk Assessment: BTS 66 kV



BRUNSWICK TERMINAL STATION 66 kV (BTS 66 kV)

BTS 66 kV is a proposed new 66 kV source of supply, to be established with
220/66 kV transformation, to reinforce the security of supply to the northern and inner
Central Business District areas, and to provide future supply to the nearby suburbs of
Brunswick, Brunswick West, Northcote, Carlton, Fitzroy and Collingwood.

Magnitude, probability and impact of loss of load

At present, the supply to the Central Business District relies heavily on West
Melbourne Terminal Station (WMTS) which supplies about 50% of the Central
Business District load.

Following the extremely hot summer in 2009, SPI PowerNet expressed concern
regarding the operating temperature of the WMTS 220/66 kV transformers. In order
to avoid operating the WMTS transformers at temperatures that would result in
accelerated aging, SPI PowerNet has reduced the WMTS Terminal Station summer
cyclic ratings by about 5.5% to 497 MVA at 35ºC ambient and about 10% to
463 MVA at 43ºC ambient. This would result in dramatically exacerbating the load at
risk at WMTS 66kV.

Based on the latest 50th percentile maximum demand forecasts, loading at WMTS
66 kV and WMTS 22 kV will exceed N-1 capacity by around 2012 and 2014
respectively (Refer to the Risk Assessment Reports for WMTS 66 kV and WMTS
22 kV).

The preferred option to address the emerging constraint at WMTS 22 kV as indicated
in the Risk Assessment Report for WMTS 22 kV is to upgrade a critical 22 kV zone
substation in the Central Business District to 66 kV, which would require additional
66 kV capacity from a terminal station source. The proposed BTS 66 kV facility could
gradually off-load WMTS 66 kV and WMTS 22 kV, and provide a new 66 kV point of
connection for Central Business District supply, thereby reducing the reliance on
WMTS.

As indicated in the Risk Assessment Report for RTS 66 kV that station is already
heavily loaded and extra capacity is required by around 2014. The proposed BTS
66 kV station is planned to off-load RTS 66 kV, and hence to remove the immediate
loading constraint at RTS 66 kV.

In summary, the objectives of establishing the new BTS 66 kV station are:

1. to provide a new 66 kV point of connection with additional terminal station
   capacity for the Central Business District supply, thereby reducing the reliance
   on CBD supply from WMTS;

2. to remove the loading constraint at both WMTS 66 kV and WMTS 22 kV;

3. to remove the loading constraint at RTS 66 kV; and

4. to reinforce the security of supply to the Central Business District by establishing
   strong “Normal Open” 66 kV subtransmission ties among the new BTS 66 kV,
   WMTS 66 kV and RTS 66 kV (Refer to the Risk Assessment Reports for WMTS
   66 kV and RTS 66 kV).




                                                                                 Page 1 of 2
2010 Transmission Connection Planning Report                                Risk Assessment: BTS 66 kV



It is expected that the new BTS 66 kV station will be summer critical. An embedded
generator in the order of about 250 MVA would help to defer the need for
establishing a new 66 kV point of supply.

Preferred network option(s) for alleviation of constraints

In May 2008, CitiPower undertook a Regulatory Test for the upgrade of BTS with
66 kV supply. The Regulatory Test was undertaken under the market benefits limb
of the National Electricity Rules (NER) to address the overall distribution loading
constraint in the Central Business District supply areas, and to alleviate the heavily
loaded West Melbourne Terminal Station. CitiPower’s application of the Regulatory
Test confirmed that establishment of the new BTS 66 kV supply source (with two 225
MVA 220/66 kV transformers) is the most cost-effective option for addressing the
network constraints.

Following its completion of the Regulatory Test, CitiPower published a Consultation
Report on 26 May 2006, recommending an upgrade of BTS with additional
220/66 kV transformation capacity to relieve constraints at West Melbourne terminal
station (WMTS 66 kV and WMTS 22 kV) that supply the northern and western inner
Central Business District and surrounding areas. As noted above, the upgrade will
also help alleviate constraints at the heavily loaded Richmond Terminal Station. No
submissions or proposals to establish non-network solutions were received in
response to that consultation paper. Accordingly the preliminary recommendation -
to establish a new 66 kV source of supply at BTS - has been adopted.

The Final Report on the proposed Brunswick Terminal Station was published on
NEMMCO’s website on 14 August 2008.

In 2010, the City of Moreland rejected the planning permit submitted by SPI
PowerNet. A new planning proposal is being prepared for Council approval. A new
Regulatory Test is to be undertaken in 2011 due to the expected increased cost of
establishing BTS. Subject to the outcomes of the Regulatory Test and planning
approval process, the revised date for the commissioning of BTS is 2014 1 . Any
further delays resulting from the planning process and increase in SPI PowerNet’s
project delivery lead times will be beyond the control of CitiPower.




1
        Subject to SPI PowerNet’s timely delivery of the necessary works.



                                                                                              Page 2 of 2
2010 Transmission Connection Planning Report                                                                Risk Assessment: CBTS


CRANBOURNE TERMINAL STATION (CBTS)

Magnitude, probability and impact of loss of load

Cranbourne terminal station (CBTS) was originally commissioned with two 150 MVA
220/66 kV transformers in 2005 to reinforce the security and reliability of supply for United
Energy Distribution and SPI Electricity customers in the area, and to off-load the critically
loaded terminal station at East Rowville (refer to the Risk Assessment Report for ERTS).
The geographic coverage of the area supplied by CBTS spans from Narre Warren in the
north to Clyde in the south, and from Pakenham in the east to Carrum and Frankston in the
west. The area has been amongst the fastest growing regions in Australia.

The summer peak demand at CBTS 66 kV has increased by almost 135 MW, equivalent to
an annual growth rate of 12.5%, between 2006 and 2010. The peak load on the station
reached 359.2 MW (378.6 MVA) in summer 2010. In order to supply the growing electricity
demand in the area, a third 150MVA 220/66 kV transformer was commissioned in 2009 for
summer 2009/10.

CBTS 66 kV is a summer peaking station. The graph below depicts the 10th and 50th
percentile summer maximum demand forecast together with the station’s expected
operational N rating (all transformers in service) and the N-1 rating at 35°C as well as 40°C
ambient temperature.

                                                           CBTS Summer Peak Forecasts
         650
                                                                                      10% PoE
                                                      Actual     Forecast
         600


         550


         500


         450                                                                         50% PoE
   MVA




         400          N Rating @ 35 deg C

         350
                      N Rating @ 40 deg C

         300


         250


         200          N -1 Rating @ 35 deg C

                      N -1 Rating @ 40 deg C
         150
               2006       2007    2008         2009    2010    2011   2012   2013   2014   2015   2016   2017   2018   2019     2020
                                                                             Year




The N rating on the chart indicates the maximum load that can be delivered from CBTS
66 kV with all transformers in service. Exceeding this level will initiate SPI PowerNet’s
automatic load shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.




                                                                                                                              Page 1 of 6
2010 Transmission Connection Planning Report                                                                                              Risk Assessment: CBTS




                                                       Annual Energy and Hours at Risk at CBTS (Single Contingency Only)

                                                   Hours at Risk (LH scale)          Energy at Risk MWh (LH scale)        Customer Value (RH scale)

                                  100,000                                                                                                             $38,000,000


                                   90,000                                                                                                             $34,200,000


                                   80,000                                                                                                             $30,400,000


                                   70,000                                                                                                             $26,600,000
    MWh at Risk / Hours at Risk




                                   60,000                                                                                                             $22,800,000


                                   50,000                                                                                                             $19,000,000


                                   40,000                                                                                                             $15,200,000


                                   30,000                                                                                                             $11,400,000


                                   20,000                                                                                                             $7,600,000


                                   10,000                                                                                                             $3,800,000


                                       0                                                                                                              $0
                                            2011         2012        2013     2014        2015          2016     2017   2018      2019        2020
                                                                                                 Year




Comments on Energy at Risk

For an outage of one 220/66kV transformer at CBTS, there will be insufficient capacity at the
station to supply all demand at the 50th percentile temperature for about 165 hours in 2014.
The energy at risk under N-1 conditions is estimated to be 7,484 MWh in 2014. The
estimated value to consumers of the 7,484 MWh of energy at risk is approximately $445
million (based on a value of customer reliability of $59,432/MWh) 1 . In other words, at the
50th percentile demand level, and in the absence of any other operational response that
might be taken to mitigate the impact of a forced outage, a major outage of one 220/66kV
transformer at CBTS for the entire duration of the summer of 2014 would be anticipated to
lead to involuntary supply interruptions that would cost consumers $445 million.

It is emphasised however, that the probability of a major outage of one of the transformers
occurring over the year is very low at about 1.0% per transformer per annum, whilst the
expected unavailability per transformer per annum is 0.217%. When the energy at risk
(7,484 MWh) is weighted by this low unavailability, the expected unserved energy is
estimated to be around 48.3 MWh. This expected unserved energy is estimated to have a
value to consumers of around $2.9 million (based on a value of customer reliability of
$59,432/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2014 is estimated to be 10,460 MWh. The estimated value to consumers of this
energy at risk in 2014 is approximately $622 million. The corresponding value of the
expected unserved energy is $4.0 million.

1
                                       The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
                                       in accordance with the composition of the load at this terminal station.


                                                                                                                                                           Page 2 of 6
2010 Transmission Connection Planning Report                             Risk Assessment: CBTS


These key statistics for the year 2014 under N-1 outage conditions are summarised in the
table below.

                                                            MWh         Valued at consumer
                                                                         interruption cost
Energy at risk, at 50th percentile demand forecast         7,484            $445 million

Expected unserved energy at 50th percentile demand          48.3             $2.9 million

Energy at risk, at 10th percentile demand forecast        10,460            $622 million

Expected unserved energy at 10th percentile demand          67.6             $4.0 million



If one of the 220/66 kV transformers at CBTS is taken off line during peak loading times and
the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by
SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at zone substation feeder level in
accordance with United Energy’s and SPI Electricity’s operational procedures after the
operation of the OSSCA scheme.

In the case of CBTS 66 kV supply at maximum demand, the Schedule of Priority Load
Shedding recommended by the Demand Reduction Committee, the OSSCA scheme would
shed about 150 MVA of load, affecting approximately 57,000 customers in 2011.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint.

1. Implement contingency plans to transfer load to adjacent terminal stations: Both SPI
   Electricity and United Energy Distribution have established and implemented the
   necessary plans that enable load transfers under contingency conditions via emergency
   66 kV ties to the adjacent terminal stations at East Rowville (ERTS 66 kV), Tyabb (TBTS
   66 kV) and Heatherton (HTS 66 kV). The emergency 66 kV ties can be in operation
   within 2 hours and have a combined capability to transfer up to 150 MVA of load.

2. Establish a new 220/66 kV terminal station: SPI Electricity expects that a new terminal
   station in the Pakenham area (with a site yet to be acquired) will be required in around 6
   years time to service load growth in the region. This development will help to off-load
   CBTS as well as addressing overloading problems on the existing 66 kV sub-
   transmission network from CBTS to the Pakenham area. SPI Electricity will carry out
   planning studies to assess whether this option is economic, and if so, to determine the
   optimal timing of any investment. An alternative would be to develop a new terminal
   station on a reserved site in North Pearcedale. The North Pearcedale site, however, is
   not located within the growth area and is considered unsuitable at this stage.

3. Install a 4th 220/66 kV transformer at Cranbourne Terminal Station: The site has
   provision for a 4th transformer and implementing this option is relatively straight forward,


2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre


                                                                                     Page 3 of 6
2010 Transmission Connection Planning Report                                           Risk Assessment: CBTS


    however it would require 66 kV lines to be re-arranged so that the station can operate
    with split 66 kV buses in order to maintain fault levels within acceptable limits.

4. Install two new 50 MVAr 66 kV capacitor banks: CBTS currently has no 66 kV capacitor
   banks and the station operates with a power factor around 0.94 lagging in summer.
   Installing two 50 MVAr 66 kV capacitor banks will help to reduce the net MVA supplied by
   transformers by approximately 20 MVA.

5. Demand Side Management: United Energy Distribution has developed a number of
   innovative network tariffs that encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and
   the subsequent change in load pattern and will be taken into consideration when
   determining the optimum timing for the capacity augmentation.

6. Embedded Generation: Embedded generation, in the order of 50 MW, connected to the
   CBTS 66 kV bus, will help to defer the need for augmentation by at least one year.

Preferred network option for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at CBTS, it is proposed to:

1. Install a fourth 150MVA 220/66kV transformer at CBTS.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at CBTS under critical loading conditions:

    •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

    •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
        impact on customers of any automatic load shedding that may take place; and

    •   subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
        metropolitan areas (refer Section 4.5), this spare transformer can be used to
        temporarily replace the failed transformer.

The capital cost of installing a fourth 150 MVA 220/66 kV transformer at CBTS is estimated
to be $15 million. The cost of establishing, operating and maintaining a new transformer
would be recovered from network users through network charges, over the life of the asset.
The estimated total annual cost of this network augmentation is approximately $1.5 million.
This cost provides a broad upper bound indication of the maximum network support payment
which may be available to embedded generators or customers to reduce forecast demand,
and to defer or avoid the transmission connection component of this augmentation. 4 Any
non-network solution that defers this augmentation for say 1-2 years, will not have as much
potential value (and contribution available from distributors) as a solution that eliminates or
defers the augmentation for, say, 10 years.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy. On the present 50th percentile
forecasts, as shown in the table, the customer value of expected unserved energy ($1.8

4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.


                                                                                                     Page 4 of 6
2010 Transmission Connection Planning Report                               Risk Assessment: CBTS


million) exceeds the annualised cost of the preferred option ($1.5 million) in 2013, hence, the
preferred option should be implemented by the end of 2012 so that additional capacity is
available during summer 2012/13. However, the typical implementation timeframe for this
type of augmentation may be up to three years. Therefore, the practically feasible
completion of the preferred option is likely to be the end of 2013. United Energy Distribution
will work closely with SPI PowerNet to ensure that any network-based solution to the
emerging constraint is delivered in the most timely possible manner.

Proponents of non-network alternatives to this augmentation should contact SPI Electricity or
United Energy as soon as possible, and in any event should provide a detailed proposal
(addressing the information requirements set out in Section 1.4 of this report) by no later than
31st March 2011. Submission of this detailed information by this date will ensure that
sufficient time is available to assess all options and to implement the preferred option, so that
an adequate level of supply reliability is maintained at all times. SPI Electricity and United
Energy envisage a decision on the augmentation option (including network and non-network
solutions) to be made shortly after this date.




                                                                                       Page 5 of 6
2010 Transmission Connection Planning Report                                            Risk Assessment: CBTS


CRANBOURNE TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                         United Energy Distribution (43.5%) and SPI Electricity (56.5%)
Station operational rating (N elements in service):                       548 MVA via 3 transformers (Summer peaking)
Summer N-1 Station Rating:                                                366 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                                411 MVA


Station: CBTS 66 kV                                           2011        2012        2013       2014        2015        2016        2017        2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                  396.6       438.7       470.0       494.7      520.9       551.4       582.7       613.0        648.4        686.0
Summer % Overload [See Note 2 below]                            9%        20%         29%         36%         43%        51%         60%          68%         78%          88%
  th
50 percentile Winter Maximum Demand (MVA)                    320.6       348.2       361.3       376.3      394.6       413.3       431.6       451.6        472.2        492.6
Winter % Overload [See Note 2 below]                            Nil         Nil         Nil         Nil        Nil         1%         5%          10%         15%          20%
Annual energy at risk (MWh) [See Note 3 below]                 347       2,186       4,700       7,484     11,337      17,281      25,725      39,150       62,716      94,879
Annual hours at risk [See Note 4 below]                          29         73         121         165        223         314         499         881        1,301        1,664
Expected Annual Unserved Energy (MWh) [See Note
                                                                2.2       14.1        30.4        48.3        73.2      111.6       166.1       252.8        405.0        612.7
5 below]
Expected Annual Unserved Energy value [See Note 6
                                                             $0.1M       $0.8M      $1.8M       $2.9M       $4.4M       $6.6M      $9.9M       $15.0M      $24.1M       $36.4M
below]

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                        Page 6 of 6
2010 Transmission Connection Planning Report                          Risk Assessment: DPTS



DEER PARK TERMINAL STATION (DPTS) 66 kV

Deer Park Terminal Station (DPTS) 66 kV is a proposed future terminal station located at the
corner of Christies Road and Riding Boundary Road in Deer Park. It is required to offload
both transformer groups at KTS by Nov 2016 to avoid excessive load at risk and load
exceeding the ‘N’ ratings in summer 2016/17. It is planned to transfer SU zone substation
from KTS (B1,2,5) transformer group and MLN zone substation from KTS (B3,4) group to
the new DPTS. Also by 2017 there will be significant load at risk on the SBY/MLN 66kV
loops and transferring MLN to DPTS will defer augmentation in this area.

BMH zone substation may also be connected to DPTS to alleviate load at risk at ATS/BLTS,
improve supply to BMH and reduce environmental impact by reducing the number of lines
supplying SU. DPTS will also supply a nearby proposed new zone substation, Truganina
(TNA) which is required by 2017-18 to offload nearby SU zone substation and augment
supply to the fast-growing western suburbs of Melbourne.

The creation of a new zone substation TNA will also enable the transfer of load from
Laverton and Laverton North zone substations which are supplied from ATS West and
ATS/BLTS terminal stations respectively, further deferring the need for augmentation at
these stations.

DPTS is planned to be constructed with two 150 MVA 220/66kV transformers. The initial
load is forecast to be as high as 220 MVA if BMH is connected in November 2016. Demand
at DPTS would then increase to 276 MVA by 2018 after TNA is connected. A third
220/66 kV 150 MVA transformer at DPTS may be economically justified by 2019.

DPTS will connect into the existing KTS-GTS 220 kV lines which presently pass through the
site.




                                                                                  Page 1 of 1
2010 Transmission Connection Planning Report                           Risk Assessment: ERTS


EAST ROWVILLE TERMINAL STATION (ERTS)

Magnitude, probability and impact of loss of load

ERTS consists of three 150 MVA 220/66 kV transformers, and is the main source of supply
for most of the outer south-eastern corridor of Melbourne. The geographic coverage of the
area supplied by this station spans from Scoresby in the north to Skye in the south, and from
Belgrave in the east to Mulgrave in the west. The electricity supply network for this large
region is split between United Energy Distribution (UED) and SPI Electricity (SPIE).

ERTS has been one of the most highly utilised terminal stations in Victoria until 2005. Major
works completed over the last ten years have included:

•   upgrading of 66 kV transformer circuit breakers at ERTS in 2000;

•   sub-transmission line works in 2001 by United Energy Distribution to transfer about
    60 MVA of load away from ERTS to a lightly loaded terminal station at Tyabb (TBTS)
    prior to summer 2002; and

•   establishment of a new terminal station at Cranbourne (CBTS) in 2005 to off-load ERTS
    prior to summer 2006.

The summer peak demand at ERTS 66 kV has increased by almost 111 MW, equivalent to
an annual growth rate of 8.6%, between 2006 and 2009. The peak load on the station
reached 504.9 MW (523.4 MVA) in summer 2009. The recorded peak demand in summer
2010 was 482.6 MW (507.5 MVA), which was approximately 22 MW lower than the 2009
summer peak. This is mainly attributed to the comparatively mild weather conditions
observed during summer 2010.

The risk of supply interruption at ERTS 66 kV, for a single contingency event was assessed
as being unacceptable in 2007, and the establishment of a fourth 150 MVA 220/66 kV
transformer at ERTS 66 kV was identified as the most economic network solution by both
SPI Electricity and United Energy Distribution. The new fourth transformer is planned to be
commissioned by December 2011 for summer 2011/12.

ERTS 66 kV is a summer peaking station. The graph below depicts the 10th and 50th
percentile summer maximum demand forecast together with the station’s expected
operational N rating (all transformers in service) and the N-1 rating at 35°C as well as 40°C
ambient temperature.




                                                                                   Page 1 of 6
2010 Transmission Connection Planning Report                                                                                                 Risk Assessment: ERTS




                                                                                 ERTS Summer Peak Forecasts
                                850.0


                                800.0


                                750.0
                                                                                                                                                    10% PoE
                                            66kV transformer CBs
                                700.0          upgrade in 2000

                                                                                                    Actual           Forecast
                                650.0
                                                           (N) Rating @ 35 deg C
 MVA




                                600.0
                                                           (N) Rating @ 40 deg C
                                                                                Off-load to CBTS
                                                                                     in 2005
                                550.0

                                                                                                                                       50% PoE
                                500.0


                                450.0     Off-load to
                                         TBTS in 2001          (N-1) Rating @ 35 deg C

                                400.0
                                                               (N-1) Rating @ 40 deg C

                                350.0
                                        2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
                                                                                                             Year



The N rating on the chart indicates the maximum load that can be supplied from ERTS with
all transformers in service. Exceeding this level will initiate SPI PowerNet’s automatic load
shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.



                                                        Annual Energy and Hours at Risk at ERTS (Single Contingency Only)

                                                  Hours at Risk (LH scale)               Energy at Risk MWh (LH scale)           Customer Value (RH scale)

                                7,000                                                                                                                         $3,000,000


                                6,300                                                                                                                         $2,700,000


                                5,600                                                                                                                         $2,400,000


                                4,900                                                                                                                         $2,100,000
  MWh at Risk / Hours at Risk




                                4,200                                                                                                                         $1,800,000


                                3,500                                                                                                                         $1,500,000


                                2,800                                                                                                                         $1,200,000


                                2,100                                                                                                                         $900,000


                                1,400                                                                                                                         $600,000


                                  700                                                                                                                         $300,000


                                    0                                                                                                                         $0
                                           2011         2012        2013        2014         2015            2016        2017   2018        2019       2020
                                                                                                    Year




                                                                                                                                                              Page 2 of 6
2010 Transmission Connection Planning Report                                         Risk Assessment: ERTS


Comments on Energy at Risk

After the installation of the fourth transformer, for an outage of one transformer at ERTS,
there will be insufficient capacity at the station to supply all demand at the 50th percentile
temperature for about 17 hours in 2020. The energy at risk at the 50th percentile temperature
under N-1 conditions is estimated to be 325 MWh in 2020. The estimated value to
consumers of the 325 MWh of energy at risk is approximately $21.7 million (based on a
value of customer reliability of $66,762/MWh) 1 . In other words, at the 50th percentile demand
level, and in the absence of any other operational response that might be taken to mitigate
the impact of a forced outage, a major outage of one transformer at ERTS in 2020 would be
anticipated to lead to involuntary supply interruptions that would cost consumers $21.7
million.

It is emphasised however, that the probability of a major outage of one of the four
transformers occurring over the year is very low at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (325 MWh) is weighted by this low unavailability, the expected unserved energy is
estimated to be around 2.8 MWh. This expected unserved energy is estimated to have a
value to consumers of around $187,000 (based on a value of customer reliability of
$66,762/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2020 is estimated to be 738 MWh. The estimated value to consumers of this
energy at risk in 2020 is approximately $49.3 million. The corresponding value of the
expected unserved energy is approximately $424,000.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                                      MWh           Valued at consumer
                                                                                     interruption cost
Energy at risk, at 50th percentile demand forecast                      325               $21.7 million

Expected unserved energy at 50th percentile demand                      2.8                $187,000

Energy at risk, at 10th percentile demand forecast                      738               $49.3 million

Expected unserved energy at 10th percentile demand                      6.3                $424,000



If one of the 220/66 kV transformers at ERTS is taken off line during peak loading times and
the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by
SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at zone substation feeder level in


1
        The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
        in accordance with the composition of the load at this terminal station.
2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operation Centre


                                                                                                    Page 3 of 6
2010 Transmission Connection Planning Report                             Risk Assessment: ERTS


accordance with United Energy’s and SPI Electricity’s operational procedures after the
operation of the OSSCA scheme.

In the case of ERTS supply at maximum loading periods, and based on the Schedule of
Priority Load Shedding recommended by the Demand Reduction Committee, the OSSCA
scheme would shed about 100 MVA of load, affecting approximately 35,000 SPIE customers
followed by an additional 120 MVA of load shedding, if required, affecting approximately
34,100 UED customers.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement contingency plans to transfer load to adjacent terminal stations. Both United
   Energy Distribution and SPI Electricity have established and implemented the necessary
   infrastructure and plans that enable load transfers under contingency conditions via
   emergency 66 kV subtransmission ties to Springvale Terminal Station and Ringwood
   Terminal Station, respectively. The emergency 66 kV tie to Ringwood Terminal Station
   can be in operation within 2 hours and has the capacity to transfer up to 60 MVA of load.
   The emergency 66 kV tie to Springvale Terminal Station has the capacity to transfer up to
   65 MVA of load. A further 20 MVA can be transferred using the 22 kV distribution
   network.

2. Transfer Hampton Park (HPK) zone substation from ERTS to Cranbourne Terminal
   Station (CBTS). This would require 15 kilometres of new 66 kV lines between CBTS and
   HPK as well as new 66 kV line circuit breakers at CBTS. (Note that this option would not
   be valid unless CBTS is augmented with a 4th transformer – refer to the risk assessment
   report for CBTS.)

3. Establish a new 220/66 kV terminal station. A terminal station site in Dandenong has
   been reserved for possible future electrical infrastructure development to meet
   customers’ needs in the area.

4. Demand Side Management. United Energy Distribution has developed a number of
   innovative network tariffs that encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and
   the subsequent change in load pattern, and will be taken into consideration when
   determining the optimum timing for the capacity augmentation.

5. Embedded Generation. Embedded generation, in the order of 40 MVA, connected to the
   ERTS 66 kV bus, will help to defer the need for augmentation by at least one year.

Preferred network option for alleviation of constraints

1. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at ERTS under critical loading conditions:

    •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

    •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
        impact on customers of any automatic load shedding that may take place; and




                                                                                      Page 4 of 6
2010 Transmission Connection Planning Report                         Risk Assessment: ERTS


    •   subject to the availability of the SPI PowerNet’s spare 220/66 kV transformer for
        metropolitan areas (refer Section 4.5), this spare transformer can be used to
        temporarily replace the failed transformer.

2. In the absence of any commitment by interested parties to offer network support services
   by installing local generation or through demand side management initiatives that would
   reduce load at ERTS, it is proposed to off-load ERTS by transferring HPK onto CBTS.
   On the present forecasts this is not likely to be required within the ten year planning
   horizon.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                 Page 5 of 6
2010 Transmission Connection Planning Report                                           Risk Assessment: ERTS


EAST ROWVILLE TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                           United Energy Distribution (66.8%) and SPI Electricity (33.2%)
Station operational rating (N elements in service):                         623 MVA via 3 transformers (Summer peaking)
Summer N-1 Station Rating:                                                  415 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                                  465 MVA
Normal cyclic rating with all plant in service after Nov 2011:              830 MVA via 4 transformers (Summer peaking)
Summer N-1 Station Rating after Nov 2011:                                   623 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating after Nov 2011:                                   698 MVA


Station: ERTS 66kV                                               2011          2012       2013      2014         2015       2016      2017       2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                     530.7         531.4      554.3      573.7       583.6      601.0      618.2     631.4        650.1        668.6
Summer % Overload [See Note 2 below]                             28%           28%         Nil        Nil         Nil        Nil        Nil       1%           4%           7%
50th percentile Winter Maximum Demand (MVA)                     406.5         400.6      401.6      403.3       407.0      415.8      422.0     427.8        434.1        440.4
Winter % Overload [See Note 2 below]                               Nil          Nil        Nil        Nil         Nil        Nil        Nil       Nil           Nil          Nil
Annual energy at risk (MWh) [See Note 3 below]                  6,443             0          0          0           0          0          0         9          118          325
Annual hours at risk [See Note 4 below]                           191             0          0          0           0          0          0         4            9           17
Expected Annual Unserved Energy (MWh) [See Note 5
                                                                 41.6            0.0        0.0       0.0          0.0        0.0       0.0        0.1          1.0         2.8
below]
Expected Annual Unserved Energy value [See Note 6
                                                              $2,778k             $k        $k         $k           $k        $k         $k    $5.23k         $68k       $187k
below]

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                        Page 6 of 6
2010 Transmission Connection Planning Report                                                    Risk Assessment: FBTS

FISHERMAN’S BEND TERMINAL STATION 66 kV (FBTS 66 kV)

FBTS 66 kV is a terminal station shared by both CitiPower (currently 91%) and Powercor. It
is a summer critical station consisting of three 150 MVA 220/66 kV transformers supplying
the Docklands areas and an area south-west of the City of Melbourne bounded by the Yarra
River in the north and west, St Kilda/Queen’s Roads in the east and Hobsons Bay in the
south. The main supply areas include Docklands and Southbank of the Central Business
District planning areas, Port Melbourne, Fisherman’s Bend, Albert Park, Middle Park and St
Kilda West.

Magnitude, probability and impact of loss of load

To facilitate voltage control on the main transmission network in the Melbourne metropolitan
area, a 125 MVA synchronous compensator has been installed at FBTS. Given the high
total fault current contribution from the synchronous compensator, together with the fault
current contribution of existing embedded generators (totalling 17 MW of generating
capacity) under earth fault conditions, one of the three 220/66 kV transformers at FBTS is
operating on “Normal Open Auto-close” duty. Under this arrangement, one transformer
operates on hot stand-by and it can be automatically switched into operation if there is a
forced outage of any one of the two normal running transformers. This arrangement is
required to maintain the 66 kV fault level to within the terminal station fault rating. With this
transformer operating arrangement, the N rating is approximately equal to the N-1 rating (i.e.
equal to the capacity of two transformers), thus imposing a restriction that the terminal station
should not be loaded beyond the reduced N capacity of two transformers at any time.

The graph below depicts the 10th and 50th percentile maximum demand forecasts during the
summer periods over the next ten years, together with the station’s operational N and N-1
ratings. The forecast demand includes the effects of any future load transfer works that have
been committed.

                                  FBTS 66kV Summer Peak Forecasts
       500


       450
                                                             10% Probability Demand Forecasts
       400
                    N Rating @ 35 deg C
       350
                    N-1 Rating @ 35 deg C
 MVA




       300


       250
                                                                          50% Probability Demand Forecasts
       200
                                          Actuals           Forecasts
       150


       100
             2004   2006         2008               2010    2012         2014         2016         2018         2020
                                                           Year


The graph shows that there would be insufficient capacity at FBTS 66 kV to supply the
forecast 10th percentile and 50th percentile demands by around 2017 and 2018 respectively.
Action will be required from around 2017/18 to minimise the load at risk under N and N-1
conditions.


                                                                                                          Page 1 of 5
2010 Transmission Connection Planning Report                                                           Risk Assessment: FBTS

The bar chart below depicts the energy at risk (under normal system conditions with one
transformer on “Normal Open Auto-close” duty) for the 50th percentile demand forecast, and
the hours per year that the 50th percentile demand forecast is expected to exceed the rated
capacity under both N and N-1 conditions. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.


                                                     Annual Energy and Hour at Risk and
                                                   Expected Customer Value at FBTS 66KV


                                    Hour at Risk      MWh at Risk      Consumer expected $ value (RH scale)
               MWH & Hour at Risk




                                    200                                                                $16,000,000

                                    150                                                                $12,000,000

                                    100                                                                $8,000,000

                                     50                                                                $4,000,000

                                       0                                                               $0
                                           2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

                                                                    Year



Comments on Energy at Risk

With the existing transformer operating arrangement at FBTS, it is expected that by around
2019, there will be insufficient capacity to supply all demand at the 50th percentile
temperature under N and N-1 conditions. Under these operating arrangements, the
expected unserved energy is equal to the energy at risk, whenever loading exceeds the
capacity of two transformers.

By 2019, the energy at risk and the expected unserved energy under N and N-1 conditions is
about 19.4 MWh at the 50th percentile demand forecast. Under these conditions, there would
be insufficient capacity to meet demand for about 4.5 hours in that year. The estimated
value to consumers of this energy at risk in 2019 is approximately $1.8 million (at a value of
customer reliability of $91,578 per MWh). 1 In other words, at the 50th percentile demand
level, and in the absence of any other operational response that might be taken to mitigate
the impact of a forced outage, the existing load forecast for 2019 implies a level of
involuntary supply interruption that would cost consumers approximately $1.8 million.

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2019 is estimated to be 314.9 MWh. The estimated value to
consumers of this energy at risk in 2019 is approximately $28.8 million.

These key statistics for the year 2019 under both N and N-1 conditions are summarised in
the table below.



1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
        in accordance with the composition of the load at this terminal station.



                                                                                                              Page 2 of 5
2010 Transmission Connection Planning Report                                Risk Assessment: FBTS



                                                              MWh         Valued at consumer
                                                                           interruption cost

Energy at risk, at 50 percentile demand forecast              19.4             $1.8 million

Expected unserved energy at 50 percentile demand              19.4             $1.8 million

Energy at risk, at 10 percentile demand forecast             314.9            $28.8 million

Expected unserved energy at 10th percentile demand           314.9            $28.8 million



If the total station load exceeds the N and N-1 station ratings, the OSSCA 2 load shedding
scheme which is operated by SP AusNet’s NOC 3 will act swiftly to reduce the load in blocks
to within safe loading limits. Any load reductions that are in excess of the minimum amount
required to limit load to the rated capability of the station would be restored after the
operation of the OSSCA scheme, at zone substation feeder level in accordance with
CitiPower’s and Powercor’s operational procedures.

In the case of FBTS 66 kV supply at maximum loading periods, and based on the existing
Schedule of Priority Load Shedding recommended by the Demand Reduction Committee,
the OSSCA scheme would shed about 26 MW of load under 50th percentile loading
conditions, affecting approximately 3,900 customers, up to 2019. After 2019, the load
shedding could impact significantly more customers if no action is taken to reduce the load at
risk.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Contingency plans could be put in place to transfer load to the adjacent terminal stations
   via the 11 kV distribution networks under transformer outage conditions. This option can
   defer major capital augmentation works until after the current ten-year planning period,
   but it requires the following work to be carried out to mitigate the risk of supply
   interruption and/or to alleviate the emerging constraint in the meantime:

        •   Increase the N rating to the normal three-transformer capacity level of about
            520 MVA (i.e. with all the three transformers operating on load) such that the
            station could be loaded up to beyond the N-1 rating under normal conditions.

            The N rating could be increased to the normal three-transformer capacity level, to
            connect the ‘hot standby’ transformer by removing the “Normal Open Auto-close”
            duty on the 66 kV transformer circuit breaker and implementing a “Normal Open
            Auto-close” facility on a 66 kV bus tie circuit breaker instead of on the transformer,
            for 66 kV fault level control. (Under these arrangements, the normal open bus tie
            circuit breaker will be automatically closed upon loss of any one of the three
            transformers). The total budget cost of these works is estimated to be in the order
            of $450,000.


2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operation Centre.



                                                                                   Page 3 of 5
2010 Transmission Connection Planning Report                                            Risk Assessment: FBTS

2. Installation of a fourth 150 MVA 220/66 kV transformer is a longer term option to address
   the emerging constraint at FBTS. However, this still requires the fault level reduction
   work described in Option 1 to be completed before the option is feasible.

3. Embedded generation in the order of 100 MVA, will help to defer the need for
   augmentation.

Preferred option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at FBTS 66 kV, or any other identified better network solutions, it is proposed to
increase the station N rating to the normal three-transformer capacity, to defer any major
capital augmentation works until after the current ten-year planning period by:

1. Operating all three existing transformers for the period prior to 2018/19 summer by
   implementing a “Normal Open Auto-close” facility on a 66 kV bus tie circuit breaker
   instead of on the transformer for 66 kV fault level control.

2. Implementing the following measures to cater for an unplanned outage of one
   transformer at FBTS 66 kV under critical loading conditions:

    •   Maintain contingency plans to transfer load via HV distribution networks to the
        adjacent terminal stations;

    •   Fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
        impact on customers of any load shedding that may take place; and

    •   Subject to the availability of the SP AusNet spare 220/66 kV transformer for
        metropolitan areas (refer Section 4.5), this spare transformer can be used to
        temporarily replace the failed transformer, and so minimise the transformer outage
        period.

The estimated total terminal station capital cost associated with this option is approximately
$450,000. The estimated total annual cost of this network augmentation is approximately
$45,000. This cost provides a broad upper bound indication of the maximum network
support payment which may be available 4 to embedded generators or customers to reduce
forecast demand, and to defer or avoid the transmission connection component of this
augmentation. Any non-network solution that defers this augmentation for say 1-2 years, will
not have as much potential value (and contribution available from distributors) as a solution
that eliminates or defers the augmentation for, say, 10 years. Sections 1.4 and 1.5 of this
report provide further background information to proponents of non-network solutions to
emerging constraints.

Any non-network proposal must be submitted with detailed plans to CitiPower for
consideration no later than June 2013. This will ensure that sufficient time is available to
implement the most cost-effective measure(s) to manage the risk of supply interruption, and
to maintain a satisfactory level of supply reliability. The table on the following page provides
more detailed data on the station rating, demand forecasts, energy at risk and expected
unserved energy.

4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.



                                                                                                Page 4 of 5
2010 Transmission Connection Planning Report                                                Risk Assessment: FBTS


     FISHERMAN’S BEND TERMINAL STATION 66 kV
     Detailed data: Magnitude and probability of loss of load
     Distribution Businesses supplied by this station:                CitiPower (Currently 91%); Powercor (currently 9%)
     Station operational rating (N elements in service):              358 MVA via 3 transformers with one transformer on "Normal Open Auto-close" duty [Note 7]
                                                                      (Summer peaking)
     Summer N-1 Station Rating:                                       309.3 MW (346.2 MVA) [See Note 1 below for interpretation of N-1]
     Winter N-1 Station Rating:                                       355.8 MW (390.0 MVA)


Station: FBTS 66kV
                                                               2011      2012       2013       2014        2015         2016       2017       2018        2019        2020
50th percentile Summer Maximum Demand (MVA)                    251.2     263.8      276.1      291.0       304.7        318.8      333.1      347.0       361.1       375.4
Summer % Overload [See Note 2 below]                            Nil       Nil        Nil        Nil         Nil          Nil        Nil       0.2%        4.3%        8.4%
50th percentile Winter Maximum Demand (MVA)                    209.1     219.6      230.7      244.6       257.6        270.8      284.2      297.3       310.6       324.4
Winter % Overload [See Note 2 below]                            Nil       Nil        Nil        Nil         Nil          Nil        Nil        Nil          Nil         Nil
Annual Energy at Risk (MWh) [See Note 3 below]                  0.0       0.0        0.0        0.0         0.0          0.0        0.0        0.3         19.4       157.8
Annual Hours at Risk [See Note 4 below]                         0.0       0.0        0.0        0.0         0.0          0.0        0.0        0.2         4.5         21.3
Expected Annual Unserved Energy (MWh) [See
                                                                0.0        0.0        0.0        0.0        0.0          0.0         0.0       0.3        19.4        157.8
Note 5 below]

Expected Annual Unserved Energy value [See
                                                                $0.        $0         $0         $0          $0          $0          $0      $0.03M       $1.8M       $14.5M
Note 6 below]


     Notes:
1.    “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.    This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3.    “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
                                                                                           th
4.    “Annual hours per year at risk” is the number of hours in a year during which the 50 percentile demand forecast exceeds the N-1 capability rating.
5.    Because of the “Normal Open Auto-close” duty on one transformer at FBTS, “Expected annual unserved energy” is equal to the “annual energy at risk”.
6.    The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.
7.    The N and N-1 ratings are approximately equal due to the restriction of “Normal Open Auto-close” transformer duty. The N rating will be increased to about 520MVA when the
      restriction is removed..




                                                                                                   Page 5 of 5
2010 Transmission Connection Planning Report                          Risk Assessment: FTS


FRANKSTON TERMINAL STATION (FTS)

Magnitude, probability and impact of loss of load

FTS is a 66 kV switching station. Over the last ten years, the station has seen two major
changes in terms of both 66 kV incoming supply arrangements and the geographic area
supplied from the station, as described below:

1. A major project initiated by United Energy Distribution (UED) in 2001 has changed the
   coverage of the terminal station in the region to enable the spare capacity at Tyabb
   terminal station (TBTS) to be utilised. This resulted in FTS demand being reduced to
   below its N-1 rating in summer 2002.

2. With the establishment of a new terminal station at Cranbourne (CBTS) in 2005, FTS,
   originally supplied from East Rowville terminal station (ERTS), was transferred to
   Cranbourne terminal station (CBTS) in May 2005. The station is now supplied via three
   66 kV supply routes.

In addition to the above, UED upgraded its existing CBTS-CRM 66 kV line in 2009. This
increased the summer thermal rating of the line from 930 A to 1125 A at 35ºC.

Arrangements relating to the ownership of assets supplying FTS, as well as the ratings of
those assets are listed in the table below.


66kV Supply Route to FTS           Thermal Rating @ 35°C             Ownership

CBTS-FTS #1                                    825 Amp     Transmission connection asset
                                                           owned by SPI PowerNet

CBTS-FTS #2                                    825 Amp     Transmission connection asset
                                                           owned by SPI PowerNet

CBTS-CRM-(FTN/LWN)-FTS                     1125 Amp        Distribution system assets
                                                           owned by United Energy




The various 66 kV supply routes and ownership arrangements mean that the risk
assessment for FTS is more complicated than for other terminal stations. As far as
transmission connection assets are concerned, load flow studies indicate that N-1 rating of
FTS corresponds to the outage of CBTS-CRM 66 kV line and is limited by the thermal rating
of CBTS-FTS #1 and CBTS-FTS #2 66 kV lines.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational N-1 rating at 35°C as well as 40°C ambient
temperature.




                                                                               Page 1 of 5
2010 Transmission Connection Planning Report                                                                                                                 Risk Assessment: FTS



                                                                                          FTS Summer Peak Forecats
                                220.0
                                                               N-1 rating of connection                                                          10% PoE
                                200.0                             assets at 35 deg C


                                180.0


                                160.0
                                                                                                                                                                    N-1 rating of connection
                                                                                                                                                                       assets at 40 deg C
                                140.0

                                                                                                                               50% PoE
                                120.0
 MVA




                                100.0


                                 80.0


                                 60.0


                                 40.0
                                                                                                            Actual           Forecast
                                 20.0


                                    0.0
                                          2001   2002   2003    2004    2005   2006    2007   2008    2009     2010     2011    2012    2013   2014   2015   2016   2017   2018   2019   2020
                                                                                                                     Year


The bar chart below depicts the energy at risk for the 50th percentile demand forecast, and
the hours per year that the 50th percentile demand forecast is expected to exceed the N-1
capability rating. The line graph shows the value to consumers of the expected unserved
energy in each year, for the 50th percentile demand forecast.


                                                          Annual Energy and Hours at Risk at FTS (Single Contingency Only)

                                                    Hours at Risk (LH scale)                  Energy at Risk MWh (LH scale)                      Customer Value (RH scale)

                                3                                                                                                                                                        $300
  MWh at Risk / Hours at Risk




                                2                                                                                                                                                        $200




                                1                                                                                                                                                        $100




                                0                                                                                                                                                        $0
                                          2011          2012           2013           2014           2015             2016          2017          2018          2019          2020
                                                                                                             Year



Comments on Energy at Risk

For loss of CBTS-CRM 66 kV line, there will be insufficient capacity at the station to supply
all demand at the 50th percentile probability of exceedance for about an hour in 2020. The
energy at risk under N-1 conditions is estimated at 1,630 kWh in summer 2020. The
estimated value to consumers of the 1,630 kWh of energy at risk is approximately $109,000


                                                                                                                                                                            Page 2 of 5
2010 Transmission Connection Planning Report                                         Risk Assessment: FTS


(based on a value of customer reliability of $67,191/MWh) 1 . In other words, at the 50th
percentile demand level, and in the absence of any other operational response that might be
taken to mitigate the impact of a forced outage, loss of the CBTS-CRM 66 kV line in 2020
would be anticipated to lead to involuntary supply interruptions that would cost consumers
$109,000.

It is emphasised however, that the expected unavailability of CBTS-CRM 66 kV line,
estimated to be 0.245%, is very low, as derived in table below.

                CBTS-CRM 66kV Lines                                             Reliability Data

Line length                                                      L = 12.8 km

Failure rate (sustained fault) per annum                         F = 7 failures per 100km

Mean duration of outage (sustained fault) per annum              T = 24 hours

Expected unavailability of the line per year                     T/ (T+24x365/(F x L)) = 0.245%



When the energy at risk (1,630 kWh in 2020) is weighted by this low unavailability, the
expected unserved energy is estimated to be around 4.0 kWh. This expected unserved
energy is estimated to have a value to consumers of around $270 (based on a value of
customer reliability of $67,191/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2020 is estimated to be 48,140 kWh. The estimated value to consumers of this
energy at risk in 2020 is approximately $3.2 million. The corresponding value of the
expected unserved energy is around $7,900.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.
                                                         kWh        Valued at consumer
                                                                      interruption cost
Energy at risk, at 50th percentile demand forecast                     1,630                $109,000

Expected unserved energy at 50th percentile demand                          4                  $270

Energy at risk, at 10th percentile demand forecast                    48,140               $3,234,000

Expected unserved energy at 10th percentile demand                       120                  $7,900


Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement a contingency plan to transfer load to adjacent terminal stations. United
   Energy Distribution has established and implemented the necessary plans that enable


1
        The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
        in accordance with the composition of the load at this terminal station.


                                                                                                Page 3 of 5
2010 Transmission Connection Planning Report                                          Risk Assessment: FTS


    load transfers under contingency conditions, via both 66 kV subtransmission and 22 kV
    distribution networks.

2. Upgrade CBTS-FTS #1 and CBTS-FTS #2 66 kV circuits.

3. Demand Side Management: United Energy Distribution has developed a number of
   innovative network tariffs that encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and
   the subsequent change in load pattern, and will be taken into consideration when
   determining the optimum timing for any future capacity augmentation.

4. Embedded generation, in the order of 10 MVA, connected to the network supplied by
   FTS 66 kV bus, will help to defer the need for augmentation by one year.

Preferred network option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at FTS, it is proposed to:

1. Upgrade CBTS-FTS #1 and CBTS-FTS #2 66kV circuits; and

2. Maintain contingency plans to transfer load quickly to adjacent terminal stations.

On the present forecasts upgrading of CBTS-FTS #1 and CBTS-FTS #2 circuits is not likely
to be required within the ten year planning horizon. The capital cost of upgrading both
circuits is estimated to be $800,000. The estimated total annual cost of this network
augmentation is approximately $80,000. This cost provides a broad upper bound indication
of the maximum network support payment which may be available to embedded generators
or customers to reduce forecast demand, and to defer or avoid the transmission connection
component of this augmentation. 2 Any non-network solution that defers this augmentation
for say 1-2 years, will not have as much potential value (and contribution available from
distributors) as a solution that eliminates or defers the augmentation for, say, 10 years.
Sections 1.4 and 1.5 of this report provide further background information to proponents of
non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




2
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria..


                                                                                                Page 4 of 5
2010 Transmission Connection Planning Report                                           Risk Assessment: FTS


FRANKSTON TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                United Energy Distribution (100%)
Station operational rating (N elements in service):              236 MVA
Summer N-1 Station Rating:                                       189 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       201 MVA


Station: FTS 66 kV                                            2011        2012        2013       2014        2015        2016        2017        2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                  156.6       159.5      164.5       168.6       169.8       174.2      178.3        181.1       185.5        189.8
Summer % Overload [See Note 2 below]                            Nil         Nil         Nil        Nil         Nil         Nil         Nil         Nil          Nil         1%
50th percentile Winter Maximum Demand (MVA)                  129.0       131.2      131.3       131.6       132.4       135.8      138.0        139.9       142.2        144.4
Winter % Overload [See Note 2 below]                            Nil         Nil         Nil        Nil         Nil         Nil         Nil         Nil          Nil         Nil
Annual energy at risk (MWh) [See Note 3 below]                  0.0        0.0         0.0         0.0         0.0        0.0         0.0          0.0         0.0          1.6
Annual hours at risk [See Note 4 below]                         0.0        0.0         0.0         0.0         0.0        0.0         0.0          0.0         0.0          1.0
Expected annual unserved energy (kWh) [See Note 5
below]                                                          0.0        0.0         0.0         0.0         0.0        0.0         0.0          0.0         0.0          4.0

Expected Annual Unserved Energy value [See Note 6
below]                                                          $0          $0          $0          $0         $0          $0          $0          $0           $0        $268


Notes:
1. “N-1” means station output capability rating for outage of CBTS-CRM 66kV line. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of being in state N-1 due to the outage of CBTS-CRM 66kV line.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                      Page 5 of 5
2010 Transmission Connection Planning Report                                                                             Risk Assessment: GNTS


GLENROWAN TERMINAL STATION 66 kV (GNTS 66 kV)

At GNTS, there is one 125 MVA three phase transformer and one 110 MVA transformer
composed of six single phase 55 MVA units. The station is the main source of supply for a
major part of north eastern Victoria. The geographic coverage of the station’s supply area
includes Wangaratta in the north; to Euroa in the south; to Mansfield and Mt Buller in the
east; and Benalla more centrally.

Magnitude, probability and impact of loss of load

GNTS is a winter peaking station and growth in winter peak demand at GNTS 66 kV has
averaged around 1 MW (1%) per annum over the last 5 years. The summer peak demand
growth has also averaged around 1 MW (1%) per annum over the last 5 years. The growth
is forecast to continue at this level for the next few years. The peak load on the station
reached 116 MW (119 MVA) in winter 2007 and 106 MW (115 MVA) in summer 2008/9. The
station demand in summer 2009/2010 was 103 MW (105 MVA with 22.7 MVAr capacitor
bank in service). As explained in further detail below, all of the load at risk at GNTS occurs
during the summer maximum demand period, even though the peak demand occurs in
winter.

With the forecast demand growth rates, GNTS 66 kV is not expected to reach its “N-1” winter
station rating during the current planning horizon until 2020.

In the summer, with an assumed ambient temperature of 35 degrees C, the rating of the
transformers is lower than the winter (5 degrees C) rating. Thus, although the summer
loading is less than winter, all of the energy at risk at the station occurs during the summer
maximum demand period. The graph below depicts the 10th and 50th percentile summer
maximum demand forecast together with the station’s operational “N” rating (all transformers
in service) and the “N-1” rating at an ambient temperature of 35°C. The loading at GNTS is
forecast to reach its “N-1” rating in summer 2012 at the 50th percentile summer maximum
demand forecast.

                                                      GNTS 66 kV Summer Peak Forecasts

        220.0

                              (N) Rating @ 35 deg C
        200.0



        180.0



        160.0
  MVA




        140.0

                                                                                      10% Weather Probability Forecast
        120.0
                                 (N-1) Rating @ 35 deg C

        100.0                                                                                                                     50% Forecast



         80.0

                                                              Actuals                 Forecasts
         60.0
                2003   2004    2005   2006    2007     2008   2009      2010   2011    2012   2013   2014   2015   2016    2017    2018   2019   2020
                                                                                  Year




                                                                                                                                          Page 1 of 5
2010 Transmission Connection Planning Report                                                                                               Risk Assessment: GNTS


The (N) rating on the above chart indicates the maximum load that can be supplied from
GNTS 66 kV with all transformers in service.

The bar chart below depicts the energy at risk over the summer periods with one transformer
out of service for the 50th percentile demand forecast, and the hours per year that the 50th
percentile demand forecast is expected to exceed the N-1 capability. The line graph shows
the value to consumers of the expected unserved energy in each year, for the 50th percentile
demand forecast.


                                                                             Annual Energy and Hours at Risk at GNTS

                                                  Hours at Risk (LH scale)       Energy at Risk MWhrs (LH scale)          Customer Value (RH scale)
                                                                                                                                                              $35,000

                                   140                                                                                                                        $33,000
                                                                                                                                                              $31,000
                                                                                                                                                              $29,000
                                   120
                                                                                                                                                              $27,000
                                                                                                                                                              $25,000
    MWhr at Risk / Hours at Risk




                                   100                                                                                                                        $23,000
                                                                                                                                                              $21,000
                                                                                                                                                              $19,000
                                   80
                                                                                                                                                              $17,000
                                                                                                                                                              $15,000
                                   60                                                                                                                         $13,000
                                                                                                                                                              $11,000

                                   40                                                                                                                         $9,000
                                                                                                                                                              $7,000
                                                                                                                                                              $5,000
                                   20
                                                                                                                                                              $3,000
                                                                                                                                                              $1,000
                                    0                                                                                                                         -$1,000
                                           2011          2012         2013    2014        2015          2016       2017       2018        2019        2020
                                                                                                 Year




Comments on Energy at Risk

By the end of the ten year planning period, for an outage of one transformer at
GNTS 66 kV over the entire summer period, there will be insufficient capacity at the station to
supply all demand at the 50th percentile temperature for about 27 hours in summer 2019/20.
The energy at risk at the 50% percentile temperature under “N-1” conditions is estimated to
be 105 MWh in summer 2019/20. The estimated value to consumers of the 105 MWh of
energy at risk is approximately $6.9 million (based on a value of customer reliability of
$65,999/MWh) 1 . In other words, at the 50 percentile demand level, and in the absence of
any other operational response that might be taken to mitigate the impact of a forced outage,
an outage of one transformer at GNTS 66 kV over the summer of 2019/20 would be
anticipated to lead to involuntary supply interruptions that would cost consumers $6.9 million.

It is emphasised however, that the probability of a major outage of one of the two
transformers occurring over the duration of the year is very low, at about 1.0% per
transformer per annum, whilst the expected unavailability per transformer per annum is
0.217%. When the energy at risk (105 MWh for summer 2020) is weighted by this low
probability, the expected unsupplied energy is estimated to be 0.5 MWh. This expected


1
                                         The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
                                         in accordance with the composition of the load at this terminal station.


                                                                                                                                                             Page 2 of 5
2010 Transmission Connection Planning Report                                     Risk Assessment: GNTS


unserved energy is estimated to have a value to consumers of around $30,000 (based on a
value of customer reliability of $65,999/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in summer 2019/20 is estimated to be 367 MWh. The estimated
value to consumers of this energy at risk in 2019/20 is approximately $24.2 million. The
corresponding value of the expected unserved energy is approximately $105,000.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                                   MWh          Valued at consumer
                                                                                 interruption cost
Energy at risk, at 50th percentile demand forecast                  105               $6.9 million

Expected unserved energy at 50th percentile demand                  0.5                 $30,114

Energy at risk, at 10th percentile demand forecast                  367              $24.2 million

Expected unserved energy at 10th percentile demand                  1.6                $105,121



If one of the 220/66 kV transformers at GNTS is taken off line during peak loading times and
the N-1 station rating is exceeded, then the Overload Shedding Scheme for Connection
Assets (OSSCA) which is operated by SPI PowerNet’s TOC 2 to protect the connection
assets from overloading 3 , will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at feeder level in accordance with SPI
Electricity’s operational procedures after the operation of the OSSCA scheme.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruptions and/or to alleviate the emerging network constraint:

1. Implement contingency plans to transfer load to adjacent terminal stations.
   SPI Electricity has a 66 kV tie between GNTS and Mt Beauty Terminal Station. This can
   be used in a limited capacity to transfer load between the two terminal stations.

2. Install a third 220/66 kV transformer at GNTS: A third transformer at GNTS is a relatively
   simple, technically feasible option for augmenting GNTS. There is a provision in the
   existing 66 kV yard for an additional 220/66 kV transformer.

3. Embedded generation: Embedded generation, in the order of 20 MVA, connected to the
   GNTS 66 kV bus, will help to defer the need for augmentation by several years.

2
    Transmission Operation Centre.
3
  OSSCA is designed to protect against transformer damage caused by overloads. Damaged transformers can
take months to replace which can result in prolonged, long term risks to reliability of customer supply.




                                                                                               Page 3 of 5
2010 Transmission Connection Planning Report                                       Risk Assessment: GNTS


4. Addition of more power factor correction capacitors: The station is currently running with
   a power factor of around 0.96 at the summer peak. The use of additional capacitors to
   reduce the MVA loading would bring only marginal benefits.

Preferred network option(s) for alleviation of constraints

1. In the event there are no firm commitments by interested parties to offer network support
   services by installing local generation or through demand side management initiatives
   that would reduce future load at GNTS 66 kV, then it will be proposed to install a new
   220/66 kV transformer at GNTS 66 kV. On the basis of present forecasts, this is not
   expected to be required until around 2020.

    The capital cost of installing a new 220/66 kV transformer at GNTS 66 kV is estimated to
    be $13 million in 2010. The cost of establishing, operating and maintaining the
    transformer would be recovered from network users through network charges, over the
    life of the asset. In today’s terms, the estimated total annual cost of this network
    augmentation is approximately $1.3 million. This cost provides a broad upper bound
    indication of the maximum network support payment which may be available 4 to
    embedded generators or customers to reduce forecast demand and defer or avoid this
    transmission connection augmentation which may be required beyond 2020. Any non-
    network solution that defers this augmentation for say 1-2 years, will not have as much
    potential value (and contribution available from distributors) as a solution that eliminates
    or defers the augmentation for say 10 years. Section 1.5 of this report provides further
    background information to proponents of non-network solutions to emerging network
    constraints.

2. In the meantime it is proposed to implement the following measures to cater for an
   unplanned outage of one transformer at GNTS 66 kV under critical loading conditions
   before a third transformer is commissioned:

        •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

        •   fine-tune the OSSCA scheme settings in conjunction with TOC to minimise the
            impact on customers of any load shedding that may take place to protect the
            connection assets from overloading;

        •   subject to the availability of the SPI PowerNet country spare 220/66 kV
            transformer (refer section 4.5), this spare transformer can be used to temporarily
            replace a failed transformer; and

        •   Monitor the load growth to ensure the load at risk is within the forecasts.

The table on the following page provides data on the station rating, demand forecasts for
both summer and winter periods, annual energy and hours at risk and expected annual
unserved energy.




4
       A Rule change proposal is presently before the AEMC to enable distributors to make these payments and
       recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-
       recovery-of-transmission-related-charges.html). The Rule change, if accepted, would replicate the
       previous regulatory arrangements in Victoria.




                                                                                                Page 4 of 5
2010 Transmission Connection Planning Report                                         Risk Assessment: GNTS




GLENROWAN TERMINAL STATION 66kV (GNTS)
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:      SPI Electricity (100%)
Normal cyclic rating with all plant in service         252 MVA via 2 transformers (Winter peaking)
Summer N-1 Station Rating (MVA):                       108
Winter N-1 Station Rating (MVA):                       126

Station: GNTS 66kV                                           2011       2012        2013       2014        2015        2016       2017        2018       2019          2020
50th percentile Summer Maximum Demand (MVA)                 105.6       107.2      110.3       110.1      111.2       112.5      114.0       115.4       117.5         119.8
Summer % Overload [See Note 2 below]                          Nil         Nil      2.1%        1.9%       2.9%        4.1%       5.5%        6.8%        8.8%         10.9%
50th percentile Winter Maximum Demand (MVA)                 111.1       110.6      110.9       111.6      113.2       113.6      114.3       115.4       116.3        117.3
Winter % Overload [See Note 2 below]                           Nil         Nil        Nil         Nil        Nil         Nil         Nil        Nil         Nil          Nil
Annual energy at risk (MWh) [See Note 3 below]                 0.0        0.0         1.0        0.8         2.3        5.8        12.3       24.0        55.5        105.1
Annual hours at risk [See Note 4 below]                        0.0        0.0         1.0        0.8         2.0        3.5         6.0       11.4        19.4          27.5
Expected Annual Unserved Energy (MWh) [See
                                                               0.0        0.0         0.0        0.0         0.0        0.0         0.1         0.1        0.2           0.5
Note 5 below]
Expected Annual Unserved Energy value [See Note 6
                                                               $0          $0       $286       $229        $657      $1,651     $3,518      $6,877    $15,904       $30,114
below]




Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage with
    a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of section 2.3, weighted in accordance with the composition of the load at this terminal
    station.




                                                                                                                                                                  Page 5 of 5
2010 Transmission Connection Planning Report                                                                   Risk Assessment: GTS



GEELONG TERMINAL STATION (GTS) 66kV

Geelong Terminal Station (GTS) 66 kV consists of three 150 MVA 220/66 kV transformers,
with a fourth transformer due for commissioning in December 2010. Due to the excessive
fault levels associated with all four transformers operating in parallel, the new transformer
will operate as a hot standby with a normally open auto close scheme on its 66 kV circuit
breaker.

For the purposes of this report, it is assumed all four transformers are in service with the
fourth operating on hot standby.

GTS is the main source of supply for over 127,500 customers in Geelong and the
surrounding area. The station supply area includes Geelong, Corio, North Shore, Drysdale,
Waurn Ponds and the Surf Coast.

Magnitude, probability and impact of loss of load

Growth in summer peak demand at GTS has averaged around 10.5 MW (2.6%) per annum
over the last 5 years. The peak load on the station reached 418.3 MW in 2010.

GTS 66 kV demand is summer peaking. The graph below depicts the 10th and 50th
percentile summer maximum demand forecast together with the station’s operational “N”
rating (all transformers in service) and the “N-1” rating at 35°C ambient temperature. As the
fourth transformer is planned to operate on hot standby following its commissioning in
December 2010, the N-1 rating is equal to the N rating (3 transformers on load in parallel)
from 2011.


                                                           GTS 66kV Summer Peak Forecasts

        700.0


                                             30 min interval data used from 2010, as
        600.0                                per AEMO revised standard.                 10% Weather Probability Forecast



                   (N) rating @ 35 deg C
        500.0



        400.0
                                                                                               50% Weather Probability Forecast
  MVA




                   (N-1) Rating @ 35 deg C


        300.0                                                                                                      Where (N) = (N-1) Rating due to
                                                                                                                  new B2 transformer (hot standby)
                                                                       Actuals                Forecasts             planned for commissioning in
                                                                                                                          December 2010
        200.0



        100.0



          0.0
                1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
                                                                                 Year




The (N) rating on the chart indicates the maximum load that can be supplied from GTS with
three transformers in service. Exceeding this level will initiate automatic load shedding by
SPI PowerNet’s automatic load shedding scheme.


                                                                                                                                       Page 1 of 3
2010 Transmission Connection Planning Report                                           Risk Assessment: GTS



Under system normal conditions (i.e. with three transformers available for service) and under
(N-1) transformer outage conditions for the 50th percentile demand forecast, it is estimated
that by 2013, there will be insufficient capacity to supply all load at the station. This will lead
to automatic load shedding of customers. It is expected that first order load shedding would
occur initially, including approximately 29 MVA of demand in the Winchelsea and Colac
areas.

The above estimate is based on an assumption of moderate summer temperatures
occurring in each year. Under more extreme summer temperature conditions (that is, at the
10th percentile level), it is estimated that by 2012, there will be insufficient capacity to supply
all load at the station under (N) and (N-1) transformer outage conditions, resulting in the
above scenario.

Feasible options and preferred option for alleviation of constraints

In November 2008, Powercor published an Application Notice in relation to the proposed
augmentation of Geelong Terminal Station 1 . A copy of the Application Notice can be
downloaded from Powercor’s website at:

        http://www.citipower.com.au/docs/pdf/Electricity%20Networks/Powercor%20Network/
        GTS%20Reg%20Test%20Application%20Notice_14%20Nov.pdf

The Application Notice examined a number of options to address the emerging constraint at
the station, including:

•        Establishment of a new 220/66 kV terminal station in the East Geelong area on an
         existing vacant terminal station site. Development of this option was found to be
         uneconomic due to the high establishment costs and associated transmission
         augmentation costs.

•        Demand reduction: Voluntary demand reduction could contribute to a reduction in
         loading at the terminal station during times of network constraint. However, no firm
         offers from proponents of non-network alternatives were received in relation to
         Powercor’s proposal (foreshadowed in the 2005 Transmission Connection Planning
         Report) to install a fourth transformer.

•        Embedded generation, in the order of 150 MVA, connected to the GTS 66 kV bus,
         could substitute for additional transformer capacity at GTS. However, no firm offers
         from proponents of non-network alternatives were received in relation to Powercor’s
         proposal (foreshadowed in the 2005 Transmission Connection Planning Report) to
         install a fourth transformer.

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at GTS, Powercor decided to implement its preferred option, which is described on
page 5 of the Application Notice as follows:


1
        The Application Notice was prepared in accordance with, and meets the requirements of clause 5.6.6 of
        the National Electricity Rules (NER). It explains the rationale for the proposed fourth transformer at
        GTS with reference to the requirements of the regulatory test. The Application Notice explained that the
        proposed fourth transformer at GTS is a transmission connection investment, so the regulatory test and
        the provisions in clause 5.6.6 of the NER are not strictly applicable to the proposed investment.
        Nevertheless, this Application Notice was intended to provide a further opportunity for interested parties
        to comment on the proposed investment, which had been foreshadowed in the annual Transmission
        Connection Planning Report since 2005.


                                                                                                      Page 2 of 3
2010 Transmission Connection Planning Report                                          Risk Assessment: GTS



        “The project which is the subject of this Application Notice involves the establishment of a
        fourth 220/66 kV transformer, to be operated initially on “normal open, auto-close” duty.
        Under this arrangement, the fourth transformer will operate on “hot stand-by”, and it will be
        automatically switched into operation if there is a forced outage of any one of the other three
        normal-running transformers. The transformer is to be double-switched at 220 kV and single
        switched to the No 2 66 kV bus.

        Following the installation of the fourth transformer, Powercor’s network development plans
        envisage a second stage of works involving the permanent switching of the transformer on
        load, the creation of an open point between 66 kV buses 2 and 3, and the re-arrangement of
        66 kV feeders to balance loads and reduce fault levels at the station. On present demand
        forecasts, these works are expected to be required in 2012. For the purpose of this
        Application Notice the estimated costs of the second stage works form part of the proposed
        project.”

The latest analysis of the magnitude, probability and impact of loss of load (set out above)
confirms that proposed works to re-arrange the 66 kV exits at GTS to enable all four
transformers to operate on load with reduced fault levels are required to be completed in
2012, to support the peak summer demand for system normal conditions. Accordingly,
Powercor is proceeding with these works.

The capital cost of re-arranging the 66 kV exits at GTS is estimated to be $5 million. The
cost of establishing, operating and maintaining the 66 kV exit re-arrangements would be
recovered from network users through network charges, over the life of the asset. The
estimated total annual cost of the preferred network option is approximately $0.5 million.
This cost provides a broad upper bound indication of the maximum network support
payment which may be available 2 to embedded generators or customers to reduce forecast
demand and defer or avoid the transmission connection component of this augmentation.
Any non-network proposal must be submitted with detailed plans to Powercor for
consideration no later than June 2011. This will ensure that sufficient time is available to
implement the most cost-effective measure(s) to manage the risk of supply interruption, and
to maintain a satisfactory level of supply reliability.




2
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers   (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.


                                                                                                    Page 3 of 3
2010 Transmission Connection Planning Report                                                                        Risk Assessment: HOTS



HORSHAM TERMINAL STATION (HOTS) 66kV

Horsham Terminal Station (HOTS) 66 kV consists of two 100 MVA 235/67.5 kV transformers and
is the main source of supply for some 35,800 customers in Horsham and the surrounding area.
The station supply area includes Horsham, Edenhope, Warracknabeal and Nhill. The station also
supplies Stawell via the inter-terminal 66 kV ties with Ballarat Terminal Station (BATS).

Magnitude, probability and impact of loss of load

HOTS 66 kV demand is summer peaking. Growth in summer peak demand at HOTS has
averaged around 3.4 MW (4.6%) per annum over the last 5 years. The peak load on the station
reached 85.4 MW in summer 2010.

In 2007, as part of its asset replacement program, SPI PowerNet replaced the existing two 70
MVA 235/67.5 kV transformers with 100 MVA units after approval from Powercor. The capacity
increase delivered by these works is depicted by the step increase in the N and N-1 station rating
shown in the graph below.

The graph depicts the 10th and 50th percentile summer maximum demand forecast together with
the station’s operational “N” rating (all transformers in service) and the “N-1” rating at 35°C
ambient temperature.


                                                           HOTS 66kV Summer Peak Forecasts


        300.0

                                                                          Actuals           Forecasts


        250.0




        200.0
  MVA




        150.0             (N) rating @ 35 deg C
                                                                                                10% Weather Probability Forecast



        100.0
                        (N-1) Rating @ 35 deg C


                                                                                                        50% Weather Probability Forecast
         50.0                                     30 min interval data used from 2010, as
                                                  per AEMO revised standard.



          0.0
                1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
                                                                               Year



The graph shows that there is sufficient capacity at the station to supply all expected load over
the forecast period, even with one transformer out of service. Therefore, the need for
augmentation or other corrective action is not expected to arise over the next ten years.




                                                                                                                                           Page 1 of 1
2010 Transmission Connection Planning Report                                                                                    Risk Assessment: HTS


HEATHERTON TERMINAL STATION (HTS)

Magnitude, probability and impact of loss of load

HTS consists of three 150 MVA 220/66 kV transformers, and is the main source of supply for
a major part of the south-eastern metropolitan area. The geographic coverage of the HTS
supply area spans from Brighton in the north to Edithvale in the south.

HTS 66 kV is critically loaded in summer. The peak load on the station reached 341.1 MW
(351.4 MVA) in summer 2009. The recorded peak demand in summer 2010 was 310.1 MW
(318.6 MVA), which was approximately 31 MW lower than the 2009 peak. This is mainly
attributed to the comparatively mild weather conditions observed during summer 2010.

Major works completed at HTS over the last ten years have included:

•     sub-transmission line works to transfer about 40 MVA away from HTS prior to summer
      2002; and

•     establishment of a new terminal station at Cranbourne (CBTS) in 2005 to off-load HTS
      (and ERTS) prior to summer 2006. United Energy Distribution transferred approximately
      48 MW away from HTS to CBTS in September 2005.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational N rating (all transformers in service) and the N-1 rating
at 35°C as well as 40°C ambient temperature.

                                                            HTS Summer Peak Forecasts
          500.0
                    N Rating @ 35 deg C

                    N Rating @ 40 deg C

          450.0

                                                                                                                             10% PoE

                                                                          Actual          Forecast

          400.0
    MVA




                                                                                                                                             50% PoE
          350.0
                                                                                                                  N -1 Rating @ 35 deg C


                                                                                                                  N -1 Rating @ 40 deg C
          300.0




          250.0
                  2001   2002   2003   2004   2005   2006   2007   2008   2009     2010   2011   2012   2013   2014   2015   2016   2017   2018   2019   2020
                                                                                      Year




The N rating on the chart indicates the maximum load that can be supplied from HTS with all
transformers in service. Exceeding this level will initiate SPI PowerNet’s load shedding
scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to


                                                                                                                                              Page 1 of 5
2010 Transmission Connection Planning Report                                                                                         Risk Assessment: HTS


consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.
                                                     Annual Energy and Hours at Risk at HTS (Single Contingency Only)

                                                 Hours at Risk (LH scale)          Energy at Risk MWh (LH scale)           Customer Value (RH scale)

                                  1,250                                                                                                                  $500,000


                                  1,125                                                                                                                  $450,000


                                  1,000                                                                                                                  $400,000


                                   875                                                                                                                   $350,000
    MWh at Risk / Hours at Risk




                                   750                                                                                                                   $300,000


                                   625                                                                                                                   $250,000


                                   500                                                                                                                   $200,000


                                   375                                                                                                                   $150,000


                                   250                                                                                                                   $100,000


                                   125                                                                                                                   $50,000


                                     0                                                                                                                   $0
                                          2011       2012          2013     2014       2015          2016          2017   2018       2019         2020
                                                                                              Year




Comments on Energy at Risk

For an outage of one transformer at HTS, there will be insufficient capacity at the station to
supply all demand at the 50th percentile temperature for about 41 hours in 2020. The energy
at risk under N-1 conditions is estimated at 1,036 MWh in summer 2020. The estimated
value to consumers of the 1,036 MWh of energy at risk is approximately $72.9 million (based
on a value of customer reliability of $70,299/MWh) 1 . In other words, at the 50th percentile
demand level, and in the absence of any other operational response that might be taken to
mitigate the impact of a forced outage, a major outage of one transformer at HTS over the
summer of 2020 would be anticipated to lead to involuntary supply interruptions that would
cost consumers $72.9 million.

It is emphasised however, that the probability of a major outage of one of the three
transformers occurring over the year is very low at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (1,036 MWh in 2020) is weighted by this low unavailability, the expected unserved
energy is estimated to be around 6.7 MWh. This expected unserved energy is estimated to
have a value to consumers of around $470,000 (based on a value of customer reliability of
$70,299/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2020 is estimated to be 1,670 MWh. The estimated value to consumers of this
energy at risk in 2020 is approximately $117.4 million. The corresponding value of the
expected unserved energy is around $758,000.


1
                                      The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
                                      in accordance with the composition of the load at this terminal station.


                                                                                                                                                   Page 2 of 5
2010 Transmission Connection Planning Report                            Risk Assessment: HTS


These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.
                                                        MWh        Valued at consumer
                                                                     interruption cost
Energy at risk, at 50th percentile demand forecast         1,036            $72.9 million

Expected unserved energy at 50th percentile demand            6.7             $470,000

Energy at risk, at 10th percentile demand forecast         1,670           $117.4 million

Expected unserved energy at 10th percentile demand          10.8              $758,000


If one of the 220/66 kV transformers at HTS is taken off line during peak loading times and
the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by
SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at zone substation feeder level in
accordance with United Energy’s operational procedures after the operation of the OSSCA
scheme.

In the case of HTS supply at maximum loading periods, and based on the Schedule of
Priority Load Shedding recommended by the Demand Reduction Committee, the OSSCA
scheme would shed about 100 MVA of load, affecting approximately 38,700 customers in
2011.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement a contingency plan to transfer load to adjacent terminal stations. United
   Energy Distribution has established and implemented the necessary plans that enable
   load transfers under contingency conditions, via both 66 kV subtransmission and 22 kV
   distribution networks.

2. Install a fourth 220/66 kV transformer at HTS.

3. Demand Side Management: United Energy Distribution has developed a number of
   innovative network tariffs that encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and
   the subsequent change in load pattern, and will be taken into consideration when
   determining the optimum timing for any future capacity augmentation.

4. Embedded generation, in the order of 30 MVA, connected to the network supplied by
   HTS 66 kV bus, will help to defer the need for augmentation at HTS by one year.




2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre


                                                                                 Page 3 of 5
2010 Transmission Connection Planning Report                                          Risk Assessment: HTS


Preferred network option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at HTS, it is proposed to:

1. Install a fourth 150 MVA 220/66 kV transformer at HTS.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at HTS under critical loading conditions:

        •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

        •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
            impact on customers of any load shedding that may take place; and

        •   Subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
            metropolitan areas (refer to Section 4.5), this spare transformer can be used to
            temporarily replace the failed transformer.

On the present forecasts an additional 220/66 kV transformer is not likely to be required
within the ten year planning horizon. The capital cost of installing a 220/66 kV transformer at
HTS is estimated to be $14 million. The cost of establishing, operating and maintaining a
new transformer would be recovered from network users through network charges, over the
life of the asset. The estimated total annual cost of this network augmentation is
approximately $1.4 million. This cost provides a broad upper bound indication of the
maximum network support payment which may be available to embedded generators or
customers to reduce forecast demand, and to defer or avoid the transmission connection
component of this augmentation. 4 Any non-network solution that defers this augmentation
for say 1-2 years, will not have as much potential value (and contribution available from
distributors) as a solution that eliminates or defers the augmentation for, say, 10 years.
Sections 1.5 and 1.6 of this report provide further background information to proponents of
non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.


                                                                                                Page 4 of 5
2010 Transmission Connection Planning Report                                          Risk Assessment: HTS


HEATHERTON TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                United Energy Distribution (100%)
Station operational rating (N elements in service):              495 MVA via 3 transformers (Summer peaking)
Summer N-1 Station Rating:                                       330 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       388 MVA


Station: HTS 66 kV                                           2011        2012        2013       2014        2015        2016       2017         2018        2019        2020

50th percentile Summer Maximum Demand (MVA)                  333.8      338.4       348.4       355.1      356.7       365.7       373.5       379.0       387.5        395.8
Summer % Overload [See Note 2 below]                           1%          3%         6%          8%          8%        11%         13%         15%         17%          20%
50th percentile Winter Maximum Demand (MVA)                  264.8      269.1       269.2       269.6      271.0       277.5       281.7       285.4       289.8        294.1
Winter % Overload [See Note 2 below]                            Nil        Nil         Nil         Nil        Nil         Nil         Nil         Nil         Nil          Nil
Annual energy at risk (MWh) [See Note 3 below]                  19          37        108         169        187         301        436          554         775        1,036
Annual hours at risk [See Note 4 below]                          4           6          9          13         13          17          23          29          34           41
Expected annual unserved energy (MWh) [See Note 5
                                                               0.1         0.2         0.7        1.1         1.2        1.9         2.8         3.6          5.0         6.7
below]
Expected Annual Unserved Energy value [See Note 6
                                                               $9k       $17k        $49k       $77k        $85k      $137k       $198k       $252k        $352k       $470k
below]


Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                    Page 5 of 5
  2010 Transmission Connection Planning Report                                                          Risk Assessment: HYTS



  HEYWOOD TERMINAL STATION (HYTS) 22kV

  Heywood Terminal Station (HYTS) 22 kV consists of two 70 MVA 500/275/22 kV transformers
  and is the source of supply to Midway, a woodchipper in the local area and the only customer
  supplied by this supply point.

  Magnitude, probability and impact of loss of load

  The peak 22 kV customer load supplied from the station reached 1.2 MW in summer 2010.

  The 22 kV point of supply was established in late 2009, by utilising the tertiary 22 kV on the
  existing 2 x 500/275/22 kV South Australian/Victorian interconnecting transformers. T he supply is
  arranged so that one transformer is on hot standby (on its tertiary 22 kV), due to excessive fault
  levels.

  The graph depicts the 10th and 50th percentile summer maximum demand forecast together with
  the station’s operational “N-1” rating at 35°C ambient temperature.

                                                     HYTS 22kV Summer Peak Forecasts




      80.0

               (N-1) Rating @ 35 deg C
      70.0



      60.0



      50.0
MVA




      40.0



      30.0



      20.0
                                                       50% & 10% Weather Probability
                           Forecasts                            F      t
      10.0



       0.0
             2010       2011           2012   2013       2014         2015         2016   2017   2018     2019    2020
                                                                      Year



  The graph shows that there is sufficient capacity at the station to supply all expected 22 kV
  customer load over the forecast period, even with one transformer out of service. Therefore, the
  need for augmentation or other corrective action is not expected to arise over the next ten years.




                                                                                                                   Page 1 of 1
2010 Transmission Connection Planning Report                                                                           Risk Assessment: KGTS



KERANG TERMINAL STATION (KGTS) 66kV & 22kV

Magnitude, probability and impact of loss of load

Kerang Terminal Station (KGTS) 66 kV and 22 kV consists of three 35 MVA 235/66/22 kV
transformers and is the main source of supply for over 18,828 customers in Kerang and the
surrounding area. The station supply area includes Kerang, Swan Hill and Cohuna.

Growth in summer peak demand at KGTS is expected to average around 1.47 MVA (1.89%)
per annum over the next ten year forecast period. The peak load on the station reached 69
MVA (66 kV and 22 kV networks) in summer 2010.

KGTS 66 kV demand is summer peaking. The graph below depicts the 10th and 50th
percentile summer maximum demand forecast together with the station’s operational “N”
rating (all transformers in service) and the “N-1” rating at 35°C ambient temperature.

                                                              KGTS Summer Peak Forecasts


        140.0



        120.0           (N) rating @ 35 deg C




        100.0
                                                                                                10% Weather Probability Forecast
                        (N-1) Rating @ 35 deg C


         80.0
  MVA




         60.0
                                                                                                                 50% Weather Probability Forecast



         40.0



         20.0                                     Actuals                 Forecasts




          0.0
                2005   2006   2007     2008       2009      2010   2011    2012       2013   2014    2015     2016     2017        2018   2019      2020
                                                                                Year




The graph shows there is sufficient capacity at the station to supply all expected demand at
the 50th percentile temperature, over the forecast period, even with one transformer out of
service. Therefore, the need for augmentation or other corrective action is not expected to
arise over the next ten years. From 2018, there is load at risk at the 10th percentile
temperature for the loss of a transformer and it is planned to use mobile generation to
provide network support in the event that a transformer outage would otherwise lead to load
shedding.




                                                                                                                                             Page 1 of 1
2010 Transmission Connection Planning Report                                 Risk Assessment: KTS


KEILOR TERMINAL STATION 66 kV (KTS 66 kV)

Keilor Terminal Station is located in the north west of Greater Melbourne. It operates at
220/66 kV and supplies Jemena Electricity Networks and Powercor customers in the Airport
West, St. Albans, Sunshine, Melton, Woodend, Pascoe Vale, Essendon and Braybrook
areas.

Background

KTS has five 150 MVA transformers connected to four 66 kV buses and is a summer critical
station. The station is operated with one of the five transformers, also known as KTS B5
transformer, in “hot standby” mode and the No. 2-3 66 kV bus tie circuit breaker open for the
purpose of limiting the magnitude of the fault level to within switchgear ratings. In the event
of an outage of one of the four “normally in-service” transformers, the B5 unit will be
connected in automatically. Therefore the “N” and “N-1” ratings are the same.

The risk of supply interruption at Keilor Terminal Station (KTS) had previously been
assessed as being unacceptable for summer 2009/10, and the installation of the new KTS
B5 transformer at the existing Keilor Terminal station was identified (in the 2004, 2005 and
2006 Transmission Connection Planning Reports) as the most economic network solution.
The new KTS B5 transformer was intended to be operated in a “hot standby” mode initially
for the purpose of limiting the magnitude of the fault level to within switchgear ratings. Prior to
committing to the preferred network solution, Jemena Electricity Networks and Powercor
completed a public “Expression of Interest” process for non-network alternatives, via the
publication of the Transmission Connection Planning Report in 2006. At the conclusion of
the expression of interest process on 28 February 2007, no firm proposals for alternatives to
the network augmentation had been received. In the absence of any commitment by
interested parties to offer non-network solutions, Jemena Electricity Networks and Powercor
proceeded to implement the proposed network solution.

The new KTS B5 transformer was commissioned in early 2010. Jemena Electricity Networks
and Powercor had also conducted a joint planning study in 2008 which concluded that re-
configuring the station to enable the KTS B5 transformer to take load under system normal
conditions by summer 2011/12 is the most economic network solution. This project is now
underway and will result in KTS being split into two groups, KTS(B1,2,5) and KTS(B3,4),
from summer 2011/12 onwards. Under system normal conditions, the No.1, No.2 & No.5
transformers are operated in parallel as one group (KTS(B1,2,5)) and supply the No.1, No.2
& No.5 66kV buses. The No.3 & No.4 transformers are operated in parallel as a separate
group (KTS(B3,4)) and supply the No.3 & No.4 66 kV buses. The 66 kV bus 3-5 and bus 1-4
tie circuit breakers are operated in the normally open position to limit the maximum
prospective fault levels on the five 66 kV buses to within switchgear ratings.

For an unplanned transformer outage in the KTS(B3,4) group, the No.5 transformer will
automatically change over to the KTS(B3,4) group. Therefore, an unplanned transformer
outage of any one of the five transformers at KTS will result in both the KTS(B1,2,5) &
KTS(B3,4) groups being comprised of two transformers each. Given this configuration, load
demand on the KTS(B3,4) group must therefore be kept within the capabilities of the two
transformers at all times or load shedding will occur.

The graph below depicts the KTS operational “N” rating (for all four transformers in service),
the “N-1” rating (for an outage of one transformer) and the 50th and 10th percentile summer
maximum demand forecasts up to summer 2010/11.




                                                                                        Page 1 of 10
2010 Transmission Connection Planning Report                                                                                                                            Risk Assessment: KTS



                                                                                   KTS Summer Peak Forecasts

                800
                             10% Weather Probability Forecast                                                       KTS 66kV is planned to be split into two groups,
                750                                                                                                   KTS(B125) and KTS(B34), by summer 2012
                             50% Weather Probability Forecast
                700                                                                                                                                       (N)=(N-1) Rating @ 35 deg C

                650

                600
        MVA




                550

                500            (N-1) Rating @ 35 deg C

                450
                                                                                                                                                         (N)=(N-1) Ratings due to 'Normally
                                                                                                                                                          Open Auto-close' duty on the new
                400
                                                                                                                                                          B5 transformer commissioned in
                                                              Actuals                            Forecasts                                                         February 2010
                350

                300
                      2006        2007           2008         2009       2010             2011     2012        2013           2014      2015        2016         2017   2018         2019          2020
                                                                                                               Year



The graph shows that with four transformers in service, there is inadequate capacity to meet
the anticipated maximum load demand in 2011. Jemena Electricity Networks and Powercor
have appropriate contingency plans to transfer load to adjacent terminal stations under high
ambient temperatures.

As noted above, after summer 2010/11, the station will be split into two groups, also known
as KTS(B1,2,5) and KTS(B3,4). The following sections discuss the two transformer groups.

Transformer group KTS (B1,2,5) Summer Peak Forecasts

The graph below depicts the KTS (B1,2,5) rating with all transformers (B1, B2 & B5) in
service (“N” rating), and with one of the three transformers out of service (“N-1” rating), along
with the 50th and 10th percentile summer maximum demand forecasts from summer 2012
onwards 1 .
                                                                                           KTS(B125) Summer Peak Forecasts

               600


                                                                                                                                     10% Weather Probability Forecast
               550



                                                (N) Rating @ 40 deg C
               500

                                                (N) Rating @ 45 deg C

               450
         MVA




               400
                                                                                                  50% Weather Probability Forecast



               350              KTS 66kV is planned to be split into two groups,
                                  KTS(B125) and KTS(B34), by summer 2012
                                                                                                                                                                        (N-1) Rating @ 40 deg C

               300
                                                                                                                                                                        (N-1) Rating @ 45 deg C



               250       Forecasts




               200
                      2011               2012                 2013                 2014             2015               2016               2017               2018          2019               2020
                                                                                                             Year




1
    Note that station transformer output capability rating and transformers’ loading is used.


                                                                                                                                                                                                  Page 2 of 10
2010 Transmission Connection Planning Report                                                                                                  Risk Assessment: KTS



The above graph shows that with all transformers in service, there is adequate capacity to
meet the anticipated maximum load demand until 2016. However, if there is a forced
transformer outage during peak load periods from 2012 onwards, some customers might be
affected.

Transformer group KTS (B3,4) Summer Peak Forecasts

The graph below depicts the summer maximum demand forecasts (for 50th and 10th
percentile temperatures) for KTS (B3,4) and the corresponding rating with both transformers
(B3 & B4) operating. It shows that with all transformers in service, there is adequate capacity
to meet the anticipated maximum load demand until 2013, even under a transformer outage
condition. From 2013 onwards, there is insufficient capacity to meet the anticipated
maximum load demand (at the 10th percentile forecast) for the remainder of the forecast
period.



                                                                              KTS(B34) Summer Peak Forecasts

       450




                                                                                                10% Weather Probability Forecast
       400




       350                                                                                                                         Rating of 2 transformers @ 40 deg C


                                                                                                                                   Rating of 2 transformers @ 45 deg C
 MVA




       300                                                                         50% Weather Probability Forecast

                    KTS 66kV is planned to be split into two groups,
                      KTS(B125) and KTS(B34), by summer 2012



       250

                Forecasts




       200
             2011               2012                2013               2014           2015               2016               2017     2018               2019             2020
                                                                                               Year




Magnitude, probability and impact of loss of load at KTS

The magnitude, probability and load at risk for the two transformer groups are considered
together below.

System Normal Condition (All 5 transformers in service)

The bar chart below depicts the energy at risk under system normal conditions for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N capability rating. The line graph shows the value to consumers
of the expected unserved energy in each year, for the 50th percentile demand forecast. It
should be noted that the energy at risk on the KTS (B3,4) group is the same as the expected
unserved energy in each year because the B5 transformer will be normally operated in
parallel with the KTS (B1,2,5) group.


                                                                                                                                                                     Page 3 of 10
2010 Transmission Connection Planning Report                                                                                                                                      Risk Assessment: KTS


                                                                       Annual Energy and Hours at Risk and Expected Customer Value at KTS (B34)
                                                                                           under system normal condition
                                                                        Hours at Risk (LH scale)       Energy at Risk MWhrs (LH scale)          Customer Value (RH scale)
                                  400                                                                                                                                                                $25,000 k




                                  350


                                                                                                                                                                                                     $20,000 k

                                  300
 MWhr at Risk / Hours at Risk




                                  250
                                                                                                                                                                                                     $15,000 k



                                  200



                                                                                                                                                                                                     $10,000 k
                                  150




                                  100

                                                                                                                                                                                                     $5,000 k


                                  50




                                    0                                                                                                                                                                $0 k
                                            2011     2012     2013               2014                2015                  2016               2017                  2018         2019      2020
                                                                                                                Year




N-1 System Condition

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating for the KTS(B1,2,5) group. The line graph
shows the value to consumers of the expected unserved energy in each year, for the 50th
percentile demand forecast.

                                                                       Annual Energy and Hours at Risk and Expected Customer Value at KTS(B125)
                                                                                                 under (N-1) condition
                                                                          Hours at Risk (LH scale)          Energy at Risk MWhrs (LH scale)          Customer Value (RH scale)
                                  25,000                                                                                                                                                              $16,000 k




                                                                                                                                                                                                      $14,000 k


                                  20,000

                                                                                                                                                                                                      $12,000 k
   MWhr at Risk / Hours at Risk




                                                                                                                                                                                                      $10,000 k
                                  15,000



                                                                                                                                                                                                      $8,000 k



                                  10,000
                                                                                                                                                                                                      $6,000 k




                                                                                                                                                                                                      $4,000 k
                                   5,000


                                                                                                                                                                                                      $2,000 k




                                        0                                                                                                                                                             $0 k
                                              2011     2012     2013               2014               2015                  2016              2017                   2018        2019      2020
                                                                                                                  Year




                                                                                                                                                                                                  Page 4 of 10
2010 Transmission Connection Planning Report                                            Risk Assessment: KTS


Comments on Energy at Risk at KTS

From 2012 onwards, there will be sufficient capacity at the station to supply all customer
demand until 2017 under system normal condition for the 50th percentile demand forecast.
However from 2012 onwards, for a major outage of one transformer at KTS 66 kV over the
summer peak load period, there would be insufficient capacity at the station to supply all
customer demand.

By summer 2016/17, the energy at risk for a system normal (N condition) and a transformer
outage (N-1 condition) on the KTS transformer groups is estimated to be 7.9 MWh and
9017.1 MWh respectively for the 50th percentile demand forecast. Over the summer 2016/17
period, there would be insufficient capacity to meet demand for about 1 hour and 226 hours
in that year for N and (N-1) conditions respectively. The estimated value to consumers of the
7.9 WMh and 9017.1 MWh of energy at risk is approximately $476,200 and $541.0 million
respectively (based on a value to customer reliability of $60,000/ MWh) 2 . In other words, at
the 50th percentile summer demand level, and in the absence of any other operational
response that might be taken to mitigate impacts on customers:

     • under system normal conditions over the summer of 2016/17, insufficient capacity at
       KTS would be expected to lead to involuntary supply interruptions that would cost
       consumers $476,200; and

     • a major outage of one transformer at KTS over the summer of 2016/17 would be
       anticipated to lead to involuntary supply interruptions that would cost consumers
       $541.0 million respectively.

It is emphasised however, that the probability of a major outage of one of the five
transformers is very low, at about 1.0% per transformer per annum, whilst the expected
unavailability per transformer per annum is 0.217%. When the energy at risk (9017.1 MWh)
is weighted by this low transformer unavailability, the expected unserved energy (for loss of
one transformer) is estimated to be around 97.7 MWh. Combining this with the expected
unserved energy (7.9 MWh) under system normal conditions, the total expected unserved
energy is estimated to have a value to consumers of around $6.3 million.

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate (50th percentile) summer temperatures
occurring in each year. Under more extreme summer temperature conditions (that is, at the
10th percentile level), the customer demand increases significantly due to air conditioning
loads. At the 10th percentile demand forecast, the energy at risk in the summer of 2016/17 for
N and (N-1) conditions are estimated to be 465.2 MWh and 15,369 MWh respectively. The
estimated value to consumers of this energy at risk in the summer of 2016/17 for N and (N-1)
conditions are approximately $27.9 million and $922.1 million respectively. The total
corresponding value of the expected unserved energy is approximately $37.9 million.

These key statistics for the summer of 2016/17 under N and (N-1) outage conditions are
summarised in the table below.




2
         The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
         in accordance with the composition of the load at this terminal station.


                                                                                                    Page 5 of 10
2010 Transmission Connection Planning Report                            Risk Assessment: KTS




                                                           MWh             Valued at
                                                                           consumer
                                                                       interruption cost
Energy at risk, at 50th percentile demand forecast
                                                            7.9           $476,200
under N condition
Expected unserved energy at 50th percentile demand
                                                            7.9           $476,200
under N condition
Energy at risk, at 50th percentile demand forecast
                                                          9017.1        $541.0 million
under N-1 outage condition
Expected unserved energy at 50th percentile demand
                                                           97.7          $5.9 million
under N-1 outage condition
Energy at risk, at 10th percentile demand forecast
                                                          465.2          $27.9 million
under N condition
Expected unserved energy at 10th percentile demand
                                                          465.2          $27.9 million
under N condition
Energy at risk, at 10th percentile demand forecast
                                                          15,369        $922.1 million
under N-1 outage condition
Expected unserved energy at 10th percentile demand
                                                           166.5         $10.0 million
under N-1 outage condition


Possible Impact on Customers

System Normal Condition (All 5 transformers in service)

Applying the 50th percentile demand forecast, it is anticipated that load shedding of 8.6MVA
in 2016/17 increasing to 46.9MVA in 2019/20 would be required to limit the load to within the
rated capacity of the station. This would affect approximately 2,900 customers in 2016/17
and increases to 15,600 in 2019/20 under system normal condition. This indicates that major
action will be required during the forecast period to alleviate this emerging constraint.

N-1 System Condition

If one of the KTS 220/66 kV transformers is taken off line during peak loading times, causing
the KTS (B1,2,5) rating to be exceeded, the OSSCA 3 load shedding scheme which is
operated by SPI PowerNet’s NOC 4 will act swiftly to reduce the loads in blocks to within
transformer capabilities. Any load reductions that are in excess of the minimum amount
required to limit load to the rated capability of the station would be restored after the
operation of the OSSCA scheme, at zone substation feeder level in accordance with
Jemena EN’s and Powercor’s, operational procedures.

In the summer of 2016/17, at maximum loading periods, based on the Schedule of Priority
Load Shedding recommended by the Demand Reduction Committee, the OSSCA scheme
would automatically shed about 147.5 MVA of the KTS supply load. This would affect
approximately 49,200 customers.

3
         Overload Shedding Scheme of Connection Asset.
4
         Network Operations Centre.


                                                                                   Page 6 of 10
2010 Transmission Connection Planning Report                              Risk Assessment: KTS


Applying the 50th percentile demand forecast, the energy at risk increases from 946.4MWh in
2011/12 to 20,187.2MWh in 2019/20. For the same period, the expected unserved energy
increases from 10.3MWh in 2011/12 to 218.7MWh in 2019/20. This indicates that major
action will be required during the forecast period to alleviate this emerging constraint.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or alleviate the emerging constraint over the next ten year planning
horizon:

1. Installation of Reactive Compensation at KTS, followed by the establishment of a new
   Terminal Station at Deer Park.

    The most likely long term viable solution for the next stage of augmentation at Keilor
    Terminal Station includes the installation of a 100 MVAr capacitor bank on the KTS(B3,4)
    group to improve the power factor and to reduce the transformer load. This would be
    followed by the establishment of a new 220/66kV Terminal Station at Deer Park on a site
    already reserved for this purpose. This development path is consistent with AEMO’s long
    term plan to augment 220 kV capacity in the area by connecting into future terminal
    stations at Deer Park and Tarneit from a proposed terminal station at Truganina
    connected to the 500 kV transmission line.

2. Establishment of 6th Transformer at KTS, followed by the establishment of a new
   Terminal Station at Deer Park.

    The establishment of the 6th transformer at KTS on the KTS(B3,4) group, followed by the
    establishment of a new 220/66kV Deer Park Terminal Station will alleviate the emerging
    constraint. However, this option is likely to cost more than Option 1.

3. Installation of Reactive Compensation or 6th Transformer at KTS, followed by the
   establishment of new 500/220 kV and 220/66 kV transformation at Sydenham Terminal
   Station. This option is likely to be technically feasible and more expensive than Options 1
   and 2 because the transmission voltage that exists at Sydenham Terminal Station is
   500 kV and it usually costs more to transform to 66 kV from 500 kV than it does from
   220 kV.

4. Embedded generation. An alternative option to the network solution could be the
   establishment of an embedded generator, suitably located in the area that is presently
   supplied by KTS.

5. Demand Management. Another alternative option could be the introduction of demand
   management to reduce the magnitude of the summer peak demands under network
   emergencies. This might involve the introduction of interruptible load, negotiated with
   customers at reduced prices, with an agreement that the load can be interrupted during
   times of network constraint.

Preferred network option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer comparable non-network
solutions such as installing local generation or through demand side management initiatives
that would reduce load at KTS, the following network option is proposed.



                                                                                     Page 7 of 10
2010 Transmission Connection Planning Report                                        Risk Assessment: KTS


    1. Install a 100 MVAr capacitor bank on the KTS(B3,4) group by summer 2013/14 at an
       estimated capital cost of $6 million, to improve the power factor and to reduce the
       transformer load; and

    2. Establish a new 220/66kV terminal station at Deer Park and associated 66 kV sub-
       transmission lines by summer 2016/17 at an estimated capital cost of $70 million, to
       transfer load from KTS(B1,2,5) and KTS(B3,4) groups to the new terminal station.

In the meantime, exposure to energy at risk will be managed through the following temporary
measures to cater for system normal conditions and an unplanned outage of one transformer
at KTS at times of peak loading:

•   balance the load between the two bus groups at KTS so that the load on each bus group
    is kept below its respective N rating

•   maintain contingency plans to transfer load quickly to adjacent terminal stations;

•   fine-tune the OSSCA scheme settings in conjunction with SPI PowerNet’s NOC to
    minimise the impact on customers of any automatic load shedding that may take place;
    and

•   Subject to the availability of the SPI PowerNet spare 220/66 kV transformer for urban
    areas (refer section 4.5), this spare transformer can be used to temporarily replace a
    failed transformer.

This proposal will be reviewed annually having regard to the 10th and 50th percentile
maximum demand forecasts, and the load at risk under N and N-1 conditions.

The estimated total annual cost of this network augmentation is $7.6 million. This cost
provides a broad upper bound indication of the maximum contribution from distributors which
may be available to embedded generators or customers to reduce forecast demand and
defer or avoid the transmission connection component of this augmentation 5 . Any non-
network solution that defers this augmentation for a short time, say 1-2 years, will not have
the same potential value (and contribution available from distributors) as a solution that
eliminates or defers the augmentation for a longer period of time, say, 10 years.

Proponents of non-network alternatives to these augmentations should contact Jemena EN
or Powercor with a detailed proposal (addressing the information requirements set out in
Section 1.4 of this report) before December 2011. Submission of this detailed information by
that date will ensure that sufficient time is available to assess all options and to implement
the preferred option, so that an adequate level of supply reliability can be maintained.
Section 1.5 of this report provides further background information to proponents of non-
network solutions to emerging constraints.

The tables on the following pages provide more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.
5
   A Rule change proposal is presently before the AEMC to enable distributors to make these payments and
recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-recovery-
of-transmission-related-charges.html). The Rule change, if accepted, would replicate the previous regulatory
arrangements in Victoria.




                                                                                               Page 8 of 10
2010 Transmission Connection Planning Report                                                                                                             Risk Assessment: KTS




    KEILOR TERMINAL STATION UNDER N-1 OUTAGE CONDITIONS (KTS(B1,2,5) TRANSFORMER GROUP) 6
    Detailed data: Magnitude and probability of loss of load

    Distribution Businesses supplied by this station:                           Jemena EN (64%), Powercor (36%)
    Normal cyclic rating with all plant in service                              495 MVA (Summer peaking)
    Summer N-1 Station Transformer Rating:                                      313 MVA [See Note 1 below for interpretation of N-1]
    Winter N-1 Station Transformer Rating:                                      353 MVA

    Station: KTS(B125) 66kV                                        2011        2012         2013        2014    2015     2016          2017      2018        2019         2020
    50th percentile Summer Maximum Demand (MVA)                     363         378          392         406     434      446           461       475         489         504
    Summer % Overload [See Note 2 below]                           16%         21%          25%         30%     38%      42%           47%       52%         56%          61%
    50th percentile Winter Maximum Demand (MVA)                     282         294          303         326     334      343           353       362         372         381
    Winter % Overload [See Note 2 below]                            0%          0%           0%          0%      0%       0%            0%        3%          5%           8%
    Annual energy at risk (MWh) [See Note 3 below]                  456        946          1,616       2,619   5,227    6,768         9,017    11,747      15,196       20,196
    Annual hours at risk [See Note 4 below]                          29         48            67          96     143      175           226      295         394          539
    Expected Annual Unserved Energy (MWh) [See
                                                                     5           10          18           28     57        73           98        127         165          228
    Note 5 below]
    Expected Annual Unserved Energy value [See
                                                                  $296 k      $615 k      $1,050 k $1,703 k $3,397 k $4,399 k $5,861 k $7,636 k $9,877 k                $13,668 k
    Note 6 below]
Notes:
1. “N-1” means cyclic station transformer output capability rating with outage of one transformer. The rating is at an ambient temperature of 40 degrees Centigrade as this is
    the typical temperature where 50% PoE loads are likely to occur at KTS.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. "Annual energy at risk" is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
    outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
    station.


6
    Note that risk assessment for this station is carried out using station transformers’ rating and loading.




                                                                                                                                                                 Page 9 of 10
2010 Transmission Connection Planning Report                                                                                                            Risk Assessment: KTS




 KEILOR TERMINAL STATION UNDER N and N-1 CONDITIONS (KTS(B3,4) TRANSFORMER GROUP)
 Detailed data: Magnitude and probability of loss of load

 Distribution Businesses supplied by this station:                     Jemena EN (31%), Powercor (69%)
 Normal cyclic rating with all plant in service:                       344 MVA (Summer peaking)
 Summer N-1 Station Transformer Rating:                                344 MVA [See Note 1 below for interpretation of N-1]
 Winter N-1 Station Transformer Rating:                                344 MVA

Station: TTS34 66kV                                          2011         2012        2013        2014          2015         2016        2017         2018         2019          2020
50th percentile Summer Maximum Demand (MVA)                   300          312         322         334           329          340         352          365          377          391
Summer % Overload [See Note 2 below]                          0%           0%          0%          0%            0%           0%          3%           6%          10%           14%
50th percentile Winter Maximum Demand (MVA)                   227          236         242         240           248          255         264          272          281          290
Winter % Overload [See Note 2 below]                          0%           0%          0%          0%            0%           0%          0%           0%           0%            0%
Annual energy at risk (MWh) [See Note 3 below]                 0            0           0           0             0            0           8           53           148          362
Annual hours at risk [See Note 4 below]                        0            0           0           0             0            0           1            5           13            23
Expected Annual Unserved Energy (MWh) [See
                                                               0            0           0           0             0            0           8           53           148          362
Note 5 below]
Expected Annual Unserved Energy value [See
                                                              $- k        $- k         $- k        $- k         $- k         $- k       $476 k      $3,194 k     $8,884 k $21,725 k
Note 6 below]
Notes:
1. “N-1” means cyclic station transformer output capability rating with outage of one transformer. The rating is at an ambient temperature of 40 degrees Centigrade as this is
    the typical temperature where 50% PoE loads are likely to occur at KTS.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. "Annual energy at risk" is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
                                                                                        th
4. “Annual hours per year at risk” is the number of hours in a year during which the 50 percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
    outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
    station.




                                                                                                                                                                Page 10 of 10
2010 Transmission Connection Planning Report                                                                        Risk Assessment: MBTS



MT BEAUTY TERMINAL STATION 66 kV (MBTS 66 kV)

Mt Beauty Terminal Station is the main point of connection into the 220 kV electricity grid for
Victoria’s Kiewa hydro generation resources. The power stations include West Kiewa,
Mackay, Dartmouth, Clover and Eildon. MBTS is also the source of 66 kV supply for the
alpine areas of Mt Hotham and Falls Creek along with the townships of Bright, Myrtleford
and Mount Beauty. The station has two 220/66 kV 50 MVA transformers installed in 2005
(as part of SPI PowerNet’s asset replacement program) but only one is in service with the
other available as a hot spare that can be brought into service in approximately 4 hours. In
addition, supply can also be taken from Clover Power Station and the 66 kV tie to
Glenrowan Terminal Station via Myrtleford. It is SPI Electricity’s responsibility to plan the
electricity supply network for this large region.

Magnitude, probability and impact of loss of load

MBTS is a winter peaking station and growth in winter peak demand at MBTS 66 kV has
averaged around 1 MW (2%) per annum over the last 4 years (2006 to 2009) however the
latest demand forecast suggests an annual growth rate of 1% for the next few years. The
peak load on the station reached 51.2 MVA in winter 2009, whereas the station peak
demand reached 48 MVA in winter 2010. The summer peak is approximately 73% of the
winter peak.

In light of the current and expected future network configuration, and in keeping with the
approach adopted by AEMO in its planning studies, the “N-1” scenario for MBTS is the loss
of the 66 kV line to Clover Power Station.

The graph below depicts the 10th and 50th percentile winter maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N-1”
rating at an ambient temperature of 5°C. With the forecast growth rates, MBTS 66 kV is not
expected to reach its “N-1” winter station rating during 10 year planning horizon.


                                                   MBTS 66 kV Winter Peak Forecasts

         90.0



                                                      (N) Rating @ 5 deg C
         80.0




         70.0                                                 (N-1) Rating @ 5 deg C
                                                                 (loss of Clover P.S.)
   MVA




         60.0

                                                                                         10% Weather Probability Forecast


         50.0
                                                                                                            50% Weather Probability Forecast



         40.0
                                                           Actuals             Forecasts



         30.0
                2003   2004   2005   2006   2007    2008   2009   2010    2011     2012      2013    2014    2015    2016   2017    2018   2019
                                                                          Year




                                                                                                                                        Page 1 of 2
2010 Transmission Connection Planning Report                                         Risk Assessment: MBTS



The above analysis ignores the possibility of loss of load for the short period of about 4
hours that it takes to change over from the in-service transformer to the hot spare
transformer. The 66 kV tie line to Glenrowan Terminal Station can support about 25 MW of
MBTS load and this tie line is operated normally closed so if the MBTS load is below this
limit there will not be any loss of customer load. The Clover Power Station can generate
around 26 MW and so any generation would also minimise the likelihood of the loss of
customer load during a transformer outage.

It is recognised that at times of high demand and with low output from Clover Power Station
a transformer outage at MBTS could result in the loss of some customer load for a period of
no more than 4 hours.

The energy at risk for a major transformer outage 1 at MBTS (taking account of the limited 66
kV tie line capability) is significant at around 7,027 MWh in winter 2011 and rising to 9909
MWh by 2019. However, given that the hot spare transformer will be made available within
4 hours, the expected outage duration in the case of a major transformer failure at MBTS is
4 hours (rather than 2.6 months). Accordingly, the probability of the transformer being
unavailable in this particular case is only 0.000457%. The expected unserved energy at
MBTS is therefore less than 0.1 MWh in 2019 and this is estimated to have a value to
consumers of around $6,500 (based on a value of customer reliability of $65,687/MWh). 2
Full switching of the hot spare transformer with new 220 kV and 66 kV circuit breakers would
eliminate this risk but this is estimated to cost around $1,800,000 so it would not be
economic to carry out this work during the 10 year planning horizon.




1
        In this report, “major transformer outage” means an outage that has a mean duration of 2.6 months.
2
        The value of unserved energy is derived from the sector values given in Table 1 of section 2.3, weighted
        in accordance with the composition of the load at this terminal station.


                                                                                                    Page 2 of 2
2010 Transmission Connection Planning Report                                                                              Risk Assessment: MTS 22 kV


MALVERN 22 kV TERMINAL STATION (MTS 22 kV)

Magnitude, probability and impact of loss of load

MTS 22 kV is the source of supply for over 13,000 customers in Burwood, Ashwood, Glen Iris,
Mount Waverley and Surrey Hills. The station used to have three 45/55 MVA 220/22 kV
transformers which were over 55 years old. In 2007 the asset owner, SPI PowerNet, replaced
aged transformers and switchgear including protection and control equipment at the station.
The project was part of SPI PowerNet’s asset replacement program, and included replacement
of the three existing 45/55 MVA 220/22 kV transformers with two brand new 40/60 MVA
66/22 kV transformers. These transformers are supplied from existing 140/225 MVA 220/66 kV
transformers at MTS (refer also to the Risk Assessment for MTS 66 kV).

In addition to asset replacement works at MTS 22 kV by SPI PowerNet, two major 22 kV to
66 kV conversion projects initiated by United Energy Distribution (UED) on its network, resulted
in load transfers from MTS 22 kV to MTS 66 kV being commenced in 2001. The reduction in
station summer maximum demand from 89.3 MVA in 2001 to 43.8 MVA in 2009, shown in the
graph below, is attributed to the conversion works by UED. In addition to historical summer
maximum demands, the graph depicts the 10th and 50th percentile summer maximum demand
forecast together with the station’s operational N rating (all transformers in service) and the N-1
rating at 35°C as well as 40°C ambient temperature.


                                                          MTS 22kV Summer Peak Forecasts
         160.0



         140.0


                        (N) Rating @ 35 deg C
         120.0
                        (N) Rating @ 40 deg C

         100.0
                                                                             Actual          Forecast
   MVA




                                                                                                                (N-1) Rating @ 35 deg C
          80.0
                                                                                                                (N-1) Rating @ 40 deg C
                                                                                                                                            10% PoE
          60.0



          40.0

                                                                                                        50% PoE
          20.0



           0.0
                 2001    2002   2003   2004     2005   2006   2007   2008   2009   2010   2011   2012    2013   2014   2015   2016   2017    2018   2019   2020
                                                                                      Year



On the present forecasts it is projected that demand at MTS 22 kV will remain well within the
N-1 thermal rating of the new 45/55 MVA 220/22 kV transformers over the next ten years, as
shown above. Hence, the need for augmentation of transmission connection assets at MTS
22kV is not expected to arise over the next decade.




                                                                                                                                                      Page 1 of 1
2010 Transmission Connection Planning Report                                                                          Risk Assessment: MTS 66 kV


MALVERN 66 kV TERMINAL STATION (MTS 66 kV)

Magnitude, probability and impact of loss of load

MTS 66 kV is the main source of supply for over 59,700 customers in Elsternwick, Caulfield,
Carnegie, Malvern East, Ashburton, Chadstone, Oakleigh, Ormond, Murrumbeena,
Hughesdale and Bentleigh East. The station used to have three 45/55 MVA 220/66 kV
transformers which were over 50 years old. In 2007 the asset owner, SPI PowerNet,
replaced aged transformers and switchgear including protection and control equipment at the
station. The project was part of SPI PowerNet’s asset replacement program, and included
replacement of the three existing 45/55 MVA 220/66 kV transformers with two brand new
140/225 MVA 220/66 kV transformers. These transformers support the demand of both
66 kV and 22 kV networks ex MTS (refer also to the Risk Assessment for MTS 22 kV).

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational N rating (all transformers in service) and the N-1 rating
at 35°C as well as 40°C ambient temperature.



                                                     MTS 66kV Summer Peak Forecasts
        550.0
                                                                             N Rating @ 35 deg C

        500.0                                                                 N Rating @ 40 deg C


        450.0


        400.0


        350.0                                                                                                                10% PoE
  MVA




        300.0
                                                                        N -1 Rating @ 35 deg C

        250.0
                                                                    N -1 Rating @ 40 deg C

        200.0                                                                                             50% PoE


        150.0

                                                                           Actual          Forecast
        100.0


         50.0
                2001   2002   2003   2004   2005   2006   2007   2008     2009   2010   2011     2012   2013   2014   2015    2016     2017   2018   2019   2020
                                                                                    Year




The N rating on the chart indicates the maximum load that can be supplied from MTS 66 kV
with all transformers in service. Exceeding this level will initiate SPI PowerNet’s automatic
load shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.




                                                                                                                                              Page 1 of 5
2010 Transmission Connection Planning Report                                                                                   Risk Assessment: MTS 66 kV



                                                Annual Energy and Hours at Risk at MTS 66kV (Single Contingency Only)

                                               Hours at Risk (LH scale)          Energy at Risk MWh (LH scale)          Customer Value (RH scale)

                                  40                                                                                                                      $10,000




                                  30                                                                                                                      $7,500
    MWh at Risk / Hours at Risk




                                  20                                                                                                                      $5,000




                                  10                                                                                                                      $2,500




                                  0                                                                                                                       $0
                                        2011      2012          2013      2014       2015          2016          2017   2018        2019        2020
                                                                                            Year




Comments on Energy at Risk

For an outage of one transformer at MTS 66kV, there will be insufficient capacity at the
station to supply all demand at the 50th percentile temperature for about 5 hours in 2020.
The energy at risk under N-1 conditions is estimated at 30 MWh in summer 2020. The
estimated value to consumers of the 30 MWh of energy at risk is approximately $1.8 million
(based on a value of customer reliability of $59,948/MWh) 1 . In other words, at the 50th
percentile demand level, and in the absence of any other operational response that might be
taken to mitigate the impact of a forced outage, a major outage of one transformer at MTS 66
kV over the summer of 2020 would be anticipated to lead to involuntary supply interruptions
that would cost consumers $1.8 million.

It is emphasised however, that the probability of a major outage of one of the three
transformers occurring over the year is very low at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (30 MWh in 2020) is weighted by this low unavailability, the expected unserved energy is
estimated to be around 0.1 MWh. This expected unserved energy is estimated to have a
value to consumers of around $7,700 (based on a value of customer reliability of
$59,948/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2020 is estimated to be 235 MWh. The estimated value to consumers of this
energy at risk in 2020 is approximately $14.1 million. The corresponding value of the
expected unserved energy is around $60,800.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

1
                                       The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
                                       in accordance with the composition of the load at this terminal station.


                                                                                                                                                    Page 2 of 5
2010 Transmission Connection Planning Report                        Risk Assessment: MTS 66 kV


                                                            MWh         Valued at consumer
                                                                         interruption cost
Energy at risk, at 50th percentile demand forecast            30             $1.8 million

Expected unserved energy at 50th percentile demand            0.1              $7,700

Energy at risk, at 10th percentile demand forecast           235            $14.1 million

Expected unserved energy at 10th percentile demand            1.0             $60,800


If one of the 220/66 kV transformers at MTS 66 kV is taken off line during peak loading times
and the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is
operated by SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe
loading limits. Any load reductions that are in excess of the minimum amount required to
limit load to the rated capability of the station would be restored at zone substation feeder
level in accordance with United Energy’s operational procedures after the operation of the
OSSCA scheme.

In the case of MTS 66 kV supply at maximum loading periods, and based on the Schedule of
Priority Load Shedding recommended by the Demand Reduction Committee, the OSSCA
scheme would shed about 65 MVA of load, affecting approximately 26,500 customers in
2011.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement a contingency plan to transfer load to adjacent terminal stations. United
   Energy Distribution has established and implemented the necessary plans that enable
   load transfers under contingency conditions, via both 66 kV subtransmission and 22 kV
   distribution networks.

2. Install a third 140/225 MVA 220/66 kV transformer at MTS 66 kV.

3. Demand Side Management: United Energy Distribution has developed a number of
   innovative network tariffs that encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and
   the subsequent change in load pattern, and will be taken into consideration when
   determining the optimum timing for any future capacity augmentation.

4. Embedded generation, in the order of 30 MVA, connected to the network supplied by
   MTS 66 kV bus, will help to defer the need for augmentation at MTS 66 kV by one year.




2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre


                                                                                 Page 3 of 5
2010 Transmission Connection Planning Report                                    Risk Assessment: MTS 66 kV


Preferred network option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at MTS 66 kV, it is proposed to:

1. Install a third 140/225 MVA 220/66 kV transformer at MTS 66kV.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at MTS 66 kV under critical loading conditions:

        •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

        •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
            impact on customers of any automatic load shedding that may take place; and

        •   Subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
            metropolitan areas (refer to Section 4.5), this spare transformer can be used to
            temporarily replace the failed transformer.

On the present forecasts an additional 220/66 kV transformer is not likely to be required
within the ten year planning horizon. The capital cost of installing a 220/66 kV transformer at
MTS 66 kV is estimated to be $16 million. The cost of establishing, operating and
maintaining a new transformer would be recovered from network users through network
charges, over the life of the asset. The estimated total annual cost of this network
augmentation is approximately $1.6 million. This cost provides a broad upper bound
indication of the maximum network support payment which may be available to embedded
generators or customers to reduce forecast demand, and to defer or avoid the transmission
connection component of this augmentation. 4 Any non-network solution that defers this
augmentation for say 1-2 years, will not have as much potential value (and contribution
available from distributors) as a solution that eliminates or defers the augmentation for, say,
10 years. Sections 1.4 and 1.5 of this report provide further background information to
proponents of non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.


                                                                                                Page 4 of 5
2010 Transmission Connection Planning Report                                     Risk Assessment: MTS 66 kV


MALVERN TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                United Energy Distribution (100%)
Station operational rating (N elements in service):              526 MVA via 2 transformers (Summer peaking)
Summer N-1 Station Rating:                                       263 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       303 MVA


Station: MTS 66 kV                                           2011        2012        2013       2014        2015        2016       2017         2018        2019        2020

50th percentile Summer Maximum Demand (MVA)                 222.9       227.7      235.7       242.1       244.7      251.0       256.7       260.7        266.9       272.8
Summer % Overload [See Note 2 below]                           Nil         Nil         Nil        Nil         Nil         Nil        Nil          Nil        1%           4%
50th percentile Winter Maximum Demand (MVA)                 174.7       177.5      177.5       177.8       178.7      182.9       185.6       187.9        190.7       193.5
Winter % Overload [See Note 2 below]                           Nil         Nil         Nil        Nil         Nil         Nil        Nil          Nil         Nil         Nil
Annual energy at risk (MWh) [See Note 3 below]                   0           0          0           0           0          0           0           0            7          30
Annual hours at risk [See Note 4 below]                          0           0          0           0           0          0           0           0            3           5
Expected annual unserved energy (MWh) [See Note 5
below]                                                         0.0         0.0        0.0         0.0        0.0         0.0         0.0         0.0         0.0          0.1

Expected Annual Unserved Energy value [See Note 6
below]                                                          $k         $k          $k          $k         $k          $k          $k          $k       $1.8k       $7.7k


Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                    Page 5 of 5
2010 Transmission Connection Planning Report                           Risk Assessment: MWTS



MORWELL TERMINAL STATION (MWTS) 66 kV (MWTS 66 kV)

Morwell Terminal Station 66 kV is supplied by three 150 MVA 220/66 kV transformers and
by Morwell Power Station (MPS) generators via three 11/66 kV transformers. MWTS 66 kV
is the main source of supply for a major part of south-eastern Victoria including Gippsland
and spanning from Phillip Island, Wonthaggi, Leongatha in the west; to Moe and Traralgon
in the central area; to Omeo in the north; and to Bairnsdale and Mallacoota in the east.

Magnitude, probability and impact of loss of load

MWTS 66 kV is a summer peaking station which reached 457 MW (485 MVA) in January
2009. The recorded peak demand in summer 2010 was 422 MW (442 MVA), which was
approximately 35 MW lower than the 2009 peak. This is attributed to the comparatively mild
weather conditions observed during summer 2010.

Growth in peak demand at MWTS 66 kV has averaged around 12 MW (3%) per annum over
the last 5 years and is forecast to continue at this level for the next few years.

MWTS 66 kV is loaded above the “N-1” station rating in summer. Assessment of the energy
at risk at MWTS 66 kV needs to take into account the generation from Morwell Power
Station (MPS) which is connected to the MWTS 66 kV bus via 11/66 kV transformers. MPS
output directly offsets the loading and risk for the three 220/66 kV transformers at MWTS.
The MPS generation connected to the 66 kV bus comprises three generating units of
approximately 25 MVA capacity that operate essentially continuously. There are times when
one unit is taken out for maintenance or when plant operates at reduced power output.
Typically however, the units contribute between 50 and 80 MVA but for risk assessment
purposes a contribution of 50 MVA is assumed as MPS rarely contributes less than this.
Similarly, the generation output from 2X40 MVA units installed at the Bairnsdale Power
Station also contributes to reducing the loading levels of the three 220/66 kV transformers at
MWTS.

The “N–1” and “N” ratings shown on the graph below include the transformer capacity as
well as the assumed 50 MVA contribution from MPS. For example the 364 MVA “N–1”
rating includes the 314 MVA capacity of two 220/66kV transformers and 50 MVA from MPS.
The graph also shows the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service plus 50 MVA
from MPS) and the “N-1” rating at an ambient temperature of 35°C. The N rating on the
chart indicates the maximum load that can be supplied from MWTS 66 kV with all
transformers in service.

The graph below shows that loading at MWTS is expected to exceed the station’s N rating in
summer 2016, if all the generation contribution available from both Morwell and Bairnsdale
Power Stations is not taken into account. However, when the maximum output from both
Morwell and Bairnsdale Power Stations is included, there would be no energy at risk at
MWTS up to 2014 under N-1 conditions. On the other hand, with the winther forecast
demand growth rates, MWTS 66 kV is not expected to reach its “N-1” winter station rating
until 2020.




                                                                                    Page 1 of 6
2010 Transmission Connection Planning Report                                                                                                             Risk Assessment: MWTS




                                                         MWTS 66 kV Summer Peak Forecasts excluding BPS generation
                                 700.0


                                 650.0


                                 600.0

                                                         (N) Rating @ 35 deg C (includes 478 MVA for transformers and 50 MVA for MPS)
                                 550.0

                                                                                      10% Weather Probability Forecast
                                 500.0
                                                                                                                                                50% Weather Probability Forecast
  MVA




                                 450.0


                                 400.0
                                                                                                                                  N-1 rating after replacing faulty B1 transformer

                                 350.0                                                   (N-1) Rating @ 35 deg C (includes 314 MVA for transformers and 50 MVA for MPS)


                                 300.0
                                                                                              Actuals                  Forecasts

                                 250.0
                                         2002   2003   2004   2005      2006   2007   2008    2009      2010    2011   2012   2013      2014    2015    2016    2017   2018   2019   2020
                                                                                                                Year




The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.

                                                         Annual Energy and Hours at Risk at MWTS 66 kV (Single Contingency Only)

                                            Hours at Risk (LH scale)             Energy at Risk MWhrs (LH scale)                    Customer Value (RH scale)

                                 80000                                                                                                                                        $33,000,000


                                                                                                                                                                              $29,700,000


                                                                                                                                                                              $26,400,000


                                                                                                                                                                              $23,100,000
  MWhr at Risk / Hours at Risk




                                                                                                                                                                              $19,800,000


                                                                                                                                                                              $16,500,000


                                                                                                                                                                              $13,200,000


                                                                                                                                                                              $9,900,000


                                                                                                                                                                              $6,600,000


                                                                                                                                                                              $3,300,000


                                     0                                                                                                                                        $0
                                            2011       2012            2013       2014          2015           2016        2017          2018          2019        2020
                                                                                                        Year




                                                                                                                                                                               Page 2 of 6
2010 Transmission Connection Planning Report                                        Risk Assessment: MWTS



Comments on Energy at Risk (Assuming Bairnsdale Power Station 1 is not
available and Morwell Power Station output is 50 MVA)

For an outage of one transformer at MWTS 66 kV over the entire summer period, there will
be insufficient capacity at the station to supply all demand at the 50th percentile temperature
for about 151 hours in summer 2010/11. The energy at risk under N-1 conditions is
estimated to be 4,183 MWh in summer 2010/11. The estimated value to consumers of the
4,183 MWh of energy at risk is approximately $276 million (based on a value of customer
reliability of $65,992/MWh). 2 In other words, at the 50th percentile demand level, and in the
absence of any other operational response that might be taken to mitigate the impact of a
forced outage, a major outage of one transformer at MWTS 66 kV over the summer of
2010/11 would be anticipated to lead to involuntary supply interruptions that would cost
consumers $276 million.

It is emphasised however, that the probability of a major outage of one of the three
transformers occurring over the year is very low, at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (4,183 MWh for summer 2010/11) is weighted by this low unavailability, the expected
unsupplied energy is estimated to be 27.2 MWh. This expected unserved energy is
estimated to have a value to consumers of around $1.8 million, (based on a value of
customer reliability of $65,992/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2010/11 is estimated to be 6,890 MWh. The estimated value to
consumers of this energy at risk in 2010/11 is approximately $454.7 million. The
corresponding value of the expected unserved energy is approximately $2.96 million.

These key statistics for the year 2011 under N-1 outage conditions are summarised in the
table below.

                                                                       MWh           Valued at consumer
                                                                                      interruption cost
Energy at risk, at 50th percentile demand forecast                    4,183               $276 million

Expected unserved energy at 50th percentile demand                     27.2                $1.8 million

Energy at risk, at 10th percentile demand forecast                    6,890              $454.7 million

Expected unserved energy at 10th percentile demand                     44.9               $2.96 million

If one of the 220/66 kV transformers at MWTS is taken off line during peak loading times and
the “N-1” station rating is exceeded, then the Overload Shedding Scheme for Connection
Assets (OSSCA) which is operated by SPI PowerNet’s TOC 3 to protect the connection

1
        Bairnsdale Power Station is contracted to be available to provide network support over the night-time
        hot water demand peak at an output of up to 40 MVA but frequently generates up to its maximum output
        of 80 MVA during the summer period.
2
        The value of unserved energy is derived from the sector values given in Table 1 of section 2.3, weighted
        in accordance with the composition of the load at this terminal station.
3
        Transmission Operation Centre.



                                                                                                    Page 3 of 6
2010 Transmission Connection Planning Report                                    Risk Assessment: MWTS



assets from overloading 4 , will act swiftly to reduce the load in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load
to the rated capability of the station would be restored at zone substation feeder level in
accordance with SPI Electricity’s operational procedures after the operation of the OSSCA
scheme. If OSSCA operates at MWTS, it would shed about 110 MVA of load, affecting
approximately 46,000 customers.

Comments on Energy at Risk assuming Bairnsdale Power Station is available

The previous comments on the energy at risk are based on the assumption that there is only
50 MVA of generation from Morwell Power Station and no other embedded generation
available to offset the 220/66 kV transformer loading. As already noted, Morwell Power
Station usually generates more than 50 MVA and often as much as 80 MVA.

The Bairnsdale Power Station (BPS) is contracted to be available to provide network support
over the night-time hot water demand peak at an output of up to 40 MVA but frequently
generates up to its maximum output of 80 MVA during the summer period. In practice this
embedded generation reduces the energy at risk over the summer period to much lower
levels than indicated above. If there was a major transformer failure it should be possible to
ensure additional generation is available over the peak period to minimise any load shedding
required.

There is no firm commitment that generation will be available to offset transformer loading at
MWTS; however it is most likely that the times of peak demand at MWTS will coincide with
the periods of high wholesale electricity prices, resulting in a high level of certainty that BPS
will be generating. With BPS and MPS generation available to its full potential there would
be no energy at risk at MWTS up to 2014.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Establish a new terminal station in or adjacent to the supply area of MWTS. A
   strategically selected location for a new terminal station could allow load to be
   transferred away from MWTS. Studies of electricity supply options for the Pakenham
   area currently supplied from Cranbourne Terminal Station propose the establishment of
   a new terminal station near Tynong, Pakenham or Nar Nar Goon in the next 5 to 10
   years. This option would allow some MWTS load in West Gippsland to be transferred
   away from MWTS.

2. Embedded generation: Bairnsdale Power Station normally provides 20 MVA over the
   night time peak but it can be called upon to provide up to 40 MVA at any time, and if
   available up to 80 MVA can be sought. The Morwell Power Station may also be able to
   increase output in the event of a transformer failure.




4
  OSSCA is designed to protect against transformer damage caused by overloads. Damaged transformers can
take months to replace which can result in prolonged, long term risks to reliability of customer supply.




                                                                                              Page 4 of 6
2010 Transmission Connection Planning Report                                        Risk Assessment: MWTS



3. Install a fourth 220/66 kV transformer at MWTS: Installation of a 4th transformer at
   MWTS is a technically feasible option. However, fault level constraints would make such
   a solution costly to implement.

4. Installation of Power Factor Correction Capacitors: The station is currently running with
   a power factor of around 0.95 at the summer peak. At this power factor level, the use of
   additional capacitors to further improve power factor and to reduce the MVA loading will
   bring only marginal benefits.

Preferred network option(s) for alleviation of constraints

The preferred options for alleviation of transformer loading constraints are:

1. Continue to ensure that an adequate level of the existing embedded generation (Morwell
   Power Station and Bairnsdale Power Station) is available in case of a major transformer
   failure. (As already noted, SPI Electricity has entered into a network support agreement
   with Bairnsdale Power Station for up to 40 MVA of support.)

2. Depending on the electricity supply option chosen for the supply area adjacent to CBTS
   and MWTS, there is a strong possibility of transferring some load to a new terminal
   station so as to offload MWTS.

3. Install a new fourth 220/66 kV transformer at MWTS. Installation of a fourth transformer
   at MWTS as soon as possible is economic, ignoring any contribution from embedded
   generation. However, taking into consideration the generation contribution which is
   available on ongoing basis, installation of a fourth transformer can be deferred by at
   least one year from 2013/14. With all embedded generation available, all demand can
   be met until summer 2014/15 with one transformer out of service.

4. Subject to the availability of the SPI PowerNet spare 220/66kV transformer for rural
   areas (refer section 4.5), this spare transformer can be used to temporarily replace a
   failed transformer.

The capital cost of installing a new fourth 220/66 kV 150 MVA transformer at MWTS is
estimated to be $15 million, including some additional cost of the works required to mitigate
fault levels. The cost of establishing, operating and maintaining the transformer would be
recovered from network users through network charges, over the life of the asset. The
estimated total annual cost of this network augmentation is approximately $1.5 million. This
cost provides a broad upper bound indication of the maximum network support payment
which may be available 5 to embedded generators or customers to reduce forecast demand
and defer or avoid the transmission connection augmentation. Any non-network solution that
defers this augmentation for say 1-2 years, will not have as much potential value (and
contribution available from distributors) as a solution that eliminates or defers the
augmentation for say 10 years. Section 1.5 of this report provides further background
information to proponents of non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy for both the summer and winter
periods.
5
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers   (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.




                                                                                                    Page 5 of 6
2010 Transmission Connection Planning Report                                           Risk Assessment: MWTS




MORWELL TERMINAL STATION 66kV (MWTS 66 kV)
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:   SPI Electricity (100%)
Normal cyclic rating with all plant in service      668 MVA via 3 transformers and Morwell Power Station
Summer N-1 Station Rating (MVA):                    364 MVA via 2 transformers and MPS
Winter N-1 Station Rating (MVA):                    457 MVA via 2 transformers and MPS

Station: MWTS 66kV                                        2011        2012        2013         2014         2015     2016      2017         2018         2019         2020
50th percentile Summer Maximum Demand (MVA)              456.1        468.8       490.6       500.3        515.9     530.7     546.2        560.7       579.2         597.8
Summer % Overload [See Note 2 below]                     25.3%       28.8%       34.8%       37.5%         41.7%    45.8%     50.1%        54.1%       59.1%         64.2%
50th percentile Winter Maximum Demand (MVA)              413.4        416.9       420.4       425.7        431.0     436.4     441.9        447.5       453.2         458.9
Winter % Overload [See Note 2 below]                        Nil          Nil        Nil          Nil         Nil       Nil       Nil          Nil          Nil           Nil
Annual energy at risk (MWh) [See Note 3 below]          4182.8       6107.7    10658.5      13413.4    18840.8     25307.9   33826.7     43370.2      57841.1       75071.6

Annual hours at risk [See Note 4 below]                  151.0        206.3       314.1       387.0        497.5     648.7     817.7        970.2      1207.1        1430.5
Expected Annual Unserved Energy (MWh) [See
                                                        27.2       39.7       69.3       87.2      122.5       164.5       219.9       281.9       376.0       488.0
Note 5 below]
Expected Annual Unserved Energy value [See Note 6
                                                  $1,794,199 $2,619,897 $4,571,966 $5,753,697 $8,081,766 $10,855,864 $14,509,978 $18,603,668 $24,810,983 $32,202,015
below]



Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage with
    a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1of section 2.3, weighted in accordance with the composition of the load at this terminal
    station




                                                                                                                                                                 Page 6 of 6
2010 Transmission Connection Planning Report                                                                  Risk Assessment: RCTS 22kV



RED CLIFFS TERMINAL STATION (RCTS) 22kV

Red Cliffs Terminal Station (RCTS) 22 kV consists of two 35 MVA 235/66/22 kV
transformers supplying the 22 kV network ex-RCTS. Powercor installed an additional
140 MVA 235/66/22 kV transformer in 2006. Due to fault level limitations at RCTS 22 kV,
the new transformer operates normally open on the 22 kV bus with an auto-close scheme to
close the new transformer onto the 22 kV bus in the event of a failure of either of the other
two transformers. This configuration is the main source of supply for 6,200 customers in
Red Cliffs and the surrounding area. The station supply area includes Red Cliffs, Colignan
and Werrimull.

Magnitude, probability and impact of loss of load

Growth in summer peak demand on the 22 kV network at RCTS has averaged around
0.7 MW (1.9%) per annum over the last 5 years. The peak load for the 22 kV network on the
station reached 36.5 MW in summer 2010.

As noted above, the new 140 MVA 235/66/22 kV transformer (installed in 2006) operates
normally open on the 22 kV bus with an auto-close scheme to close the new transformer
onto the 22 kV bus in the event of a failure of either of the other two transformers. The
installation of the new 140 MVA 235/66/22 kV transformer and the implementation of the
auto-close scheme resulted in the station’s “N-1” capacity increasing, as shown in the graph
below. The N rating at the station increased in 2005 due to the replacement of the 22 kV
transformer circuit breakers but was not affected by the new transformer, given the normal
operating configuration of the transformers at the station.

RCTS 22 kV demand is summer peaking. The graph below depicts the 10th and 50th
percentile summer maximum demand forecast together with the station’s operational “N”
rating (all transformers in service) and the “N-1” rating at 35°C ambient temperature.
                                                          RCTS 22kV Summer Peak Forecasts


        70.0

                                                Actuals             Forecasts                  10% Weather Probability Forecast

                                                                                                                                  (N-1) Rating @ 35 deg C
        60.0
                                                                                                                                  (N) rating @ 35 deg C

        50.0

               (N) rating @ 35 deg C

        40.0
                                                                                                              50% Weather Probability
  MVA




                                                                                                              F     t

        30.0



               (N-1) Rating @ 35 deg C
        20.0



        10.0



         0.0
               2005    2006     2007     2008    2009       2010   2011   2012          2013   2014    2015     2016    2017        2018     2019     2020
                                                                                 Year




The chart shows there is sufficient capacity at the station to supply all expected load over
the forecast period, even with one transformer out of service. Therefore, the need for
augmentation or other corrective action is not expected to arise over the next ten years.



                                                                                                                                              Page 1 of 1
2010 Transmission Connection Planning Report                                                             Risk Assessment: RCTS 66kV



RED CLIFFS TERMINAL STATION (RCTS) 66kV

Magnitude, probability and impact of loss of load

Red Cliffs Terminal Station (RCTS) 66 kV consists of two 70 MVA and one 140 MVA
235/66/22 kV transformers supplying the 66 kV network ex-RCTS. This configuration is the
main source of supply for 25,800 customers in Red Cliffs and the surrounding area. The
station supply area includes Merbein, Mildura, Robinvale and Ouyen.

Magnitude, probability and impact of loss of load

RCTS 66 kV demand is summer peaking. Growth in summer peak demand on the 66 kV
network at RCTS has averaged around 11.7 MW (6.9%) per annum over the last 5 years.
The peak load for the 66 kV network on the station reached 169.7 MW in summer 2010.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N-1”
rating at 35°C ambient temperature.

The load forecast includes a transfer of load from RCTS 66 kV to Wemen Terminal Station
(WETS) when WETS is commissioned in 2011.

                                                           RCTS 66kV Summer Peak Forecast

        350.0


                         (N) rating @ 35 deg C
        300.0
                                                 Actuals             Forecasts


        250.0



        200.0                                                                                       10% Weather Probability Forecast
  MVA




                       (N-1) Rating @ 35 deg C
        150.0


                                                                                                            50% Weather Probability Forecast
        100.0



         50.0



          0.0
                2005   2006    2007     2008       2009     2010   2011   2012      2013   2014   2015    2016    2017     2018        2019   2020
                                                                                 Year




The (N) rating on the chart indicates the maximum load that can be supplied from RCTS with
all transformers in service. Exceeding this level will initiate automatic load shedding by
SPI PowerNet’s automatic load shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.



                                                                                                                                        Page 1 of 5
2010 Transmission Connection Planning Report                                                                                    Risk Assessment: RCTS 66kV




                                                                    Annual Energy and Hours at Risk at RCTS66kV

                                                          Hours at risk (LH Scale)   Energy at risk (MWh) (LH Scale)   Customer Value (RH Scale)

                                 1000                                                                                                                     $400,000


                                  900
                                                                                                                                                          $350,000

                                  800
                                                                                                                                                          $300,000
                                  700
    MWhr at Risk/Hours at Risk




                                                                                                                                                          $250,000
                                  600


                                  500                                                                                                                     $200,000


                                  400
                                                                                                                                                          $150,000

                                  300
                                                                                                                                                          $100,000
                                  200

                                                                                                                                                          $50,000
                                  100


                                    0                                                                                                                     $0
                                           2011    2012          2013         2014     2015          2016       2017     2018        2019          2020
                                                                                              Year

Comments on Energy at Risk

For a major outage of one transformer at RCTS, there will be insufficient capacity at the
station to supply all demand at the 50th percentile temperature for about 104 hours in 2011.
The energy at risk at the 50th percentile temperature under N-1 conditions is estimated to be
927 MWh in 2011. The estimated value to consumers of the 927 MWh of energy at risk in
2011 is approximately $58 million (based on a value of customer reliability of
$62,639/MWh) 1 . In other words, at the 50th percentile demand level, and in the absence of
any other operational response that might be taken to mitigate the impact of a forced outage,
a major outage of one transformer at RCTS in 2011 would be anticipated to lead to
involuntary supply interruptions that would cost consumers $58 million.

It is emphasised however, that the probability of a major outage of one of the three
transformers occurring over the year is very low (0.217% per transformer). When the energy
at risk (927 MWh for 2011) is weighted by this low probability, the expected unsupplied
energy is estimated to be around 6.0 MWh in 2011. This expected unserved energy is
estimated to have a value to consumers of around $377,000 in 2011 (based on a value of
customer reliability of $62,639/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2011 is estimated to be 1740.2 MWh and the energy at risk in
2020 is estimated to be 14.3 MWh. The estimated value to consumers of this energy at risk
in 2011 is approximately $109 million and in 2020 is approximately $0.9 million. The
corresponding value of the expected unserved energy is $708,500 in 2011 and $5,800 in

1
                                        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3,
                                        weighted in accordance with the composition of the load at this terminal station.



                                                                                                                                                          Page 2 of 5
2010 Transmission Connection Planning Report                        Risk Assessment: RCTS 66kV



2020. There is sufficient capacity to meet 10th percentile demand with all plant in service
until 2020.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                            MWh          Valued at consumer
                                                                          interruption cost
Energy at risk, at 50th percentile demand forecast              0                 $0

Expected unserved energy at 50th percentile demand              0                 $0

Energy at risk, at 10th percentile demand forecast           14.3             $0.9 million

Expected unserved energy at 10th percentile demand            0.1               $5,826



If one of the 235/66/22 kV transformers at RCTS is taken off line during peak loading times
and the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is
operated by SPI PowerNet’s TOC 3 will act swiftly to reduce the loads in blocks to within safe
loading limits. Any load reductions that are in excess of the minimum amount required to
limit load to the rated capability of the station would be restored at zone substation feeder
level in accordance with Powercor’s operational procedures after the operation of the
OSSCA scheme.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

•        Implement a contingency plan to transfer load from the RCTS 66 kV bus to the
         RCTS 22 kV bus by utilising 22 kV system ties and to transfer load from RCTS 66
         kV bus to WETS using 66 kV system ties.

•        Installation of an additional 140 MVA 235/66/22 kV transformer at RCTS.

•        Demand reduction: There is an opportunity to develop a number of innovative
         customer schemes to encourage voluntary demand reduction during times of
         network constraint. The amount of demand reduction depends on the customer
         uptake and would be taken into consideration when determining the optimum timing
         for the capacity augmentation.

•        Embedded generation, connected to the RCTS 66 kV bus, may defer the need for
         capacity augmentation at RCTS.




2
        Overload Shedding Scheme of Connection Asset.
3
        Transmission Operation Centre.



                                                                                       Page 3 of 5
2010 Transmission Connection Planning Report                    Risk Assessment: RCTS 66kV



Preferred option(s) for alleviation of constraints

A contingency plan will be developed to transfer load from the RCTS 66 kV bus to the
RCTS 22 kV bus using 22 kV system ties and, when WETS is commissioned, from the
RCTS 66 kV bus to WETS using 66 kV system ties. This will reduce the amount of load
shedding that may be required in the event that a transformer failure occurs. Prior to WETS
being commissioned the contingency plan to transfer load to the RCTS 22 kV bus will
reduce the energy at risk to an estimated 253 MWh in 2011. The corresponding expected
unserved energy is estimated to be 1.6 MWh with an estimated value to customers of
approximately $103,000 in 2011.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                 Page 4 of 5
2010 Transmission Connection Planning Report                                    Risk Assessment: RCTS 66kV



Red Cliffs Terminal Station 66kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                 Powercor (100%)
                                                                  MW      MVA
Normal cyclic rating with all plant in service                            311 via 3 transformers
Summer N-1 Station Rating:                                        150     160 [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                        186     192

Station: RCTS 66kV                                        2010          2011       2012       2013        2014        2015        2016         2017        2018        2019

50th percentile Summer Maximum Demand (MVA)               189.5         140.9     144.1      147.3       150.4        146.3       149.5       152.7       156.0       159.4
Summer % Overload [See Note 2 below]                       18.4           Nil        Nil        Nil         Nil          Nil         Nil         Nil         Nil         Nil
50th percentile Winter Maximum Demand (MVA)                89.7          91.5      93.3       95.1         96.9        95.5        97.3        99.2       101.2       103.2
Winter % Overload [See Note 2 below]                        Nil           Nil        Nil        Nil         Nil          Nil         Nil         Nil         Nil         Nil
Annual energy at risk (MWh) [See Note 3 below]            927.0           0.0        0.0        0.0         0.0         0.0         0.0         0.0          0.0         0.0
Annual hours at risk [See Note 4 below]                   103.8           0.0       0.0         0.0         0.0         0.0         0.0         0.0          0.0         0.0
Expected Annual Unserved Energy (MWh) [See
                                                            6.0           0.0       0.0         0.0         0.0         0.0         0.0         0.0          0.0         0.0
Note 5 below]
Expected Annual Unserved Energy valued in
accordance with the value of customer reliability in
                                                       $377,425           $0         $0         $0          $0           $0          $0          $0          $0          $0
September 2009 as advised by AEMO [See Note 6
below]

Notes:
1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.   This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3.   “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4.   “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5.   “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
     with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
     station.




                                                                                                                                                                    Page 5 of 5
2010 Transmission Connection Planning Report                                                   Risk Assessment RTS 22kV



RICHMOND TERMINAL STATION 22 kV (RTS 22 kV)

RTS 22 kV is a summer critical station equipped with two 165 MVA 220/22 kV transformers,
providing supply to CitiPower’s distribution network. The terminal station’s supply area includes
inner suburban areas in Richmond and Prahran and Melbourne City’s Russell Place and
surrounding areas. The station also provides supply to City Link and public transport railway
substations east of the Central Business District. Due to uneven load sharing between the two
22 kV buses at RTS, the N rating is only slightly higher than the N-1 rating. The N-1 ratings are
restricted by over-voltage limits on transformer tapping. A line drop compensator however, limits
the overall 22 kV transformation output to 141 MVA for both summer and winter.

Magnitude, probability and impact of loss of load

The graph below depicts the latest 10% and 50% probability maximum demand forecasts during
the summer periods over the next ten years, together with the operational N and N-1 ratings for
RTS 22 kV. The demand forecasts include the effects of future load transfer works that have been
committed.



                                    RTS 22kV Summer Peak Forecasts
                        N Rating @ 35 deg C & 40 deg C
           140          N-1 Rating @ 35 DegC

                        N -1 Rating @ 40 DegC
           120                                           10% Probability Demand
                                                         Forecasts


           100
     MVA




            80
                                                                        50% Probability Demand Forecasts

            60

                                        Actuals                   Forecasts

            40
                 2004      2006        2008       2010          2012       2014       2016        2018      2020
                                                                    Year


The graph shows there is sufficient station capacity to supply all anticipated load, and that no
customers would be at risk if a forced transformer outage occurred at RTS 22kV over the forecast
period. Accordingly, no capacity augmentation is planned at RTS 22kV over the next ten years.




                                                                                                   Page 1 of 1
2010 Transmission Connection Planning Report                                                Risk Assessment: RTS 66kV

RICHMOND TERMINAL STATION 66 kV (RTS 66 kV)

RTS 66 kV is a summer critical station consisting of four 150 MVA 220/66 kV transformers.
The terminal station is shared by CitiPower (91%) and United Energy Distribution (9%),
providing major supply to the Eastern Central Business District and wide-spread inner
suburban areas in the east and south-east of Melbourne, including Fitzroy, Collingwood,
Abbotsford, Richmond, North Richmond, Hawthorn, Camberwell, Gardiner, Toorak,
Armadale, South Yarra, St Kilda, Elwood and Balaclava.

Magnitude, probability and impact of loss of load

The graph below depicts the station’s operational N rating (for all transformers in service)
and the N-1 rating at 35 and 40 degrees, and the latest 10th and 50th percentile maximum
demand forecasts during summer periods over the next ten years. The forecast demands
include the effects of any future load transfer works that have been committed by DBs.



                                      RTS 66kV Summer Peak Forecasts
          800
                                                 10% Probability Demand Forecasts
          750
                       N Rating @ 35 deg C
          700
                       N Rating @ 40 DegC
          650

          600
    MVA




                                                                                 50% Probability Demand Forecasts
          550
                                              N-1 Rating @ 35 deg C
          500
                       N-1 Rating @ 40 DegC
          450

          400
                                   Actuals                     Forecasts

          350
                2004       2006        2008          2010         2012          2014       2016         2018        2020
                                                                         Year


The graph shows there would be insufficient capacity at RTS 66 kV to supply the forecast
10th percentile and 50th percentile demand by 2014 and 2018 respectively.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.




                                                                                                                Page 1 of 6
2010 Transmission Connection Planning Report                                                       Risk Assessment: RTS 66kV


                                                 Annual Energy and Hour at Risk and
                                                Expected Customer Value at RTS 66kV



                                      Hour at Risk          MWh at Risk            Consumer expected $ value (RH scale)



                             30,000                                                                               $25,000,000
        MWH & Hour at Risk




                             24,000                                                                               $20,000,000

                             18,000                                                                               $15,000,000

                             12,000                                                                               $10,000,000

                              6,000                                                                               $5,000,000

                                 0                                                                                $0
                                      2011   2012    2013    2014   2015    2016     2017   2018   2019   2020

                                                                          Year



Comments on Energy at Risk

For an outage of one transformer at RTS 66 kV during the summer period, it is expected that
there would be insufficient capacity to supply all demand at the 50th percentile temperature.

By 2014, the energy at risk at the 50th percentile temperature under N-1 conditions is
estimated to be 6,297 MWh. Under these conditions, there would be insufficient capacity to
meet demand for approximately 180 hours in that year. The estimated value to consumers
of this energy at risk in 2014 is approximately $547 million (based on a value of customer
reliability of $90,358 per MWh). 1 In other words, at the 50th percentile demand level, and in
the absence of any other operational response that might be taken to mitigate the impact of a
forced outage, a major outage of one transformer at RTS 66 kV over the summer of 2014
would be anticipated to lead to involuntary supply interruptions that would cost consumers
$547 million.

It is emphasised however, that the probability of a major outage of one of the four
transformers at RTS 66 kV occurring over the year is very low, at about 1.0% per transformer
per annum, whilst the expected unavailability per transformer per annum is 0.217%. When
the energy at risk in 2014 (6,297 MWh) is weighted by the low transformer unavailability, the
expected unserved energy is estimated to be around 54.7 MWh. This expected unserved
energy is estimated to have a value to consumers of approximately $4.9 million in 2014.

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year 2 . Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2014 is estimated to be 21,159 MWh. The estimated value to
consumers of this energy at risk in 2014 is approximately $1,912 million. The corresponding
value of the expected unserved energy is approximately $16.6 million.

1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
        in accordance with the composition of the load at this terminal station.
2
        As noted in Section 4.1, the 50th percentile demand forecast is used in each year.


                                                                                                                    Page 2 of 6
2010 Transmission Connection Planning Report                            Risk Assessment: RTS 66kV

These key statistics for the year 2014 under N-1 outage conditions are summarised in the
table below.

                                                                 MWh          Valued at consumer
                                                                               interruption cost
Energy at risk, at 50th percentile demand forecast              6,297              $569 million

Expected unserved energy at 50th percentile demand               54.7              $4.9 million

Energy at risk, at 10th percentile demand forecast             21,159             $1,912 million

Expected unserved energy at 10th percentile demand              183.7             $16.6 million



If one of the four transformers at RTS 66 kV is taken off line during peak loading times and
the N-1 station rating is exceeded, then the OSSCA 3 load shedding scheme which is
operated by SPI PowerNet’s NOC 4 will act swiftly to reduce the loads in blocks to within safe
loading limits. Any load reductions that are in excess of the minimum amount required to
limit load to the rated capability of the station would be restored after the operation of the
OSSCA scheme, at zone substation feeder level in accordance with CitiPower and United
Energy Distribution’s operational procedures.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Permanent load transfer from RTS 66 kV to the proposed BTS 66 kV (Brunswick
   Terminal Station) connection point. This is part of the integrated plan for the proposed
   BTS 66 kV (Refer to the Risk Assessment Report for BTS 66 kV) and could be achieved
   by:

    1.1     High voltage distribution load transfer from critical zone substations in the Central
            Business District areas supplied from RTS 66 kV to the upgraded zone substation
            supplied from the proposed BTS 66 kV commencing from 2014 5 (Refer to the
            Risk Assessment Report for WMTS 22 kV).

    1.2      Bulk subtransmission transfer of normal supply of a three-zone substation 66 kV
             subtransmission loop (about 130 MVA of load) from RTS 66 kV to the new BTS
             66 kV in 2015. The subtransmission loop to be transferred will then be re-
             arranged to form “Normal Open” 66 kV subtransmission ties between BTS 66 kV
             and RTS 66 kV in conjunction with the asset replacement program at RTS by the
             transmission connection asset owner, SPI PowerNet, in their current regulatory
             period ending 2015. The “Normal Open” 66 kV subtransmission ties will enhance
             the security of transmission connection points of supply by providing back-to-
             back capacity support between the two terminal stations.


3
        Overload Shedding Scheme of Connection Asset.
4
        Network Operation Centre.
5
        Subject to SPI PowerNet’s timely delivery of the required works. Any delays resulting from an
        unforeseen increase in SPI PowerNet’s project delivery lead times will be beyond the control of
        CitiPower.


                                                                                       Page 3 of 6
2010 Transmission Connection Planning Report                               Risk Assessment: RTS 66kV

     The new BTS 66 kV is programmed to be established by 2014 6 with the initial installation
     of two 220/66 kV transformers. This option with bulk subtransmission load transfer would
     require the advancement of the third transformer at BTS 66 kV to 2015 and the
     associated 66 kV subtransmission line works would have to be completed at the same
     time as the installation of the third transformer at BTS.

2. The transmission connection asset owner, SPI PowerNet, has indicated their intention to
   redevelop RTS by replacing all aged assets at RTS, including 220 kV switchgear,
   220/66 kV transformers and 66 kV switchgear, in their current regulatory period ending in
   2015. It will be a like-for-like asset replacement in terms of 220/66 kV transformation
   capacity. SPI PowerNet has indicated that it expects the asset replacement project at
   RTS 66 kV to be undertaken in 2015 7 , however firm plans and a program for the
   redevelopment works are not yet finalised.

     A feasible option to resolve the capacity constraint at RTS 66 kV would involve CitiPower
     and United Energy Distribution working closely with SPI PowerNet to install an additional
     220/66 kV transformer at RTS in conjunction with SPI PowerNet’s redevelopment
     program.

3.   Permanent transfer of supply of two zone substations (about 104 MVA of load in
     2014/15) from RTS 66 kV to MTS 66 kV (Malvern Terminal Station) connection point.

     In 2007, the asset owner, SPI PowerNet, redeveloped MTS 66 kV with two new
     140/225 MVA 220/66 kV transformers. This work was completed as part of SPI
     PowerNet’s asset replacement program (refer also to the Risk Assessment for MTS
     66 kV). This option would require a third transformer at MTS 66 kV and associated
     switchyard works together with 66 kV line works by 2014/15.

     Without this load transfer, the third transformer at MTS 66 kV will not be required for at
     least the next 10 years based on the current load forecasting profiles.

4.   Contingency plans could be put in place to transfer load to the adjacent terminal stations
     via the 66 kV subtransmission and 11 kV distribution networks. RTS 66 kV is equipped
     with higher 24-hour and 2-hour short time emergency ratings to allow excessive load to
     be transferred away within a short time frame under transformer outage contingency
     conditions. RTS and WMTS (West Melbourne Terminal Station) are interconnected at
     the subtransmission level on “Normal Open” condition via a 66 kV switching station in
     the Melbourne Central Business District. The magnitude of load that can be transferred
     to WMTS 66 kV is dependent on the available spare capacity of the WMTS transformers
     and the 66 kV subtransmission interconnecting network at the time of a transformer
     outage at RTS 66 kV.

5. Demand Reduction: United Energy Distribution has developed a number of innovative
   network tariffs to encourage voluntary demand reduction during times of network
   constraints. The amount of demand reduction depends on the tariff uptake and will be
   taken into consideration when determining the optimum timing for the capacity
   augmentation.




6
        Subject to SPI PowerNet’s timely delivery of the required works.
7
        This information was obtained from the 2010 Victorian APR.


                                                                                          Page 4 of 6
2010 Transmission Connection Planning Report                               Risk Assessment: RTS 66kV

6. Embedded generation in the order of 150 MVA, will help to defer the need for
   augmentation.

7. Establishment of a new terminal station in the inner eastern suburban area to provide an
   extra point of supply would resolve the overloading problem. Acquisition of a new
   terminal station site at a suitable location would be required for this option.

Preferred option(s) for alleviation of constraints

1. Implement the following measures to cater for an unplanned outage of one transformer at
   RTS 66 kV under critical loading conditions, until the major augmentation works
   described in point 2 below are completed in 2015:

    •   maintain contingency plans to transfer load via 66 kV subtransmission and 11 kV
        distribution networks to the adjacent terminal stations; and

    •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
        impact on customers of any load shedding that may take place.
    Subject to availability, installation of SPI PowerNet’s spare 220/66 kV transformer for
    metropolitan areas could be undertaken to temporarily replace a failed transformer at
    RTS 66 kV.

2. In the absence of any commitment by interested parties to offer network support services
   by installing local generation or through demand side management initiatives that would
   reduce load at RTS 66 kV, or any other better identified network solutions, it is proposed
   to reduce load from RTS 66 kV permanently by load transfer away to the new BTS 66 kV.
   This transfer will be done via both the high voltage distribution and subtransmission
   networks from 2014 8 and 2015 respectively, which is in line with the integrated plan for
   the establishment of the new BTS 66 kV supply point.


The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy. The table shows that in the period
prior to the planned transfer of load to the new BTS 66 kV supply point, there is load at risk at
RTS 66 kV. In addition to the measures outlined in paragraph 1 immediately above,
CitiPower would welcome proposals from proponents of non-network solutions to provide
network support services 9 to reduce the load at risk at RTS 66 kV over the period to 2014 –
2015. Proponents should contact Neil Gascoigne, System Planning & Secondary Systems
Manager, CitiPower / Powercor, on 9683 4472 for further details.




8
        Subject to SPI PowerNet’s timely delivery of the required works.
9
        A Rule change proposal is presently before the AEMC to enable distributors to make network support
        payments and to recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.


                                                                                          Page 5 of 6
2009 Transmission Connection Planning Report                                    Risk Assessment: RTS 66kV


     RICHMOND TERMINAL STATION 66 kV
     Detailed data: Magnitude and probability of loss of load
     Distribution Businesses supplied by this station:               CitiPower (89%); United Energy Distribution (11%)
     Station operational rating (N elements in service):             685 MVA via 4 transformers (Summer peaking)
     Summer N-1 Station Rating:                                      439 MW (491 MVA) [See Note 1 below for interpretation of N-1]
     Winter N-1 Station Rating:                                      521 MW (547 MVA)


Station: RTS 66kV
                                                            2011       2012        2013        2014        2015         2016        2017          2018          2019           2020
50th percentile Summer Maximum Demand (MVA)                 574.7      591.7       608.0       623.4       637.6        653.3       668.9         684.1         700.1          716.1
Summer % Overload [See Note 2 below]                       17.0%      20.5%       23.8%       27.0%        29.9%       33.0%       36.2%         39.3%         42.6%          45.9%
50th percentile Winter Maximum Demand (MVA)                 432.9      444.9       456.4       468.0       479.9        492.7       505.3         520.3         535.7          551.7
Winter % Overload [See Note 2 below]                           Nil        Nil         Nil         Nil           Nil        Nil         Nil           Nil           Nil         0.9%
Annual Energy at Risk (MWh) [See Note 3 below]              1,681      2,827       4,393       6,297       8,524      11,439       14,836        18,654        23,319         28,882
Annual Hours at Risk [See Note 4 below]                      65.8      100.0       135.5       180.0       222.0        268.5       316.3         370.5         446.5          540.8
Expected Annual Unserved Energy (MWh) [See Note
                                                             14.6       24.5        38.1        54.7           74.0      99.3       128.8         161.9         202.4          250.7
5 below]
Expected Annual Unserved Energy value [See Note 6
                                                         $1,318k     $2,217k     $3,445k     $4,939k     $6,686k      $8,971k    $11,636k     $14,630k      $18,289k       $22,653k
below]

   Notes:
1.  “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.  This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
                                                                                   th
3.  “Annual energy at risk” is the amount of energy in a year during which the 50 percentile demand forecast exceeds the N-1 capability rating.
4.  “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5.  “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                 Page 6 of 6
2010 Transmission Connection Planning Report                       Risk Assessment: RWTS 22 kV


RINGWOOD TERMINAL STATION 22 kV (RWTS 22)

Ringwood Terminal Station consists of two separate components – the 66 kV component
and the 22 kV component. Currently the RWTS 22 kV component is supplied by two
55 MVA 220/22 kV and one 38 MVA, 66/22 kV transformers but these transformers are being
replaced with two new 75 MVA 220/22 kV transformers under SPI PowerNet’s asset
replacement program. The new transformers are expected to be in service prior to summer
2011/12. RWTS 22 kV is the main source of 22 kV supply for the local area and for the
railway network. The geographic coverage of the station’s supply area includes Ringwood,
Mitcham, Wantirna and Nunawading. The electricity supply network for this area is the
responsibility of both SPI Electricity (64%) and United Energy Distribution (36%).

Magnitude, probability and impact of loss of load

Peak loading at the station occurs in summer. Growth in summer peak demand at
RWTS 22 kV is around 2 MW (2%) per annum. The station recorded a peak demand of 96
MW (99 MVA) in summer 2008/09. The recorded peak demand in summer 2009/10 was 90.5
MW (90.6 MVA), which was approximately 5.5 MW lower than the 2009 peak. This is
attributed to comparatively mild weather conditions observed during summer 2010.

Currently the installed transformer capacity cannot be fully utilised due to fault level
restrictions. The consequence of this restriction is that only two out of three transformers can
be in service at any one time. Thus, there is always a “spare” transformer that can be
switched into service in the case of a transformer failure.

The various transformer combinations mean that the risk assessment for RWTS 22 kV is
more complicated than for most terminal stations. For the purpose of this risk analysis, the
following has been assumed:

•   The “N” rating is the rating of two 220/22 kV transformers (combined rating of 115 MVA).

•   The “N-1” rating is the rating of one 220/22 kV and one 66/22 kV transformer (combined
    summer rating of 79 MVA). Unequal load sharing means that the full combined capacity
    of the two transformers cannot be utilised.

The station is normally operated with one 220/22 kV and one 66/22 kV transformer in service
except during summer peak loading periods when loading is expected to exceed 79 MVA
and the station is then operated with the two 220/22 kV transformers in service. The difficulty
with the summer peak configuration is that no voltage control of the 22 kV bus is possible as
the 220/22 kV transformers do not have automatic voltage control taps. However, this will be
no longer an issue once the two new 220/22 kV transformers are installed and placed into
service in late 2011 as these will be equipped with on load tap changers.

After the two new 220/22 kV 75 MVA transformers are installed in 2011 the station will
operate with both transformers in service and in parallel. The station “N” rating with both
transformers in service is estimated to be 190 MVA in summer and the “N–1” rating with one
transformer out of service is 95 MVA. The 22 kV transformer circuit breaker continuous
rating of 2500 Amps will limit the winter rating to 95 MVA, a similar figure to the summer
rating.

RWTS 22 kV is expected to be loaded above its “N-1” rating in summer. The graph below
depicts the 10th and 50th percentile summer maximum demand forecasts together with the
station’s “N-1” rating at an ambient temperature of 35°C.




                                                                                      Page 1 of 6
2010 Transmission Connection Planning Report                                                                                                         Risk Assessment: RWTS 22 kV


The (N) rating on the chart given below indicates the maximum load that can be supplied
from RWTS 22 kV with all transformers in service.


                                                                                 RWTS 22 kV Summer Peak Forecasts

                                 200.0

                                 190.0
                                                                                                                              (N) Rating @ 35 deg C after rebuild
                                 180.0

                                 170.0

                                 160.0

                                 150.0

                                 140.0
  MVA




                                 130.0
                                                                                                                                             10% Weather Probability Forecast
                                 120.0                   (N) Rating @ 35 deg C

                                 110.0
                                                                                                                                                                      50% Weather Probability Forecast
                                 100.0

                                  90.0                                                                                                    (N-1) Rating @ 35 deg C after rebuild
                                                    (N-1) Rating @ 35 deg C
                                  80.0
                                                                                   Actuals              Forecasts
                                  70.0

                                  60.0
                                         2005   2006      2007      2008         2009    2010    2011       2012       2013       2014       2015       2016        2017     2018        2019        2020
                                                                                                                    Year




The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.

                                                         Annual Energy and Hours at Risk at RWTS 22 kV (Single Contigency Only)

                                                Hours at Risk (LH scale)                 Energy at Risk MWhrs (LH scale)                     Customer Value (RH scale)
                                 200                                                                                                                                                            $40,000


                                 180                                                                                                                                                            $36,000


                                 160                                                                                                                                                            $32,000


                                 140                                                                                                                                                            $28,000
  MWhr at Risk / Hours at Risk




                                 120                                                                                                                                                            $24,000


                                 100                                                                                                                                                            $20,000


                                  80                                                                                                                                                            $16,000


                                  60                                                                                                                                                            $12,000


                                  40                                                                                                                                                            $8,000


                                  20                                                                                                                                                            $4,000


                                   0                                                                                                                                                            $0
                                         2011        2012           2013            2014         2015           2016             2017            2018               2019          2020
                                                                                                         Year




                                                                                                                                                                                           Page 2 of 6
2010 Transmission Connection Planning Report                                  Risk Assessment: RWTS 22 kV


Comments on Energy at Risk

As already noted, RWTS 22kV is a summer peaking station and all of the energy at risk
occurs in the summer period. Accordingly, the comments below focus on the energy at risk
over the summer period.

By the end of the ten year planning period in 2020, for an outage of one 220/22 kV
transformer at RWTS 22 kV over the entire summer period, there will be insufficient capacity
at the station to supply all demand at the 50th percentile temperature for about 26 hours in
summer 2019/20. The energy at risk at the 50th percentile temperature under N-1 conditions
is estimated at 164 MWh in summer 2019/20. The estimated value to consumers of the 164
MWh of energy at risk is approximately $9 million (based on a value of customer reliability of
$54,908/MWh) 1 . In other words, at the 50 percentile demand level, and in the absence of
any other operational response that might be taken to mitigate the impact of a forced outage,
a major outage of one transformer at RWTS 22 kV over the summer of 2019/20 would be
anticipated to lead to involuntary supply interruptions that would cost consumers $9 million.

It is emphasised however, that the probability of a major outage of one of the two
transformers occurring over the duration of the year is very low at about 1.0% per
transformer per annum, whilst the expected unavailability per transformer per annum is
0.217%. When the energy at risk (164 MWh for 2019/20) is weighted by this low
unavailability, the expected unsupplied energy is estimated to be 0.7 MWh. This expected
unserved energy is estimated to have a value to consumers of around $39,000 (based on a
value of customer reliability of $54,908MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2019/20 is estimated to be 579 MWh. The estimated value to
consumers of this energy at risk in 2019/20 is approximately $31.8 million.          The
corresponding value of the expected unserved energy on a probabilistic basis is
approximately $138,000.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                                      MWh           Valued at consumer
                                                                                     interruption cost
Energy at risk, at 50th percentile demand forecast                     164                $9.0 million

Expected unserved energy at 50th percentile demand                     0.7                  $39,000

Energy at risk, at 10th percentile demand forecast                     579               $31.8 million

Expected unserved energy at 10th percentile demand                     2.5                 $138,000




1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
        in accordance with the composition of the load at this terminal station.


                                                                                                    Page 3 of 6
2010 Transmission Connection Planning Report                              Risk Assessment: RWTS 22 kV


If one of the 220/22 kV transformers at RWTS is taken off line during peak loading times and
the N-1 station rating is exceeded, then the Overload Shedding Scheme for Connection
Assets (OSSCA) which is operated by SPI PowerNet’s TOC 2 to protect the connection
assets from overloading 3 , will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at feeder level in accordance with SPI
Electricity’s and United Energy’s operational procedures after the operation of the OSSCA
scheme.

In the event of OSSCA operating, it would automatically shed about 25 MVA of load,
affecting approximately 10,000 customers in 2010.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging network constraint:

1. Implement contingency plans to transfer load to adjacent supply points

SPI Electricity has established and implemented the necessary plans that enable up to
20 MVA of load transfers via existing 22 kV feeders and switches to adjoining Zone
Substations. United Energy Distribution has the plans and capability to transfer an additional
10 MVA. Load transfers from RWTS 22 kV could commence within 2 hours of a contingency
and take up to a further 2 hours. This option will dramatically reduce the interruption duration
and load at risk resulting from a major transformer failure.

2. Install an additional transformer at RWTS 22 kV

After the rebuild work to install two new 220/22 kV 75 MVA transformers in 2011 the station
will be arranged to allow for the future installation of a third 220/22 kV 75 MVA transformer.

3. Demand reduction

SPI Electricity is currently using an MVA tariff to encourage large customers to improve their
power factor and thus reduce load. Up to 80% of the maximum demand at RWTS 22 kV is
summer residential and commercial load, largely air conditioning.

United Energy Distribution has developed a number of innovative network tariffs to
encourage voluntary demand reduction during times of network constraints. The amount of
demand reduction depends on the tariff uptake, and will be taken into consideration when
determining the optimum timing for the capacity augmentation.

4. Embedded generation

Embedded generation in the order of 20 to 25 MVA connected to the RWTS 22 kV bus would
help to defer the need for an augmentation by at least one to two years.




2
    Transmission Operation Centre.
3
  OSSCA is designed to protect against transformer damage caused by overloads. Damaged transformers can
take months to replace which can result in prolonged, long term risks to reliability of customer supply.




                                                                                               Page 4 of 6
2010 Transmission Connection Planning Report                               Risk Assessment: RWTS 22 kV


Preferred network option(s) for alleviation of constraints

    1. In the event there are no firm commitments by interested parties to offer network
       support services by installing local generation or through demand side management
       initiatives that would reduce future load at RWTS 22 kV, then it will be proposed to
       install a new 220/22 kV, 75 MVA transformer at RWTS 22 kV. On the basis of
       present forecasts, this is not expected to be required until around 2020.

       The capital cost of installing a new 220/22 kV transformer at RWTS 22 kV is estimated
       to be $12 million in 2010. The cost of establishing, operating and maintaining the
       transformer would be recovered from network users through network charges, over
       the life of the asset. In today’s terms, the estimated total annual cost of this network
       augmentation is approximately $1.2 million. This cost provides a broad upper bound
       indication of the maximum network support payment which may be available 4 to
       embedded generators or customers to reduce forecast demand and defer or avoid
       this transmission connection augmentation which may be required beyond 2020. Any
       non-network solution that defers this augmentation for say 1-2 years, will not have as
       much potential value (and contribution available from distributors) as a solution that
       eliminates or defers the augmentation for say 10 years. Section 1.5 of this report
       provides further background information to proponents of non-network solutions to
       emerging network constraints.

    2. In the meantime it is proposed to iImplement the following temporary measures to
       cater for an unplanned outage of one transformer at RWTS 22 kV under critical
       loading conditions:

        •   maintain contingency plans to transfer load quickly to adjacent Zone Substations;

        •   fine-tune the OSSCA scheme settings in conjunction with TOC to minimise the
            impact on customers of any load shedding that may take place to protect the
            connection assets from overloading; and

        •   Monitor the load growth to ensure the load at risk is within the forecasts.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




4
       A Rule change proposal is presently before the AEMC to enable distributors to make these payments and
       recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-
       recovery-of-transmission-related-charges.html). The Rule change, if accepted, would replicate the
       previous regulatory arrangements in Victoria.




                                                                                                Page 5 of 6
2009 Transmission Connection Planning Report                            Risk Assessment: RWTS 22 kV




RINGWOOD TERMINAL STATION 22 kV (RWTS 22 kV)
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                 SPI Electricity (64%) UED (36%)
Installed Transformer Capacity (prior to 2012) =                  148 MVA             Fault Level restrictions allow only two transformers to be connected at any one time.
Installed Transformer Capacity (2012 and later) =                 150 MVA
Normal cyclic rating with all plant in service (prior to 2012)    115 MVA via 2 transformers (Summer peaking)
Normal cyclic rating with all plant in service (2012 and later)   190 MVA
Summer N-1 Station Rating in MVA (prior to 2012)                  79
Summer N-1 Station Rating in MVA (2012 and later)                 95
Winter N-1 Station Rating in MVA (prior to 2012):                 102
Winter N-1 Station Rating in MVA (2012 and later):                95

Station: RWTS 22kV                                                     2011      2012       2013      2014      2015       2016       2017       2018       2019       2020
50th percentile Summer Maximum Demand (MVA)                            91.1       93.6       97.1      98.7     101.1      103.5      105.9      108.4     111.1      113.8
Summer % Overload [See Note 2 below]                                 15.4%      -1.5%       2.3%      3.9%      6.5%       8.9%      11.4%      14.1%     17.0%      19.8%
50th percentile Winter Maximum Demand (MVA)                            75.5       75.6       75.7      76.1      77.1       78.1       78.8       79.8      80.7       81.7
Winter % Overload [See Note 2 below]                                     Nil        Nil       Nil        Nil       Nil        Nil        Nil        Nil       Nil        Nil
Annual energy at risk (MWh) [See Note 3 below]                           73          0        0.9       2.2       8.5       21.6       41.6       71.5     111.4      163.8
Annual hours at risk [See Note 4 below]                                  16          0        0.7       1.4       4.2        7.4       10.6       14.4      18.1       26.4
Expected Annual Unserved Energy (MWh) [See Note 5
                                                                         0.3       0.0        0.0       0.0       0.0        0.1        0.2        0.3        0.5       0.7
below]
Expected Annual Unserved Energy value [See Note 6 below]           $17,356          $0      $206      $522     $2,015    $5,128     $9,886 $16,997 $26,489 $38,944

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage with a
    duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                         Page 6 of 6
2010 Transmission Connection Planning Report                         Risk Assessment: RWTS 66 kV


RINGWOOD TERMINAL STATION 66 kV (RWTS 66 kV)

Ringwood Terminal Station is the main source of supply for a major part of the outer eastern
metropolitan area. The geographic coverage of the station’s supply area spans from Lilydale
and Woori Yallock in the north east; to Croydon , Bayswater and Boronia in the east; and
Box Hill, Nunawading and Ringwood more centrally. The electricity supply network for this
large region is the responsibility of both SPI Electricity (SPIE) and United Energy Distribution.

Background

Ringwood Terminal Station consists of two separate components – the 66 kV component
and the 22 kV component. The RWTS 66 kV component is supplied by four 150 MVA
220/66 kV transformers and is a summer critical station. The four transformers are operated
in two separate bus groups. Under system normal conditions, the No. 1 and No. 2
transformers are operated in parallel as one group; RWTS bus group 1/3 and supply the
No.1 and No. 3 66 kV buses whereas the No. 3 and No. 4 transformers are operated in
parallel as another group; RWTS bus group 2/4 and supply the No.2 and No. 4 66 kV buses
respectively. To achieve the station’s operation in two separate bus groups, the 66 kV bus
1-2 and bus 3-4 tie circuit breakers are operated normally open.

The operation of two separate bus groups as detailed above is essential to limit the
maximum prospective fault levels on the 66 kV busses to within their respective switchgear
ratings. Given this configuration, load demand on the RWTS bus groups B1/3 and B2/4
must be kept within the capabilities of their respective two transformers at all times otherwise
load shedding will occur. However, for an unplanned transformer outage in any of the two
RWTS bus groups, an auto close scheme will operate resulting in parallel operation of all the
remaining three transformers in service.

Combined Summer Peak Demand forecasts for RWTS 66 kV -Total Station Load

Growth in summer peak demand at RWTS 66 kV has averaged around 20 MW (4%) per
annum over the last 8 years. The peak load on the station reached 508 MW (516 MVA
including a cap bank of 95 MVAR) in summer 2008/09. The recorded peak demand in
summer 2009/10 was 485.6 MW (489 MVA including a cap bank of 95 MVAR), which was
approximately 22 MW lower than the 2009 peak. This is mainly due to relatively mild
weather conditions observed during summer 2010.

Combined peak load for both the RWTS 66 kV bus groups occurs in summer. The graph
below depicts the 10th and 50th percentile combined summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N-1”
rating at an ambient temperature of 35°C and 40°C. The combined loading at RWTS 66 kV is
forecast to reach the station’s “N-1” rating in summer 2011 at the 50th percentile summer
maximum demand forecast. This means under “N-1” conditions there will be load at risk
during summer for the entire planning period covered under this report.

On the other hand, combined winter demand at RWTS 66kV is not expected to reach its
winter “N–1” rating in the current planning period until 2020.




                                                                                       Page 1 of 7
2010 Transmission Connection Planning Report                                                                                Risk Assessment: RWTS 66 kV




                                       Total Station Load: RWTS 66 kV Summer Peak Forecasts

         800.0


         750.0


         700.0


         650.0
                                                 Addition of 4th             10% Weather Probability Forecast
                                                 transformer
         600.0
                                                                                                                              50% Weather Probability Forecast

         550.0
   MVA




                                  (N) Rating @ 35 deg C

         500.0
                                (N) Rating @ 40 deg C

         450.0


         400.0

                                      (N-1) Rating @ 35 deg
         350.0                                   C
                                      (N-1) Rating @ 40 deg C
         300.0                                                                                    Forecasts
                                                                          Actuals


         250.0
                 2002   2003   2004     2005     2006     2007     2008   2009      2010   2011     2012      2013   2014   2015   2016     2017    2018     2019   2020
                                                                                           Year


Bus group RWTS B1/3 and RWTS B2/4: Summer Peak Forecasts

In addition to the load at risk during summer under the station’s N-1 conditions as mentioned
above, it is essential to take into account the load at risk (if any) on the individual bus groups
when both their respective transformers are in service, i.e under N conditions.

Bus group RWTS B1/3: Peak demand at RWTS 66 kV bus group B1/3 occurs in
summer. Based on the individual summer demand forecasts, with both its transformers in
service, i.e. under N conditions, the loading on this bus group is forecast to reach its N rating
during summer 2017. This means that under N conditions there will be some load at risk
during summer from 2017 onwards. Given that there will be insufficient capacity to meet the
anticipated maximum load demand under the N conditions, the entire energy at risk will be
considered in the risk calculation rather than including its probability weighted component.
Bus group RWTS B2/4: Similar to the bus group B1/3, the peak load at RWTS 66 kV bus
group B2/4 also occurs in summer. Based on the individual summer demand forecasts for
this bus group, with both transformers in service, i.e. under N conditions, the loading on this
bus group is forecast to remain within its N rating throughout the planning period covered
under this report i.e. until 2020. This means there is no energy at risk during summer under
Normal operating conditions on this bus group.


Magnitude, probability and impact of loss of load

The bar chart below depicts the combined station’s energy at risk with one transformer out of
service for the 50th percentile total station’s demand forecast including energy at risk on the
bus group 1/3 from 2017 onwards, and the hours per year that the 50th percentile combined
demand forecast is expected to exceed the “N-1” capability plus the hours per year that the N
capacity of the bus group 1/3 is exceeded in each year from 2017 onwards. The line graph
shows the value to consumers of the expected unserved energy in each year, for the 50th



                                                                                                                                                           Page 2 of 7
2010 Transmission Connection Planning Report                                                                                  Risk Assessment: RWTS 66 kV


percentile demand forecast including value to customers of the entire unserved energy under
the N conditions on bus group 1/3 from 2017 onwards.

                                                          Annual Energy and Hours at Risk at RWTS 66 (Single Contingency Only)

                                             Hours at Risk (LH scale)      Energy at Risk MWhrs (LH scale)          Customer Value (RH scale)
                                   15000                                                                                                               $40,000,000


                                   13500                                                                                                               $36,000,000


                                   12000                                                                                                               $32,000,000


                                   10500                                                                                                               $28,000,000
    MWhr at Risk / Hours at Risk




                                   9000                                                                                                                $24,000,000


                                   7500                                                                                                                $20,000,000


                                   6000                                                                                                                $16,000,000


                                   4500                                                                                                                $12,000,000


                                   3000                                                                                                                $8,000,000


                                   1500                                                                                                                $4,000,000


                                      0                                                                                                                $0
                                           2011       2012         2013   2014       2015          2016      2017     2018        2019          2020
                                                                                            Year




Comments on Energy at Risk

For an outage of one transformer at RWTS 66 kV over the entire summer period, there will
be insufficient capacity at the station to supply all demand at the 50th percentile temperature
for about 72 hours in summer 2015/16, and the energy at risk under “N-1” conditions is
estimated to be 2,738 MWh. The estimated value to consumers of the 2,738 MWh of energy
at risk is approximately $156 million (based on a value of customer reliability of
$56,968/MWh). 1 In other words, at the 50th percentile demand level, and in the absence of
any other operational response that might be taken to mitigate the impact of a forced outage,
a major outage of one transformer at RWTS 66 kV for the entire duration of the summer of
2015/16 would be anticipated to lead to involuntary supply interruptions that would cost
consumers $156 million.

It is emphasised however, that the probability of a major outage of one of the four
transformers occurring over the duration of the year is very low, at about 1.0% per
transformer per annum, whilst the expected unavailability per transformer per annum is
0.217%. When the energy at risk (2,738 MWh for 2015/16) is weighted by this low
unavailability, the expected unsupplied energy is estimated to be around 24 MWh. This
expected unserved energy is estimated to have a value to consumers of around $1.35 million
(based on a value of customer reliability of $56,968/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2015/16 is estimated to be 8,115 MWh. The estimated value to

1
                                       The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
                                       in accordance with the composition of the load at this terminal station.


                                                                                                                                                        Page 3 of 7
2010 Transmission Connection Planning Report                               Risk Assessment: RWTS 66 kV


consumers of this energy at risk in 2015/16 is approximately $462 million.                           The
corresponding value of the expected unserved energy is approximately $4 million.

These key statistics for the year 2016 under N-1 outage conditions are summarised in the
table below.

                                                                   MWh          Valued at consumer
                                                                                 interruption cost
Energy at risk, at 50th percentile demand forecast                 2,738             $156 million

Expected unserved energy at 50th percentile demand                  24               $1.35 million

Energy at risk, at 10th percentile demand forecast                 8,115             $462 million

Expected unserved energy at 10th percentile demand                  70                 $4 million



If one of the 220/66 kV transformers at RWTS is taken off line during peak loading times and
the N-1 station rating is exceeded, then the Overload Shedding Scheme for Connection
Assets (OSSCA) which is operated by SPI PowerNet’s TOC 2 to protect the connection
assets from overloading 3 , will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at zone substation feeder level in
accordance with SPI Electricity’s and United Energy’s operational procedures after the
operation of the OSSCA scheme. It may be noted that in the event if OSSCA operates, it
would shed about 100 MVA of load, affecting approximately 33,000 customers.

As mentioned earlier, RWTS 66 kV consists of four 150 MVA 220/66 kV transformers which
are operated in two separate bus groups, namely bus group 1/3 and bus group 2/4. In
addition to the above mentioned key statistics for the entire RWTS 66 kV station, it is also
necessary to consider the loading on the individual bus groupings to determine whether
sufficient capacity exists to meet forecast levels of demand at the station. In this regard it is
noted that loading on bus group 1/3 is expected to reach the capacity of B1 and B2
transformers by summer 2016/17. An augmentation will therefore need to be in place by that
time to avoid system normal load shedding, given that the two transformer groups at RWTS
66 kV are operated as separate groups (because of fault level considerations) under system
normal conditions.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint and are being investigated by
SPI Electricity, United Energy Distribution and AEMO in line with the Victorian Joint Planning
Process:




2
    Transmission Operation Centre.
3
  OSSCA is designed to protect against transformer damage caused by overloads. Damaged transformers can
take months to replace which can result in prolonged, long term risks to reliability of customer supply.




                                                                                               Page 4 of 7
2010 Transmission Connection Planning Report                          Risk Assessment: RWTS 66 kV


1.      Contingency plans to transfer load to adjacent terminal stations

Both SPI Electricity and United Energy Distribution have established and implemented the
necessary plans to enable load transfers under contingency conditions via emergency 66 kV
ties to the adjacent East Rowville and Templestowe Terminal Stations, respectively. The
emergency 66 kV ties from RWTS 66 kV can be in operation within 2 hours and have a
transfer capability of approximately 40 MVA each. This option will substantially reduce the
interruption duration and load at risk resulting from a major transformer failure.
United Energy and SPI Electricity have the capability to transfer an additional 15 MVA at the
distribution feeder level.

2.      Install new 66 kV Capacitor Banks on Bus Group 1/3

Installation of two new 50 MVAR 66 kV capacitor banks connected to 66 kV bus group 1/3 to
alleviate the station loading levels may enable network augmentation to be deferred for at
least one to two years.

3.      Establish a new 220/66kV terminal station

There are vacant terminal station sites at Doncaster and Coldstream that could be utilised for
a new terminal station to offload RWTS. On the present forecasts this new terminal station
would be required to be in service prior to the 2017/18 summer. As part of the Victorian Joint
Planning Process, SPI Electricity, United Energy Distribution and AEMO have commenced
discussions with a view to carrying out further detailed studies to determine whether this
option would be likely to be the most economic option.

4.      Install a fifth 220/66kV transformer at RWTS

It is feasible to install a fifth transformer in the RWTS switchyard. There will be some
unavoidable operational issues and difficulties in operating the station with five transformers,
however, this option would address the issue of bus group 1/3 reaching its capacity. This
option can be implemented in a shorter time frame compared with the new terminal station
options and would not require a reconfiguration of the 66 kV feeder exits to control the station
fault levels.

5.      Install a fourth 220/66kV transformer at TSTS

It is feasible to install a fourth transformer in the nearby terminal station at Templestowe
(TSTS) and build new 66 kV lines to allow load to be transferred away from RWTS.

6.      Demand reduction

SPI Electricity is currently using a demand based (MVA) tariff to encourage large customers
to improve their power factor and thus reduce the station loading. Up to 50% of the
maximum demand at RWTS 66 kV is summer residential load, largely air conditioning. With
this existing load mix, SPI Electricity does not believe it is realistic to expect demand
reduction initiatives (e.g. special tariffs) to play a significant role in reducing the peak summer
load at RWTS 66 kV.

United Energy Distribution has developed a number of innovative network tariffs to
encourage voluntary demand reduction during the times of network constraints. The amount
of demand reduction depends on the tariff uptake and will be taken into consideration when
determining the optimum timing for the capacity augmentation.




                                                                                        Page 5 of 7
2010 Transmission Connection Planning Report                                  Risk Assessment: RWTS 66 kV


7.       Embedded generation

Embedded generation in the order of 40 MVA, connected to the network supplied by the
RWTS 66 kV bus will help to defer an augmentation by at least one to two years.

Preferred network option(s) for alleviation of constraints

If there is no commitment by any interested parties to offer network support services through
local generation, or through demand side management initiatives that would reduce load at
RWTS 66 kV, it is proposed to

1. Further investigate the economics and feasibility of the network options described above,
   namely: installation of a fifth 220/66 kV transformer at RWTS; installation of a fourth
   transformer at TSTS; installation of new 66 kV capacitor banks at RWTS; or development
   of a new terminal station at Doncaster or Coldstream, to address constraints at RWTS.
   As part of the Victorian Joint Planning process, SPI Electricity, United Energy and AEMO
   have commenced discussions with a view to carrying out further detailed studies to
   determine the preferred network augmentation option. The preferred option will be
   determined over the next 12 to 18 months period.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at RWTS 66 kV under critical loading conditions after summer 2010/11:

     •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

     •   fine-tune the OSSCA scheme settings in conjunction with TOC to minimise the impact
         on customers of any load shedding that may take place to protect the connection
         assets from overloading; and

     •   subject to the availability of the SPI PowerNet spare 220/66kV transformer for the
         metropolitan area (refer section 4.5), this spare transformer can be used to
         temporarily replace the failed transformer.

Whilst no decision has yet been made on a preferred network augmentation, a fifth
transformer at RWTS is potentially the most likely economic option. If this is the case the
capital cost of installing a fifth transformer at RWTS is estimated to be $14 million. The cost
of establishing, operating and maintaining this new transformer would be recovered from
network users through network charges, over the life of the asset. The estimated total annual
cost of this network augmentation is approximately $1.4 million. This cost provides a broad
upper bound indication of the maximum network support payment which may be available 4
to embedded generators or demand management initiatives that results in the deferral of this
transmission connection augmentation.             Any non-network solution that defers this
augmentation for say 1-2 years, will not have as much potential value (and contribution
available from distributors) as a solution that eliminates or defers the augmentation for, say,
10 years. Sections 1.4 and 1.5 of this report provide further background information to
proponents of non-network solutions to emerging constraints.

Any non-network proposal must be submitted with detailed plans to SPIE and UED for
consideration no later than June 2011. This will ensure that sufficient time is available to

4
         A Rule change proposal is presently before the AEMC to enable distributors to make these payments and
         recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-
         recovery-of-transmission-related-charges.html). The Rule change, if accepted, would replicate the
         previous regulatory arrangements in Victoria.




                                                                                                  Page 6 of 7
2010 Transmission Connection Planning Report                    Risk Assessment: RWTS 66 kV


implement the most cost-effective measure(s) to manage the risk of supply interruption, and
to maintain a satisfactory level of supply reliability.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                 Page 7 of 7
2010 Transmission Connection Planning Report                                     Risk Assessment: RWTS 66 kV




RINGWOOD TERMINAL STATION 66kV (RWTS 66 kV)
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:          SPI Electricity (77%), UE (23%)
Normal cyclic rating with all plant in service             676 MVA via 4 transformers (Summer peaking)
Summer N-1 Station Rating (MVA):                           507
Winter N-1 Station Rating (MVA):                           578

Station: RWTS 66kV                                            2011      2012         2013      2014       2015         2016        2017         2018          2019           2020
50th percentile Summer Maximum Demand (MVA)                   514.6     531.6       559.1      576.8      596.6        618.3       640.1        659.3         682.1          704.8
Summer % Overload [See Note 2 below]                          1.5%      4.9%       10.3%      13.8%      17.7%        22.0%       26.2%        30.0%         34.5%          39.0%
50th percentile Winter Maximum Demand (MVA)                   409.4     410.1       412.1      414.6      420.2        424.1       427.3        431.3         435.2          439.1
Winter % Overload [See Note 2 below]                             Nil       Nil         Nil        Nil        Nil          Nil         Nil          Nil           Nil            Nil
Annual energy at risk (MWh) [See Note 3 below]                  7.5      63.8       406.2      836.5     1573.4       2738.0      4330.9       6215.5        9055.0        12464.3
Annual hours at risk [See Note 4 below]                         1.7       6.0         20.2      33.0       48.1         72.1        99.2        131.4         167.5          201.1
Expected Annual Unserved Energy (MWh) under N-1
                                                                0.1        0.6        3.5        7.3        13.6        23.7         37.5         53.9          78.5         108.1
conditions
Energy at Risk in Summer (N) Bus Group 1 and 3                    0         0           0          0           0            0         1.7         40.0         211.0         569.2
Energy at Risk in Summer (N) Bus Group 2 and 4                    0         0           0          0           0            0           0            0             0           0.00
Total Expected Annual Unserved Energy (MWh) [See
                                                                0.1        0.6        3.5        7.3        13.6        23.7         39.3         93.9         289.5         677.3
Note 5 below]
Expected Annual Unserved Energy value [See Note 6
                                                            $3,706 $31,502 $200,619 $413,140 $777,107 $1,352,308 $2,238,104 $5,347,061 $16,491,480 $38,582,880
below]



Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
                                                                                  th
3. “Annual energy at risk” is the amount of energy in a year during which the 50 percentile forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage with
    duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                        Page 8 of 7
2010 Transmission Connection Planning Report                                                                            Risk Assessment: SHTS



SHEPPARTON TERMINAL STATION (SHTS) 66 kV

Shepparton Terminal Station (SHTS) 66 kV consists of three 150 MVA 220/66 kV
transformers and is the main source of supply for over 66,882 customers in Shepparton and
the Goulburn–Murray area. The station supply area includes towns of Shepparton, Echuca,
Mooroopna, Kyabram, Cobram, Yarrawonga, Numurkah, Tatura, Rochester, Nathalia,
Tongala, and Rushworth.

Magnitude, probability and impact of loss of load

Demand at SHTS is summer peaking. Growth in summer peak demand at SHTS has
averaged around 6.3 MW (2.6%) per annum over the last 10 years. Peak load on the station
in summer 2010 reached 284.3 MW.

Over the last 10 years Powercor has installed additional capacitors in a number of zone
substations in the area to provide reactive support. These have been required because of
rapid increases in air-conditioning load, and to defer the high capital cost of transmission
connection asset augmentation. The third 150 MVA 220/66 kV transformer at the station
was installed in July 2001.

The chart below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N−1”
rating at 35°C ambient temperature.


                                                      SHTS 66 kV Summer Peak Forecasts

                      600

                                      “N” rating at 35°C
                      500
                                                                                         10% Weather Probability
  SHTS Demand (MVA)




                                                                                               Forecast
                      400             “N−1” rating at 35°C



                      300
                                                                                                                 50% Weather Probability
                                                                                                                       Forecast
                      200
                                                          Actuals             Forec asts

                      100


                         0
                         05


                                 06


                                         07


                                                 08


                                                         09


                                                                 10


                                                                         11


                                                                                 12


                                                                                         13


                                                                                                 14


                                                                                                         15


                                                                                                                 16


                                                                                                                         17


                                                                                                                                 18


                                                                                                                                         19


                                                                                                                                                 20
                      20


                              20


                                      20


                                              20


                                                      20


                                                              20


                                                                      20


                                                                              20


                                                                                      20


                                                                                              20


                                                                                                      20


                                                                                                              20


                                                                                                                      20


                                                                                                                              20


                                                                                                                                      20


                                                                                                                                              20




                                                                                      Year



The chart shows there is sufficient capacity at the station to supply all expected load over
the forecast period, even with one transformer out of service. Therefore, the need for
augmentation or other corrective action is not expected to arise over the next ten years.




                                                                                                                                         Page 1 of 1
2010 Transmission Connection Planning Report                                                              Risk Assessment: SMTS


SOUTH MORANG TERMINAL STATION (SMTS 66 kV)

Magnitude, probability and impact of loss of load

The risk of supply interruption at Thomastown Terminal Station (TTS), for a single
contingency event has previously been assessed as being unacceptable for summer
2008/09. Accordingly, the establishment of new 220/66 kV connection facility with two
220/66 kV 225 MVA transformers at the existing South Morang Terminal Station (SMTS) site
was identified (in the 2004, 2005 and 2006 Transmission Connection Planning Reports) as
the most economic network solution by both SPI Electricity and Jemena Electricity Networks.

Prior to committing to the proposed development of South Morang Terminal Station (SMTS),
SPI Electricity (SPIE) and Jemena Electricity Networks (JEN) completed a public “Expression
of Interest” process for non-network alternatives, via the publication of the Transmission
Connection Planning Report in 2004. At the conclusion of the expression of interest process
on 31 March 2005, no firm proposals for alternative solutions were received. SPIE and JEN
therefore proceeded to implement the proposed network solution.

Since then, new 220/66 kV connection assets at SMTS have been commissioned, and load
has been transferred from TTS to SMTS progressively from December 2008 to October
2009. In addition, a new zone substation KLO has also been connected to SMTS. The re-
arrangement of 66 kV sub transmission loops to achieve the load transfers from TTS to
SMTS has resulted in the 140 MVA Somerton Power Station (SPS) being connected to the
SMTS 66 kV bus.

The geographic coverage of the area supplied by the new connection assets at SMTS spans
from Seymour, Kilmore, Kalkallo, Kinglake and Rubicon in the north to Mill Park in the south
and from Doreen and Mernda in the east to Somerton and Craigieburn in the west.

Demand at SMTS 66 kV is expected to be summer peaking. The graph below depicts the
10th and 50th percentile summer maximum demand forecast together with the station’s
expected operational “N” rating (all transformers in service) and the “N-1” rating at 35°C as
well as 40°C ambient temperature.
                                          SMTS 66 kV Summer Peak Forecasts

         600.0
                          (N) Rating @ 35 deg C
         550.0
                          (N) Rating @ 40 deg C
         500.0

         450.0
                                             10% Weather Probability Forecast

         400.0

         350.0                                                                  50% Weather Probability Forecast
   MVA




         300.0                                               (N-1) Rating @ 35 deg C

         250.0                                (N-1) Rating @ 40 deg C

         200.0

         150.0

         100.0

          50.0           Actuals              Forecasts

           0.0
                        2009       2010    2011    2012     2013     2014       2015     2016     2017    2018     2019   2020
                                                                        Year




                                                                                                                           Page 1 of 6
2010 Transmission Connection Planning Report                                                                                          Risk Assessment: SMTS


The (N) rating on the above chart indicates the maximum load that can be delivered from
SMTS with all transformers in service.

With the projected growth in customer demand in the area, it is expected that SMTS will
exceed its “N-1” rating in summer 2011, as shown in the graph above. Winter demand at
SMTS 66 kV is not expected to reach “N-1” rating during the current planning horizon until
2019.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.

                                                        Annual Energy and Hours at Risk at SMTS 66 kV (Single Contingency Only)

                                              Hours at Risk (LH scale)      Energy at Risk MWhrs (LH scale)          Customer Value (RH scale)
                                   120000                                                                                                               $30,000,000

                                   110000
                                                                                                                                                        $27,000,000

                                   100000
                                                                                                                                                        $24,000,000
                                   90000
                                                                                                                                                        $21,000,000
    MWhr at Risk / Hours at Risk




                                   80000

                                                                                                                                                        $18,000,000
                                   70000

                                   60000                                                                                                                $15,000,000

                                   50000
                                                                                                                                                        $12,000,000

                                   40000
                                                                                                                                                        $9,000,000
                                   30000
                                                                                                                                                        $6,000,000
                                   20000

                                                                                                                                                        $3,000,000
                                   10000

                                       0                                                                                                                $0
                                            2011       2012         2013   2014      2015          2016       2017     2018        2019          2020
                                                                                            Year




Comments on Energy at Risk

For an outage of one transformer at SMTS over the entire summer period, there will be
insufficient capacity at the station to supply all demand at the 50th percentile temperature for
about 327 hours in summer 2014/15. The energy at risk at the 50th percentile temperature
under N-1 conditions is estimated to be 9,837 MWh in 2014/15. The estimated value to
consumers of the 9,837 MWh of energy at risk is approximately $614.5 million (based on a
value of customer reliability of $62,463/MWh) 1 . In other words, at the 50th percentile demand
level, and in the absence of any other operational response that might be taken to mitigate
the impact of a forced outage, a major outage of one transformer at SMTS in 2014/15 would
be anticipated to lead to involuntary supply interruptions that would cost consumers $614.5
million.

It is emphasised however, that the probability of a major outage of one of the two
transformers occurring over the year is very low, at about 1.0% per transformer per annum,

1
                                       The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
                                       in accordance with the composition of the load at this terminal station.


                                                                                                                                                         Page 2 of 6
2010 Transmission Connection Planning Report                                    Risk Assessment: SMTS


whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (9,837 MWh) is weighted by this low transformer unavailability, the expected unserved
energy is estimated to be around 42.7 MWh. This expected unserved energy is estimated to
have a value to consumers of around $2.7 million (based on a value of customer reliability of
$62,463/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate (50th percentile) temperatures occurring in
each year. Under more extreme temperature conditions (that is, at the 10th percentile level),
the energy at risk in 2015 is estimated to be 18,494 MWh. The estimated value to
consumers of this energy at risk in 2015 is approximately $1155 million. The corresponding
value of the expected unserved energy is approximately $5 million.

These key statistics for the year 2015 under N-1 outage conditions are summarised in the
table below.

                                                                   MWh          Valued at consumer
                                                                                 interruption cost
Energy at risk, at 50th percentile demand forecast                9,837             $614.5 million

Expected unserved energy at 50th percentile demand                 42.7              $2.7 million

Energy at risk, at 10th percentile demand forecast              18,494              $1155 million

Expected unserved energy at 10th percentile demand                 80.3               $5 million



If one of the 220/66 kV transformers at SMTS is taken off line during peak loading times and
the N-1 station rating is exceeded, then the Overload Shedding Scheme for Connection
Assets (OSSCA) which is operated by SPI PowerNet’s TOC 2 to protect the connection
assets from overloading 3 , will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at feeder level in accordance with
SPIE and JEN’s operational procedures after the operation of the OSSCA scheme.

Comments on Energy at Risk Assuming Somerton Power Station is available

The previous comments on energy at risk are based on the assumption that there is no
embedded generation available to offset the 220/66 kV transformer loading. The Somerton
Power Station (SPS) is capable of generating up to 140 MVA and this generation is
connected to the SMTS 66 kV bus via SMTS-ST-SSS-SMTS 66 kV loop. There is no firm
commitment that generation will be available to offset transformer loading at SMTS; however
it is most likely that the times of peak demand at SMTS will coincide with the periods of high
wholesale electricity prices, resulting in a high likelihood that SPS will be generating. With
SPS generation available to its full potential there would be no energy at risk at SMTS up to
2015.



2
    Transmission Operation Centre.
3
   OSSCA is designed to protect against transformer damage caused by overloads. Damaged transformers can
take months to replace which can result in prolonged, long term risks to reliability of customer supply.



                                                                                              Page 3 of 6
2010 Transmission Connection Planning Report                                                 Risk Assessment: SMTS


Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging capacity constraints:

1. Implement contingency plans to transfer load to adjacent terminal stations.

2. Install a third 220/66 kV transformer at South Morang Terminal Station (SMTS).

3. Demand Side Management. SPI Electricity is currently using an MVA tariff to encourage
   large customers to improve their power factor and thus reduce load. Up to 50% of the
   maximum demand at SMTS 66 kV is expected to be summer residential load, largely air
   conditioning. With this existing load mix, SPI Electricity does not believe it is realistic to
   expect demand reduction initiatives (eg special tariffs) to play a significant role in
   reducing the peak summer load at SMTS 66 kV.

4. Embedded Generation.     As mentioned above, there is an embedded generator
   connected to SMTS. A network support agreement with SPS or an additional generator
   connected to the SMTS 66 kV bus will help to defer the need for augmentation.

Preferred network option for alleviation of constraints

1. In the event if there are no firm commitments by interested parties to offer network
   support services by installing local generation or through demand side management
   initiatives that would reduce future load at SMTS 66 kV, then it will be proposed to install
   a new 220/66 kV transformer at SMTS 66 kV. This option is economic to be in service by
   summer 2014/15 ignoring any contribution from SPS. However, when the likely
   generation contribution is taken into consideration, installation of a third transformer is not
   expected to be required in the next 8 to 10 years.

    The capital cost of installing a new third 220/66 kV transformer at SMTS is estimated to
    be $17 million including the cost of installing three fault limiting reactors. The cost of
    establishing, operating and maintaining a new transformer would be recovered from
    network users through network charges, over the life of the asset. The estimated total
    annual cost of this network augmentation is approximately $1.7 million. This cost
    provides a broad upper bound indication of the maximum annual network support
    payment which may be available to embedded generators or demand management
    initiatives that results in the deferral of this transmission connection augmentation. 4 Any
    non-network solution that defers this augmentation for say 1-2 years, will not have as
    much potential value (and contribution available from distributors) as a solution that
    eliminates or defers the augmentation for, say, 10 years. Sections 1.4 and 1.5 of this
    report provide further background information to proponents of non-network solutions to
    emerging network constraints.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at SMTS under critical loading conditions from 2011 until the new 220/66 kV
   transformer is commissioned:

    •    maintain contingency plans to transfer load quickly to adjacent terminal stations;


4
         A Rule change proposal is presently before the AEMC to enable distributors to make these payments and recover the
costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-recovery-of-transmission-related-
charges.html). The Rule change, if accepted, would replicate the previous regulatory arrangements in Victoria.




                                                                                                             Page 4 of 6
2010 Transmission Connection Planning Report                          Risk Assessment: SMTS


    •   rely on Somerton Power Station generation to reduce loading at SMTS 66, and
        investigate the possibility of, and need for formalising a network support agreement
        with SPS;

    •   fine-tune the OSSCA scheme settings in conjunction with TOC to minimise the impact
        on customers of any load shedding that may take place to protect the connection
        assets from overloading; and

    •   subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
        metropolitan areas (refer Section 4.5), this spare transformer can be used to
        temporarily replace the failed transformer.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                                  Page 5 of 6
2010 Transmission Connection Planning Report                                            Risk Assessment: SMTS


SOUTH MORANG TERMINAL STATION 66kV (SMTS 66 kV)
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:            SPI Electricity (55%), Jemena Electricity Networks (45%)
Normal cyclic rating with all plant in service               560 MVA via 2 transformers (Summer peaking)
Summer N-1 Station Rating (MVA):                             280
Winter N-1 Station Rating (MVA):                             300

Station: SMTS 66kV                                               2011       2012      2013        2014         2015       2016       2017         2018          2019          2020
50th percentile Summer Maximum Demand (MVA)                      285.6     307.1     334.9       359.0        385.3       411.6      440.0       468.4         499.3          530.6
Summer % Overload [See Note 2 below]                             2.0%      9.7%     19.6%       28.2%        37.6%       47.0%      57.1%       67.3%         78.3%          89.5%
50th percentile Winter Maximum Demand (MVA)                      195.1     206.7     219.3       232.4        245.8       258.1     271.5        285.7         300.0          311.7
Winter % Overload [See Note 2 below]                               Nil        Nil       Nil         Nil          Nil        Nil        Nil          Nil           Nil         3.9%
Annual energy at risk (MWh) [See Note 3 below]                   101.7     507.0    2073.7      4806.3       9837.4     18389.0   32822.2      52330.3       77879.4      107723.1
Annual hours at risk [See Note 4 below]                           11.4      32.6     101.9       179.2        326.8       558.3     885.3       1143.1        1389.7         1613.6
Expected Annual Unserved Energy (MWh) [See Note 5
                                                                   0.4        2.2       9.0       20.9         42.7        79.8     142.4        227.1         338.0          467.5
below]
Expected Annual Unserved Energy valued in accordance
with the Value of Customer Reliability as estimated in the
                                                              $27,580 $137,432 $562,156 $1,302,936 $2,666,821 $4,985,050 $8,897,745 $14,186,197 $21,112,291             $29,202,604
August 2009 study commissioned by AEMO[See Note 6
below]



Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                         Page 6 of 6
2010 Transmission Connection Planning Report                                                                                   Risk Assessment: SVTS


SPRINGVALE TERMINAL STATION (SVTS)

Magnitude, probability and impact of loss of load

SVTS was augmented with a new 150 MVA 220/66 kV transformer in 2006 to reinforce the
security and reliability of supply for customers in the area. The station now has four 150
MVA 220/66 kV transformers, and is the main source of supply for a major part of the eastern
metropolitan area. The geographic coverage of the station’s supply area spans from
Blackburn in the north to Keysborough in the south, and from Wantirna South in the east to
Riversdale in the west. The electricity supply network for this large region is split between
United Energy Distribution (UED) and CitiPower (CP).

SVTS 66 kV is a summer peaking station. The peak load on the station reached 478.9 MW
(490.7 MVA) in summer 2009. The recorded peak demand in summer 2010 was 449.3MW
(462.6MVA), which was approximately 29 MW lower than the 2009 peak. This is attributed
to the comparatively mild weather conditions observed during summer 2010.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational N rating (all transformers in service) and the N-1 rating
at 35°C as well as 40°C ambient temperature.


                                                           SVTS Summer Peak Forecasts
         700.0



         650.0

                                                                                                                10% PoE
         600.0


                                                                         Actual          Forecast
         550.0
                         N Rating @ 35 deg C
                                                                                                                                                 50% PoE
   MVA




         500.0
                        N Rating @ 40 deg C

         450.0



         400.0


                                               N -1 Rating @ 35 deg C
         350.0

                                               N -1 Rating @ 40 deg C
         300.0
                 2001   2002   2003   2004   2005   2006   2007   2008   2009     2010   2011   2012   2013   2014   2015   2016   2017   2018    2019     2020
                                                                                     Year




The N rating on the chart indicates the maximum load that can be supplied from SVTS with
all transformers in service. Exceeding this level will initiate SPI PowerNet’s automatic load
shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.




                                                                                                                                                    Page 1 of 5
2010 Transmission Connection Planning Report                                                                                           Risk Assessment: SVTS



                                                     Annual Energy and Hours at Risk at SVTS (Single Contingency Only)

                                                 Hours at Risk (LH scale)          Energy at Risk MWh (LH scale)           Customer Value (RH scale)

                                  1,250                                                                                                                   $800,000


                                  1,125                                                                                                                   $720,000


                                  1,000                                                                                                                   $640,000


                                   875                                                                                                                    $560,000
    MWh at Risk / Hours at Risk




                                   750                                                                                                                    $480,000


                                   625                                                                                                                    $400,000


                                   500                                                                                                                    $320,000


                                   375                                                                                                                    $240,000


                                   250                                                                                                                    $160,000


                                   125                                                                                                                    $80,000


                                     0                                                                                                                    $0
                                          2011       2012          2013     2014       2015          2016          2017   2018       2019         2020
                                                                                              Year




Comments on Energy at Risk

For an outage of one transformer at SVTS, it is expected that from 2014, there would be
insufficient capacity at the station to supply all demand at the 50th percentile temperature.

By the end of the ten-year planning period in 2020, the energy at risk under N-1 conditions is
estimated to be 1,006 MWh at the 50th percentile demand forecast. Under these conditions,
there would be insufficient capacity to meet demand for 33 hours in that year. The estimated
value to customers of the 1,006 MWh of energy at risk in 2020 is approximately $78.6 million
(based on a value of customer reliability of $78,135/MWh) 1 . In other words, at the 50th
percentile demand level, and in the absence of any other operational response that might be
taken to mitigate the impact of a forced outage, a major outage of one transformer at SVTS
over the summer of 2020 would be anticipated to lead to involuntary supply interruptions that
would cost consumers $78.6 million.

It is emphasised however, that the probability of a major outage of one of the four
transformers occurring over the year is very low at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (1,006 MWh in 2020) is weighted by this low unavailability, the expected unserved
energy is estimated to be around 8.6 MWh. This expected unserved energy is estimated to
have a value to consumers of around $675,000 (based on a value of customer reliability of
$78,135/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2020 is estimated to be 1,548 MWh. The estimated value to consumers of this
energy at risk in 2020 is approximately $121.0 million. The corresponding value of the
expected unserved energy is approximately $1.0 million.

1
                                      The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
                                      in accordance with the composition of the load at this terminal station.


                                                                                                                                                         Page 2 of 5
2010 Transmission Connection Planning Report                             Risk Assessment: SVTS


These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                            MWh         Valued at consumer
                                                                         interruption cost
Energy at risk, at 50th percentile demand forecast         1,006            $78.6 million

Expected unserved energy at 50th percentile demand            8.6             $675,000

Energy at risk, at 10th percentile demand forecast         1,548           $121.0 million

Expected unserved energy at 10th percentile demand          13.3             $1.0 million


If one of the 220/66 kV transformers at SVTS is taken off line during peak loading times and
the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by
SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at zone substation feeder level in
accordance with United Energy’s and CitiPower’s operational procedures after the operation
of the OSSCA scheme.

In the case of SVTS supply at maximum loading periods, and based on the Schedule of
Priority Load Shedding recommended by the Demand Reduction Committee, the OSSCA
scheme would shed about 110 MVA of load, affecting approximately 23,500 customers in
2011.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement a contingency plan to transfer load to adjacent terminal stations. Both United
   Energy Distribution and CitiPower have established and implemented the necessary
   plans that enable load transfers under contingency conditions via the 66 kV
   subtransmission and/or the high voltage 22 kV and 11 kV distribution networks.

2. Establish a new 220/66 kV terminal station. There are no vacant terminal station sites in
   the area and the cost of acquiring a new site would, very likely, make such an option
   uneconomic.

3. Install a third 225 MVA 220/66 kV transformer at Malvern terminal station (MTS) to off-
   load SVTS. In the absence of any vacant site, a third transformer at MTS becomes the
   least-cost, technically feasible option.

4. Demand reduction: United Energy Distribution has developed a number of innovative
   network tariffs to encourage voluntary demand reduction during times of network
   constraints. The amount of demand reduction depends on the tariff uptake and the
   subsequent change in load pattern and will be taken into consideration when determining
   the optimum timing for the capacity augmentation.



2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre


                                                                                     Page 3 of 5
2010 Transmission Connection Planning Report                                           Risk Assessment: SVTS


5. Embedded generation, in the order of 20 MVA, connected to the network supplied by the
   SVTS 66 kV bus, will help to defer augmentation in the area by one year.

Preferred network option(s) for alleviation of constraints

1. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at SVTS under critical loading conditions:

    •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

    •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
        impact on customers of any automatic load shedding that may take place; and

    •   subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
        metropolitan areas (refer to Section 4.5), this spare transformer can be used to
        temporarily replace the failed transformer.
2. In the absence of any commitment by interested parties to offer network support services
   by installing local generation or through demand side management initiatives that would
   reduce load at SVTS, it is proposed to install a new 225 MVA 220/66 kV transformer at
   MTS. On the present forecasts an additional transformer at MTS to off-load SVTS is not
   likely to be required within the ten year planning horizon. The capital cost of installing a
   225 MVA 220/66 kV transformer at MTS is estimated to be $16 million (this excludes
   66 kV line works required to off-load SVTS). The cost of establishing, operating and
   maintaining a new transformer would be recovered from network users through network
   charges, over the life of the asset.

    The estimated total annual cost of the transmission component of this network
    augmentation is approximately $1.6 million (excluding 66 kV line works). This cost
    provides a broad upper bound indication of the maximum network support payment which
    may be available to embedded generators or customers to reduce forecast demand, and
    to defer or avoid the transmission connection component of this augmentation. 4 Sections
    1.4 and 1.5 of this report provide further background information to proponents of non-
    network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.




                                                                                                     Page 4 of 5
2010 Transmission Connection Planning Report                                            Risk Assessment: SVTS


SPRINGVALE TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                United Energy Distribution (92.3%) and CitiPower (7.7%)
Station operational rating (N elements in service):              673 MVA via 4 transformers (Summer peaking)
Summer N-1 Station Rating:                                       505 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       560 MVA


Station: SVTS 66 kV                                            2011       2012      2013       2014         2015        2016         2017        2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                   472.8      486.7      501.2     513.0        516.6       529.3        541.2       549.7        562.6        575.1
Summer % Overload [See Note 2 below]                             Nil        Nil        Nil       2%          2%           5%          7%           9%         11%          14%
  th
50 percentile Winter Maximum Demand (MVA)                     359.1      365.6      366.2     367.3        369.8       379.3        385.7       391.3        397.9        404.3
Winter % Overload [See Note 2 below]                             Nil        Nil        Nil       Nil          Nil         Nil          Nil          Nil         Nil          Nil
Annual energy at risk (MWh) [See Note 3 below]                     0         0          0         43          69         183          324         455          689        1,006
Annual hours at risk [See Note 4 below]                            0         0          0          8           9           11          15           19          23           33
Expected annual unserved energy (MWh) [See Note 5
                                                                 0.0       0.0        0.0        0.4         0.6          1.6         2.8          3.9          5.9         8.6
below]
Expected Annual Unserved Energy value [See Note 6
                                                                  $k        $k         $k      $29k         $46k       $123k       $218k        $305k       $462k        $675k
below]

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                        Page 5 of 5
2010 Transmission Connection Planning Report                                                                                      Risk Assessment: TBTS


TYABB TERMINAL STATION (TBTS)

Magnitude, probability and impact of loss of load

TBTS consists of two 150 MVA 220/66 kV transformers, and is the main source of supply for
over 113,000 customers on the Mornington Peninsula. The geographic coverage of the area
spans from Frankston in the north to Portsea in the south.

TBTS 66 kV is a summer critical station. Summer peak demand at TBTS generally occurs on
days of high ambient temperature during the summer holiday period (from 25 December to the
end of January). The station reached its highest recorded peak demand of 283.4 MW (298.0
MVA) on Thursday 29 January 2009 when the ambient temperature in Mornington reached
42ºC. The peak demand in summer 2010 was 265.8 MW (277.1 MVA), which was
approximately 18 MW below the 2009 peak. This is mainly attributed to permanent load
transfers from TBTS to CBTS implemented by United Energy Distribution prior to summer 2010,
and the comparatively mild weather conditions observed during summer 2010.

Major sub-transmission line works completed in 2001 resulted in transfer of about 100 MVA of
load away from critically loaded terminal stations at East Rowville (ERTS) and Heatherton
(HTS) to TBTS for summer 2002. As the result of this transfer, TBTS has exceeded its N-1
thermal rating since summer 2003.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational N rating (all transformers in service) and the N-1 rating at
35°C as well as 40°C ambient temperature.
                                                           TBTS Summer Peak Forecasts
        450.0


                       N Rating @ 35 deg C
        400.0

                   N Rating @ 40 deg C                                             10% PoE
        350.0



        300.0                                                                                                             50% PoE
  MVA




        250.0

                                                                                                                                 N -1 Rating @ 35 deg C
        200.0
                                                                                                                             N -1 Rating @ 40 deg C
                                                                          Actual          Forecast
        150.0



        100.0



         50.0
                2001    2002   2003   2004   2005   2006   2007   2008   2009   2010   2011   2012   2013   2014   2015   2016     2017   2018   2019     2020
                                                                                   Year


The N rating on the chart indicates the maximum load that can be supplied from TBTS with all
transformers in service. Exceeding this level will initiate SPI PowerNet’s automatic load
shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast is
expected to exceed the N-1 capability rating. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.



                                                                                                                                                            Page 1 of 6
2010 Transmission Connection Planning Report                                                                                                 Risk Assessment: TBTS


                                                      Annual Energy and Hours at Risk at TBTS (Single Contingency Only)

                                                  Hours at Risk (LH scale)          Energy at Risk MWh (LH scale)           Customer Value (RH scale)

                                  30,000                                                                                                                $7,000,000


                                  27,000                                                                                                                $6,300,000


                                  24,000                                                                                                                $5,600,000


                                  21,000                                                                                                                $4,900,000
    MWh at Risk / Hours at Risk




                                  18,000                                                                                                                $4,200,000


                                  15,000                                                                                                                $3,500,000


                                  12,000                                                                                                                $2,800,000


                                   9,000                                                                                                                $2,100,000


                                   6,000                                                                                                                $1,400,000


                                   3,000                                                                                                                $700,000


                                      0                                                                                                                 $0
                                           2011        2012         2013     2014       2015          2016          2017   2018      2019        2020
                                                                                               Year




Comments on Energy at Risk

For an outage of one transformer at TBTS, there will be insufficient capacity at the station to
supply all demand at the 50th percentile temperature for about 270 hours in 2014. The energy
at risk at the 50th percentile temperature under N-1 conditions is estimated to be 9,333 MWh in
2014. The estimated value to consumers of the 9,333 MWh of energy at risk in 2014 is
approximately $516 million (based on a value of customer reliability of $55,338/MWh) 1 . In other
words, at the 50th percentile demand level, and in the absence of any other operational
response that might be taken to mitigate the impact of a forced outage, a major outage of one
transformer at TBTS in 2014 would be anticipated to lead to involuntary supply interruptions that
would cost consumers approximately $516 million.

It is emphasised however, that the probability of a major outage of one of the two transformers
occurring over the year is very low at about 1.0% per transformer per annum, whilst the
expected unavailability per transformer per annum is 0.217%. When the energy at risk (9,333
MWh in 2014) is weighted by this low unavailability, the expected unserved energy is estimated
to be around 40.3 MWh. This expected unserved energy is estimated to have a value to
consumers of around $2.2 million (based on a value of customer reliability of $55,338/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year. Under
more extreme temperature conditions (that is, at the 10th percentile level), the energy at risk in
2014 is estimated to be 10,686 MWh. The estimated value to consumers of this energy at risk
in 2014 is approximately $591 million. The corresponding value of the expected unserved
energy is approximately $2.6 million.

These key statistics for the year 2014 under N-1 outage conditions are summarised in the table
below.


1
                                       The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in
                                       accordance with the composition of the load at this terminal station.


                                                                                                                                                                   Page 2 of 6
2010 Transmission Connection Planning Report                             Risk Assessment: TBTS


                                                            MWh         Valued at consumer
                                                                         interruption cost
Energy at risk, at 50th percentile demand forecast         9,333            $516 million

Expected unserved energy at 50th percentile demand          40.3             $2.2 million

Energy at risk, at 10th percentile demand forecast        10,686            $591 million

Expected unserved energy at 10th percentile demand          46.1             $2.6 million


If one of the 220/66 kV transformers at TBTS is taken off line during peak loading times and the
N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by SPI
PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading limits. Any
load reductions that are in excess of the minimum amount required to limit load to the rated
capability of the station would be restored at zone substation feeder level in accordance with
United Energy’s operational procedures after the operation of the OSSCA scheme.

In the case of TBTS supply at maximum loading periods, and based on the Schedule of Priority
Load Shedding recommended by the Demand Reduction Committee, the OSSCA scheme
would shed about 100 MVA of load, affecting approximately 47,500 customers in 2011.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement a contingency plan to transfer load to adjacent terminal stations. United Energy
   Distribution has established and implemented the necessary plans that enable load
   transfers under contingency conditions via both 66 kV subtransmission and 22 kV
   distribution networks.

2. Install a third 220/66 kV transformer at TBTS. There is provision in the existing yard for an
   additional transformer.

3. Demand Side Management: United Energy Distribution has developed a number of
   innovative network tariffs that encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and the
   subsequent change in load pattern, and will be taken into consideration when determining
   the optimum timing for the capacity augmentation.

4. Embedded generation, in the order of 25 MVA, connected to the network supplied by TBTS
   66 kV bus, can defer the need of a new 220/66 kV transformer at TBTS by one year.




2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operation Centre


                                                                                        Page 3 of 6
2010 Transmission Connection Planning Report                                         Risk Assessment: TBTS


Preferred network option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at TBTS, it is proposed to:

1. Install a third 150 MVA 220/66 kV transformer at TBTS.

2. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at TBTS under critical loading conditions:

        •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

        •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
            impact on customers of any automatic load shedding that may take place; and
        •   subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
            metropolitan areas (refer to Section 4.5) this spare transformer can be used to
            temporarily replace the failed transformer.

The capital cost of installing a 220/66 kV transformer at TBTS is estimated to be $15 million.
The cost of establishing, operating and maintaining a new transformer would be recovered from
network users through network charges, over the life of the asset. The estimated total annual
cost of this network augmentation is approximately $1.5 million. This cost provides a broad
upper bound indication of the maximum network support payment which may be available to
embedded generators or customers to reduce forecast demand, and to defer or avoid the
transmission connection component of this augmentation. 4 Any non-network solution that
defers this augmentation for say 1-2 years, will not have as much potential value (and
contribution available from distributors) as a solution that eliminates or defers the augmentation
for, say, 10 years.

Any non-network proposal must be submitted with detailed plans to United Energy Distribution
for consideration no later than 31 March 2011 . This will ensure that sufficient time is available
to implement the most cost-effective measure(s) to manage the risk of supply interruption, and
to maintain a satisfactory level of supply reliability. Sections 1.4 and 1.5 of this report provide
further background information to proponents of non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy. On the present 50th percentile
forecasts, as shown in the table, the customer value of expected unserved energy ($1.8 million)
exceeds the annualised cost of the preferred option ($1.5 million) in 2013, hence, the preferred
option should be implemented by the end of 2012 so that additional capacity is available during
summer 2012/13. However, the typical implementation timeframe for this type of augmentation
may be up to three years. Therefore, the practically feasible completion of the preferred option
is likely to be the end of 2013. United Energy Distribution will work closely with SPI PowerNet to


4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments and
        recover the costs from customers (see http://www.aemc.gov.au/Electricity/Rule-changes/Open/DNSP-
        recovery-of-transmission-related-charges.html). The Rule change, if accepted, would replicate the previous
        regulatory arrangements in Victoria.




                                                                                                      Page 4 of 6
2010 Transmission Connection Planning Report                       Risk Assessment: TBTS


ensure that any network-based solution to the emerging constraint is delivered in the most
timely possible manner.




                                                                                 Page 5 of 6
2010 Transmission Connection Planning Report                                            Risk Assessment: TBTS




TYABB TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                United Energy Distribution (100%)
Station operational rating (N elements in service):              389 MVA via 2 transformers (Summer peaking)
Summer N-1 Station Rating:                                       195 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       206 MVA


Station: TBTS 66 kV                                           2011        2012        2013       2014        2015        2016        2017        2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                  293.4       301.6       312.8       324.1      328.0       338.0       347.8       354.6        365.2        375.4
Summer % Overload [See Note 2 below]                           51%        55%         61%         67%         69%        74%         79%          82%         88%          93%
  th
50 percentile Winter Maximum Demand (MVA)                    206.7       210.1       210.2       210.5      211.6       216.7       220.0       222.9        226.3        229.6
Winter % Overload [See Note 2 below]                            0%          2%         2%          2%          3%          5%         7%           8%         10%          11%
Annual energy at risk (MWh) [See Note 3 below]               4,932       5,935       7,488       9,333     10,050      12,173      14,746      16,932       21,015      26,267
Annual hours at risk [See Note 4 below]                        165         190         231         270        295         389         497         605          814        1,063
Expected annual unserved energy (MWh) [See Note 5
                                                               21.3       25.6        32.3        40.3        43.4       52.5        63.6         73.1        90.7        113.3
below]
Expected Annual Unserved Energy value [See Note 6
                                                           $1,177k     $1,417k     $1,788k    $2,228k     $2,400k     $2,906k     $3,521k     $4,043k      $5,018k     $6,272k
below]

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
                                                                                        th
4. “Annual hours per year at risk” is the number of hours in a year during which the 50 percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                        Page 6 of 6
2010 Transmission Connection Planning Report                                                                               Risk Assessment: TGTS



TERANG TERMINAL STATION (TGTS) 66 kV

Terang Terminal Station (TGTS) 66 kV consists of one 125 MVA transformer and one 150
MVA 220/66 kV transformer and is the main source of supply for over 64,700 customers in
Terang and the surrounding area. The terminal station supply area includes Terang, Colac,
Camperdown, Cobden, Warrnambool, Koroit, Portland and Hamilton.

Magnitude, probability and impact of loss of load

In 2007, as part of its asset replacement program, SPI PowerNet replaced the existing 1A
and 1B 125 MVA single phase transformer bank at the station with a new 150 MVA three
phase transformer unit. This has marginally increased the cyclic rating of the station as the
previous cyclic rating was based on the rating of the 1A & 1B transformer bank (i.e. for loss
of the #2 transformer). This step change in station cyclic rating is depicted in the graph
below.

TGTS 66 kV demand is summer peaking but peaks can occur in spring depending upon the
dairy industry load. Growth in summer peak demand at TGTS has averaged around 9.1 MW
(5%) per annum over the last 5 years. The peak load on the station reached 179.1 MW in
summer 2010. This is down on the Summer 2009 peak mainly due to the generation input
of the two wind farms on the KRT-PLD No1 & No 2 66 kV lines.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N-1”
rating at 35°C.
                                                   TGTS 66kV Summer Peak Forecasts

        400.0
                                                                       Actuals                     Forecasts


        350.0    (N) rating @ 35 deg C


        300.0



        250.0                                                                           10% Weather Probability Forecast
  MVA




        200.0

                 (N-1) Rating @ 35 deg C
        150.0
                                                                                                          50% Weather Probability Forecast
                                                  30 min interval data used from 2010, as
                                                  per AEMO revised standard.
        100.0



         50.0



          0.0
                1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
                                                                                 Year


The (N) rating on the chart indicates the maximum load that can be supplied from TGTS with
all transformers in service.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to



                                                                                                                                             Page 1 of 5
2010 Transmission Connection Planning Report                                                                                             Risk Assessment: TGTS



consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.

                                                                            Annual Energy and Hours at Risk at TGTS

                                                 Hours at risk (LH Scale)         Energy at risk (MWh) (LH Scale)          Customer Value (RH Scale)

                                 1200.0                                                                                                                         $350,000



                                                                                                                                                                $300,000
                                 1000.0


                                                                                                                                                                $250,000
    MWhr at Risk/Hours at Risk




                                  800.0

                                                                                                                                                                $200,000

                                  600.0

                                                                                                                                                                $150,000

                                  400.0
                                                                                                                                                                $100,000


                                  200.0
                                                                                                                                                                $50,000



                                    0.0                                                                                                                         $0
                                          2011         2012          2013      2014       2015          2016        2017      2018        2019         2020
                                                                                                 Year



Comments on Energy at Risk

For an outage of one transformer at TGTS, there will be insufficient capacity at the station to
supply all demand at the 50th percentile temperature for about 91 hours in 2020. The energy
at risk at the 50th percentile temperature under N-1 conditions is estimated to be 971 MWh in
2020. The estimated value to consumers of the 971 MWh of energy at risk is approximately
$75 million (based on a value of customer reliability of $77,190 per MWh). 1 In other words,
at the 50th percentile demand level, and in the absence of any other operational response
that might be taken to mitigate the impact of a forced outage, a major outage of one
transformer at TGTS in 2020 would be anticipated to lead to involuntary supply interruptions
that would cost consumers $75 million.

It is emphasised however, that the probability of a major outage of one of the two
transformers occurring over the year is very low at about 1.0% per transformer per annum,
while the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (971 MWh for 2020) is weighted by this low unavailability, the expected unsupplied
energy is estimated to be around 4.2 MWh. This expected unserved energy is estimated to
have a value to consumers of around $324,900 (based on a value of customer reliability of
$77,190 per MWh).

The demand at Terang Terminal Station is driven primarily by the dairy industry, and is
therefore relatively insensitive to summer temperature variations. Therefore, the demand
forecasts for the 10th percentile and 50th percentile temperatures are similar.

Key statistics relating to energy at risk and expected unserved energy for the year 2020
under N-1 outage conditions are summarised in the table below.
1
                                      The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3,
                                      weighted in accordance with the composition of the load at this terminal station.



                                                                                                                                                              Page 2 of 5
2010 Transmission Connection Planning Report                                Risk Assessment: TGTS




                                                               MWh         Valued at consumer
                                                                            interruption cost
Energy at risk, at 50th percentile demand forecast              971              $75 million

Expected unserved energy at 50th percentile demand               4.2             $324,900

Energy at risk, at 10th percentile demand forecast            2,508            $193.6 million

Expected unserved energy at 10th percentile demand             10.9              $839,000



Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

•        Replacing the #2 125 MVA 220/66 kV transformer at TGTS with a 150 MVA unit.
         For an indicative installation cost of $3 million this option will most likely prove to be
         uneconomic as it only provides a marginal increase in station capacity, hence
         necessitating additional capacity augmentation shortly afterwards.

•        Installation of a third 220/66 kV transformer (150 MVA) at TGTS.

•        Demand reduction: There is an opportunity to develop a number of innovative
         customer schemes to encourage voluntary demand reduction during times of
         network constraint. The amount of demand reduction would depend on the
         customer uptake and would be taken into consideration when determining the
         optimum timing for the capacity augmentation.

•        Embedded generation. Connection of ‘wind farm’ generation into the 66 kV
         infrastructure ex-TGTS has been implemented. Yambuk wind farm (30 MW) was
         commissioned in 2005 and this combined with Codrington wind farm (18.2 MW
         commissioned in 2001) provides a total wind generation capacity of 48.2 MW.
         Additional wind generation is being investigated in the area supplied by TGTS and
         may defer any capacity augmentation planned for TGTS.

Preferred option(s) for alleviation of constraints

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at TGTS, it is proposed to:

1. Install a third 220/66 kV transformer (150 MVA) at TGTS. On the basis of the medium
   economic growth scenario and 50th percentile weather probability, the transformer would
   not be expected to be commissioned before 2020 to support the critical peak demand.
   As previously stated, the impact of connected ‘wind farm’ generation may defer the need
   for network augmentation;




                                                                                        Page 3 of 5
2010 Transmission Connection Planning Report                                          Risk Assessment: TGTS



2. as a temporary measure, maintain contingency plans to transfer load quickly to the
   Geelong terminal station by the use of the 66 kV tie lines between TGTS and GTS in the
   event of an unplanned outage of one transformer at TGTS under critical loading
   conditions. This load transfer is in the order of 15 MVA. Under these temporary
   measures, affected customers would be supplied from the 66 kV tie line infrastructure on
   a radial network, thereby reducing their level of reliability;

3. subject to the availability of the SPI PowerNet spare 220/66 kV transformer for rural
   areas (refer Section 4.5), this spare transformer can be used to temporarily replace a
   failed transformer to minimise the transformer outage period.

The capital cost of installing a 150 MVA 220/66 kV transformer at TGTS is estimated to be
$13.5 million. The cost of establishing, operating and maintaining a new transformer would
be recovered from network users through network charges, over the life of the asset. The
estimated total annual cost of this network augmentation is $1.3 million. This cost provides
a broad upper bound indication of the maximum network support payment which may be
available 2 to embedded generators or customers to reduce forecast demand and defer or
avoid the transmission connection component of this augmentation. Any non-network
solution that defers this augmentation for say 1-2 years, will not have as much potential
value (and contribution available from distributors) as a solution that eliminates or defers the
augmentation for, say, 10 years. Sections 1.5 and 1.6 of this report provide further
background information to proponents of non-network solutions to emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




2
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers   (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.



                                                                                                    Page 4 of 5
2010 Transmission Connection Planning Report                                            Risk Assessment: TGTS


TGTS Terminal Station
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                Powercor (100%)


                                                                 MW          MVA
Normal cyclic rating with all plant in service                               357        via 2 transformers (summer)
Summer N-1 Station Rating:                                       172         177        [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       179         182        [See Note 7 below for revised rating]


Station: TGTS 66kV
                                                        2011        2012       2013        2014       2015         2016        2017         2018         2019          2020
50th percentile Summer Maximum Demand (MVA)             188.0       192.0      194.1       195.5      196.9       198.2        199.6        201.0        202.4        203.8
Summer % Overload [See Note 2 below]                     6.22       8.50        9.65       10.46      11.22       11.99        12.76        13.54        14.33        15.12
50th percentile Winter Maximum Demand (MVA)             188.0       190.8      192.7       193.8      195.1       196.5        197.8        199.2        200.6        201.9
Winter % Overload [See Note 2 below]                     3.28       4.85        5.88       6.48        7.21        7.95         8.69        9.44         10.20        10.96
Annual energy at risk (MWh) [See Note 3 below]           79.1       167.2      243.0       305.5      382.0       470.1        571.1        685.0        818.1        971.3
Annual hours at risk [See Note 4 below]                  13.3       23.3        33.0       37.8        47.5        55.3         64.5        71.3         82.0          91.0
Expected Annual Unserved Energy (MWh) [See
Note 5 below]                                            0.34       0.72        1.05       1.32        1.66        2.04         2.47        2.97         3.55          4.21
Expected Annual Unserved Energy value [See Note
6 below]                                               $26,473 $55,928 $81,269 $102,171 $127,791 $157,239 $191,026 $229,123 $273,655                                $324,879

Notes:
1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
                                             th
2.   This is the percentage by which the 50 percentile forecast maximum demand exceeds the N-1 capability rating.
3.   “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4.   “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5.   “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
     outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
     station.
7.   The 1A & 1B 125 MVA single phase transformer bank was replaced by a 150 MVA three phase transformer unit in 2007 as part of SPI PowerNet’s asset replacement
     program. This has marginally increased the summer and winter N-1 station ratings as shown above.




                                                                                                                                                                     Page 5 of 5
2010 Transmission Connection Planning Report                                                                                Risk Assessment: TSTS


TEMPLESTOWE TERMINAL STATION (TSTS)

Magnitude, probability and impact of loss of load

TSTS consists of three 150 MVA 220/66 kV transformers, and is the main source of supply
for a major part of the north-eastern metropolitan area. The geographic coverage of the
supply area spans from Eltham in the north to Canterbury in the south, and from Mitcham in
the east to Kew in the west. The electricity supply network for this large region is split
between United Energy Distribution, CitiPower, SPI Electricity and Jemena Electricity
Networks.

TSTS 66 kV is critically loaded in summer. The load on the station reached 357.6 MW
(377.1 MVA) in summer 2009. The recorded peak demand in summer 2010 was 335.6 MW
(351.2 MVA), which was approximately 22 MW lower than the 2009 peak. This is attributed
to the comparatively mild weather conditions observed during summer 2010.

The graph below depicts the 50th percentile summer maximum demand forecast together
with the station’s operational N rating (all transformers in service) and the N-1 rating at 35°C
as well as 40°C ambient temperature.


                                                          TSTS Summer Peak Forecasts
        600.0

                                                                                                                                  N Rating @ 35 deg C
        550.0

                                                                                                                                  N Rating @ 40 deg C
        500.0
                                                                                                              10% PoE
                                                                        Actual          Forecast
        450.0
  MVA




        400.0
                                                                                                                                     N -1 Rating @ 35 deg C

        350.0
                                                                                                         50% PoE                     N -1 Rating @ 40 deg C


        300.0



        250.0



        200.0
                2001   2002   2003   2004   2005   2006   2007   2008   2009     2010   2011   2012   2013   2014   2015   2016    2017   2018   2019   2020
                                                                                    Year



The N-1 rating at TSTS was restricted by over-voltage limits on transformer tapping until
summer 2004. With the installation of a 50 MVAr capacitor bank at TSTS in December 2002
and improvement in station power factor from 0.85 in 1994 to 0.91 in 2004, the station rating
was subsequently reviewed and increased in 2004.              The review, carried out by
SPI PowerNet, indicated that the over-voltage limit on transformer tapping was no longer a
constraint and could be removed.

The N rating on the chart indicates the maximum load that can be supplied from TSTS with
all transformers in service. Exceeding this level will initiate SPI PowerNet’s automatic load
shedding scheme.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast

                                                                                                                                                 Page 1 of 5
2010 Transmission Connection Planning Report                                                                                              Risk Assessment: TSTS


is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.

                                                        Annual Energy and Hours at Risk at TSTS (Single Contingency Only)

                                                    Hours at Risk (LH scale)          Energy at Risk MWh (LH scale)           Customer Value (RH scale)

                                  1,500                                                                                                                      $500,000


                                  1,350                                                                                                                      $450,000


                                  1,200                                                                                                                      $400,000


                                  1,050                                                                                                                      $350,000
    MWh at Risk / Hours at Risk




                                   900                                                                                                                       $300,000


                                   750                                                                                                                       $250,000


                                   600                                                                                                                       $200,000


                                   450                                                                                                                       $150,000


                                   300                                                                                                                       $100,000


                                   150                                                                                                                       $50,000


                                     0                                                                                                                       $0
                                             2011       2012          2013     2014       2015          2016          2017   2018       2019         2020
                                                                                                 Year




Comments on Energy at Risk

For an outage of one transformer at TSTS, it is expected that from 2012, there would be
insufficient capacity at the station to supply all demand at the 50th percentile temperature.

By the end of the ten-year planning period in 2020, the energy at risk under N-1 conditions is
1,198 MWh at the 50th percentile demand forecast. Under these conditions, there would be
insufficient capacity to meet demand for 45 hours in that year. The estimated value to
customers of the 1,198 MWh of energy at risk in 2020 is approximately $63.3 million (based
on a value of customer reliability of $52,848/MWh) 1 . In other words, at the 50th percentile
demand level, and in the absence of any other operational response that might be taken to
mitigate the impact of a forced outage, a major outage of one transformer at TSTS over the
summer of 2020 would be anticipated to lead to involuntary supply interruptions that would
cost consumers $63.3 million.

It is emphasised however, that the probability of a major outage of one of the three
transformers occurring over the year is very low at about 1.0% per transformer per annum,
whilst the expected unavailability per transformer per annum is 0.217%. When the energy at
risk (1,198 MWh in 2020) is weighted by this low unavailability, the expected unserved
energy is estimated to be around 7.7 MWh. This expected unserved energy is estimated to
have a value to consumers of around $409,000 (based on a value of customer reliability of
$52,848/MWh).




1
                                          The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted
                                          in accordance with the composition of the load at this terminal station.


                                                                                                                                                            Page 2 of 5
2010 Transmission Connection Planning Report                             Risk Assessment: TSTS


It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate temperatures occurring in each year.
Under more extreme temperature conditions (that is, at the 10th percentile level), the energy
at risk in 2020 is estimated to be 2,339 MWh. The estimated value to consumers of this
energy at risk in 2020 is approximately $123.6 million. The corresponding value of the
expected unserved energy is approximately $798,000.

These key statistics for the year 2020 under N-1 outage conditions are summarised in the
table below.

                                                            MWh         Valued at consumer
                                                                         interruption cost
Energy at risk, at 50th percentile demand forecast         1,198            $63.3 million

Expected unserved energy at 50th percentile demand            7.7             $409,000

Energy at risk, at 10th percentile demand forecast         2,339           $123.6 million

Expected unserved energy at 10th percentile demand          15.1              $798,000



If one of the 220/66 kV transformers at TSTS is taken off line during peak loading times and
the N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by
SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading
limits. Any load reductions that are in excess of the minimum amount required to limit load to
the rated capability of the station would be restored at zone substation feeder level in
accordance with each distribution company’s operational procedures after the operation of
the OSSCA scheme.

In the case of TSTS supply at maximum loading periods, and based on the Schedule of
Priority Load Shedding recommended by the Demand Reduction Committee, the OSSCA
scheme would shed about 70 MW of load, affecting approximately 20,000 customers in
2011.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Implement a contingency plan to transfer load to adjacent terminal stations. United
   Energy Distribution, CitiPower, SPI Electricity and Jemena Electricity Networks have
   established and implemented the necessary plans that enable load transfers under
   contingency conditions.

2. Establish a new 220/66 kV terminal station. Two terminal station sites, one in Doncaster
   (DCTS) and another in Kew (KWTS), have been reserved for possible future electrical
   infrastructure development to meet customers’ needs in the area. With established
   220 kV tower lines to both sites, development of either of these sites could be economic
   depending upon the geographical location of additional customer load.



2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre


                                                                                     Page 3 of 5
2010 Transmission Connection Planning Report                                           Risk Assessment: TSTS


3. Install a fourth 150 MVA 220/66 kV transformers at TSTS. There is provision in the yard
   for an additional transformer.

4. Demand Side Management: United Energy Distribution has developed a number of
   innovative network tariffs that will encourage voluntary demand reduction during times of
   network constraints. The amount of demand reduction depends on the tariff uptake and
   the subsequent change in load pattern, and will be taken into consideration when
   determining the optimum timing for any capacity augmentation.

5. Embedded generation, in the order of 20 MVA, connected to the network supplied by
   TSTS 66 kV bus, will help to defer augmentation in the area by one year.

Preferred network option(s) for alleviation of constraints

1. Implement the following temporary measures to cater for an unplanned outage of one
   transformer at TSTS under critical loading conditions:

        •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

        •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
            impact on customers of any load shedding that may take place; and
        •   subject to the availability of SPI PowerNet’s spare 220/66 kV transformer for
            metropolitan areas (refer to Section 4.5), this spare transformer can be used to
            temporarily replace the failed transformer.

2. In the absence of any commitment by interested parties to offer network support services
   by installing local generation or through demand side management initiatives that would
   reduce load at TSTS, it is proposed to install a new 220/66 kV transformer at TSTS. On
   the present forecasts an additional 220/66 kV transformer is not likely to be required
   within the ten year planning horizon. The capital cost of installing a 220/66 kV
   transformer at TSTS is estimated to be $14 million. The cost of establishing, operating
   and maintaining a new transformer would be recovered from network users through
   network charges, over the life of the asset.

    The estimated total annual cost of the transmission component of this network
    augmentation is approximately $1.4 million. This cost provides a broad upper bound
    indication of the maximum network support payment which may be available to
    embedded generators or customers to reduce forecast demand, and to defer or avoid the
    transmission connection component of this augmentation. 4 Sections 1.4 and 1.5 of this
    report provide further background information to proponents of non-network solutions to
    emerging constraints.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




4
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers    (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria.




                                                                                                     Page 4 of 5
2010 Transmission Connection Planning Report                                            Risk Assessment: TSTS


TEMPLESTOWE TERMINAL STATION 66 kV
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                United Energy Distribution (46.9%), CitiPower (22.2%), SPI Electricity (24.0%), Jemena (6.9%)
Station operational rating (N elements in service):              549 MVA via 3 transformers (Summer peaking)
Summer N-1 Station Rating:                                       366 MVA [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                       417 MVA


Station: TSTS 66 kV                                           2011        2012        2013       2014        2015        2016        2017        2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                  361.3       366.2       376.2       383.4      389.0       397.6       406.4       413.7        422.9        432.2
Summer % Overload [See Note 2 below]                            Nil         0%         3%          5%          6%          9%        11%          13%         16%          18%
  th
50 percentile Winter Maximum Demand (MVA)                    281.1       283.3       284.6       286.5      289.1       293.3       296.9       300.3        303.9        307.4
Winter % Overload [See Note 2 below]                            Nil         Nil         Nil         Nil        Nil         Nil         Nil          Nil         Nil          Nil
Annual energy at risk (MWh) [See Note 3 below]                    0           1         47         111        175         300         456         615          874        1,198
Annual hours at risk [See Note 4 below]                           0           1          8          11          14         20          22           28          38           45
Expected annual unserved energy (MWh) [See Note 5
                                                                0.0         0.0        0.3         0.7         1.1         1.9        2.9          4.0          5.6         7.7
below]
Expected Annual Unserved Energy value [See Note 6
                                                                 $k         $k        $16k       $38k        $60k       $102k      $156k        $210k       $298k        $409k
below]

Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
    with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                                                                                        Page 5 of 5
2010 Transmission Connection Planning Report                           Risk Assessment: TTS


THOMASTOWN TERMINAL STATION 66 kV (TTS 66 kV)

Thomastown Terminal Station (TTS) is located in the north of greater Melbourne. It operates
at 220/66 kV and supplies Jemena Electricity Networks and SPI Electricity customers in the
Thomastown, Coburg, Preston, Watsonia, North Heidelberg, Lalor, Coolaroo and
Broadmeadows areas.

Background

TTS has five 150 MVA transformers and is a summer critical station. Under system normal
conditions, the No.1 & No.2 transformers are operated in parallel as one group (TTS(B12))
and supply the No.1 & No.2 66 kV buses. The No.3, No.4 & No.5 transformers are operated
in parallel as a separate group (TTS(B34)) and supply the No.3 & No.4 66 kV buses. The
66 kV bus 2-3 and bus 1-4 tie circuit breakers are operated open to limit the maximum
prospective fault levels on the four 66 kV busses to within switchgear ratings. For an
unplanned transformer outage in the TTS(B12) group, the No.5 transformer will automatically
change over to the TTS(B12) group. Therefore, an unplanned transformer outage of any one
of the five transformers at TTS will result in both the TTS(B12) & TTS(B34) groups being
comprised of two transformers each. Given this configuration, load demand on the TTS(B12)
group must therefore be kept within the capabilities of the two transformers at all times or
load shedding will occur.

The risk of supply interruption at Thomastown Terminal Station (TTS) has previously been
assessed as being unacceptable for summer 2008/09, and the establishment of new
220/66 kV connection assets at the existing South Morang Terminal Station (SMTS) site was
identified (in the 2004, 2005 and 2006 Transmission Connection Planning Reports) as the
most economic network solution. Prior to committing to the preferred network solution,
Jemena Electricity Networks and SPI Electricity completed a public “Expression of Interest”
process for non-network alternatives, via the publication of the Transmission Connection
Planning Report in 2004. At the conclusion of the expression of interest process on
31 March 2005, no firm proposals for alternatives to the network augmentation had been
received. In the absence of any commitment by interested parties to offer non-network
solutions, Jemena Electricity Networks and SPI Electricity proceeded to implement the
proposed network solution.

The new 220/66 kV connection assets at SMTS were commissioned in early 2009 and the
re-arrangement of 66 kV lines (including the Somerton Power Station connection to SMTS)
and load transfers to SMTS were fully commissioned in October 2009.




                                                                                    Page 1 of 8
2010 Transmission Connection Planning Report                                                                                    Risk Assessment: TTS


Transformer group TTS (B12) Summer Peak Forecasts

The graph below depicts the summer maximum demand forecasts (for 50th and 10th
percentile temperatures) for TTS (B12) and the corresponding rating with both transformers
(B1 & B2) operating. It shows that with all transformers in service, there is adequate capacity
to meet the anticipated maximum load demand until 2018, even under a transformer outage
condition. From 2018 onwards, there is insufficient capacity to meet the anticipated
maximum load demand for the remainder of the forecast period. It is intended to balance the
load between the two bus groups so that the load in each bus group is kept below each
group’s respective N rating.



                                                            TTS(B12) Summer Peak Forecasts

        500


                                                                                   (N) Rating @ 35 deg C with B5 normally connected
                                                                                        to TTS(B12) group from 2015 onwards???

        450


                 (N) Rating @ 35 deg C with Somerton
                Power Station 70 MW network support
        400


                                                 Somerton Power Station transferred to SMTS in                      10% Weather Probability Forecast
                                                                October 2009
  MVA




        350

                                                          Rating of 2 transformers @ 35 deg C



        300


                                                                                                                      50% Weather Probability Forecast


        250
                                       Actuals                      Forecasts




        200
              2006     2007     2008     2009      2010      2011       2012     2013     2014      2015     2016        2017      2018     2019       2020
                                                                                 Year




Transformer group TTS (B34) Summer Peak Forecasts

The graph below depicts the TTS (B34) rating with all transformers (B3, B4 & B5) in service
(“N” rating), and with one of the three transformers out of service (“N-1” rating), along with
the 50th and 10th percentile summer maximum demand forecasts.




                                                                                                                                                   Page 2 of 8
2010 Transmission Connection Planning Report                                                                                         Risk Assessment: TTS



                                                                 TTS(B34) Summer Peak Forecasts

        550



                     (N) Rating @ 35 deg C
        500
                                                                   (N) and (N-1) Ratings @ 35 deg C from 2015
                                                                     onwards, with B5 normally connected to
                                                                               TTS(B12) group???
        450



                                                                                           10% Weather Probability Forecast
        400
  MVA




        350

                     (N-1) Rating @ 35 deg C


        300                                                                                                      50% Weather Probability Forecast




        250                                     Actuals                 Forecasts




        200
              2006        2007     2008        2009       2010   2011     2012      2013       2014     2015      2016        2017     2018   2019     2020
                                                                                    Year




The above graph shows that with all transformers in service, there is adequate capacity to
meet the anticipated maximum load demand for the entire forecast period. However, if there
is a forced transformer outage during peak load periods from 2014 onwards, some
customers might be affected.

Magnitude, probability and impact of loss of load at TTS

The magnitude, probability and load at risk for the two transformer groups are considered
together below.

System Normal Condition (All 5 transformers in service)

There is no energy at risk under system normal condition at TTS.

N-1 System Condition

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating for the TTS(B34) group. The line graph
shows the value to consumers of the expected unserved energy in each year, for the 50th
percentile demand forecast.




                                                                                                                                                     Page 3 of 8
2010 Transmission Connection Planning Report                                                                                                                Risk Assessment: TTS


                                                         Annual Energy and Hours at Risk and Expected Customer Value at TTS(B34)
                                                                                  under (N-1) condition
                                                         Hours at Risk (LH scale)          Energy at Risk MWhrs (LH scale)    Customer Value (RH scale)
                                   70                                                                                                                                      $45,000



                                                                                                                                                                           $40,000
                                   60


                                                                                                                                                                           $35,000

                                   50
                                                                                                                                                                           $30,000
    MWhr at Risk / Hours at Risk




                                   40
                                                                                                                                                                           $25,000



                                                                                                                                                                           $20,000
                                   30


                                                                                                                                                                           $15,000
                                   20

                                                                                                                                                                           $10,000


                                   10
                                                                                                                                                                           $5,000



                                   0                                                                                                                                       $0
                                         2011     2012           2013               2014         2015            2016        2017         2018            2019     2020
                                                                                                         Year




Comments on Energy at Risk at TTS

From 2011 onwards, there will be sufficient capacity at the station to supply all customer
demand for the entire forecast period under system normal condition for the 50th percentile
demand forecast. However from 2018 onwards, for a major outage of one transformer at
TTS 66 kV over the summer peak load period, there would be insufficient capacity at the
station to supply all customer demand.

For summer 2019/20, the energy at risk for a transformer outage (N-1 condition) on the
TTS(B34) group is estimated to be 60 MWh for the 50th percentile demand forecast. In the
event of a major transformer outage over the summer 2019/20 period, there would be
insufficient capacity to meet demand for about 6 hours in that year. The estimated value to
consumers of the 60 MWh of energy at risk is approximately $3.6 million (based on a value
to customer reliability of $60,000/MWh) 1 . In other words, at the 50th percentile summer
demand level, and in the absence of any other operational response that might be taken to
mitigate the impact of a forced outage, a major outage of one transformer at TTS over the
summer of 2019/20 would be anticipated to lead to involuntary supply interruptions that
would cost consumers $3.6 million.

It is emphasised however, that the probability of a major outage of one of the five
transformers is very low, at about 1.0% per transformer per annum, whilst the expected
unavailability per transformer per annum is 0.217%. When the energy at risk (60 MWh) is
weighted by this low transformer unavailability, the expected unserved energy is estimated to
be around 0.7 MWh. This expected unserved energy is estimated to have a value to
consumers of around $39,000.

1
                                        The value of unserved energy is derived from the sector values given in Table 1 in Section 2.3, weighted
                                        in accordance with the composition of the load at this terminal station.


                                                                                                                                                                          Page 4 of 8
2010 Transmission Connection Planning Report                                     Risk Assessment: TTS


It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate (50th percentile) summer temperatures
occurring in each year. Under more extreme summer temperature conditions (that is, at the
10th percentile level), the customer demand increases significantly due to air conditioning
loads. At the 10th percentile demand forecast, the energy at risk in the summer of 2019/20 is
estimated to be 1,078 MWh. The estimated value to consumers of this energy at risk in the
summer of 2019/20 is approximately $64.7 million. The corresponding value of the expected
unserved energy is approximately $700,000.

These key statistics for the summer of 2019/20 under N-1 outage conditions are summarised
in the table below.

                                                                 MWh               Valued at
                                                                                   consumer
                                                                               interruption cost
Energy at risk, at 50th percentile demand forecast                 60             $3.6 million

Expected unserved energy at 50th percentile demand                0.7               $39,000
Energy at risk, at 10th percentile demand forecast               1,078            $64.7 million

Expected unserved energy at 10th percentile demand                11.7             $700,000



Possible Impact on Customers

System Normal Condition (All 5 transformers in service)

With the establishment of the new 220/66 kV connection assets at SMTS in early 2009 and
the re-arrangement of 66 kV lines (including the Somerton Power Station connection to
SMTS) and load transfers to SMTS fully commissioned in October 2009, there is no load at
risk under system normal condition for the entire forecast period for a 50th percentile demand
forecast.

N-1 System Condition

If one of the TTS 220/66 kV transformers is taken off line during peak loading times, causing
the TTS (B34) rating to be exceeded, the OSSCA 2 load shedding scheme which is operated
by SPI PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within transformer
capabilities. Any load reductions that are in excess of the minimum amount required to limit
load to the rated capability of the station would be restored after the operation of the OSSCA
scheme, at zone substation feeder level in accordance with Jemena EN’s and
SPI Electricity’s operational procedures.

With the establishment of the new 220/66 kV connection assets at SMTS in early 2009 and
the re-arrangement of 66 kV lines (including the Somerton Power Station connection to
SMTS) and load transfers to SMTS fully commissioned in October 2009, there is no load at
risk under an outage of one transformer at TTS until around 2018 for the 50th percentile
demand forecast.
2
         Overload Shedding Scheme of Connection Asset. OSSCA is designed to protect against transformer
         damage caused by overloads. Damaged transformers can take months to replace which can result in
         prolonged, long term risks to reliability of customer supply.
3
         Network Operations Centre.


                                                                                              Page 5 of 8
2010 Transmission Connection Planning Report                                Risk Assessment: TTS


Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or alleviate the emerging constraint towards the end of the ten year
planning horizon:

1. Balance the load between the two bus groups at TTS so that the load in each bus group
   is kept below its respective N rating and implement a contingency plan to transfer load to
   adjacent terminal stations. Jemena Electricity Networks and SPI Electricity have
   established and implemented the necessary plans that enable load transfers under
   contingency conditions.

2. Establish a new 500/220/66 kV terminal station. Two terminal station sites, one in
   Donnybrook and another in Somerton, have been reserved for possible future electrical
   infrastructure development to meet customers’ needs in the area.

3. Embedded generation. An alternative option to the network solution could be the
   establishment of an embedded generator, suitably located in the area that is presently
   supplied by TTS.

4. Demand Management. Another alternative option could be the introduction of demand
   management to reduce the magnitude of the summer peak demands under network
   emergencies. This might involve the introduction of interruptible load, negotiated with
   customers at reduced prices, with an agreement that the load can be interrupted during
   times of network constraint.

Preferred network option(s) for alleviation of constraints

1. By around summer 2017/18, the exposure to energy at risk will be managed through the
   following measures within the TTS(B12) and TTS(B34) groups:

         •   balance the load between the two bus groups at TTS so that the load on each bus
             group is kept below its respective N rating;

         •   maintain contingency plans to transfer load quickly to adjacent terminal stations;

         •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the
             impact on customers of any automatic load shedding that may take place; and

         •   Subject to the availability of the SPI PowerNet spare 220/66 kV transformer for
             urban areas (refer to section 4.5), this spare transformer can be used to
             temporarily replace the failed transformer.

2. In the absence of any commitment by interested parties to offer network support services
   by installing local generation or through demand side management initiatives that would
   reduce load at TTS, it is proposed to install a new 500/220/66 kV terminal station at either
   Donnybrook or Somerton.           However, based on the present forecasts a new
   500/220/66 kV terminal station is not likely to be required within the ten year planning
   horizon. The capital cost of establishing a new 500/220/66 kV terminal station and
   associated 66 kV lines re-arrangement is estimated to be around $60 million.

The tables on the following pages provide more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.


                                                                                         Page 6 of 8
2010 Transmission Connection Planning Report                                                                                                             Risk Assessment: TTS




 THOMASTOWN TERMINAL STATION UNDER N-1 OUTAGE CONDITIONS (B12 TRANSFORMER GROUP)
 Detailed data: Magnitude and probability of loss of load

 Distribution Businesses supplied by this station:                        Jemena EN (43%), SPI Electricity (57%)
 Normal cyclic rating with all plant in service                           288 MW, 325 MVA (Summer peaking)
 Summer N-1 Station Rating:                                               288 MW, 325 MVA [See Note 1 below for interpretation of N-1]
 Winter N-1 Station Rating:                                               356 MVA

 Station: TTS12 66kV                                         2011        2012         2013        2014        2015        2016        2017        2018        2019        2020
 50th percentile Summer Maximum Demand (MVA)                  267         273          279         286         291         296         303         308         314        320
 Summer % Overload [See Note 2 below]                         0%          0%           0%          0%          0%          0%          0%          0%          0%          0%
 50th percentile Winter Maximum Demand (MVA)                  194         197          201        205          208         210        213         215         218         N/A
 Winter % Overload [See Note 2 below]                         0%          0%           0%          0%          0%          0%          0%          0%          0%          N/A
 Annual energy at risk (MWh) [See Note 3 below]                0           0            0           0           0           0           0           0           0           0
 Annual hours at risk [See Note 4 below]                       0           0            0           0           0           0           0           0           0           0
 Expected Annual Unserved Energy (MWh) [See
                                                                0           0           0           0           0           0           0           0           0              0
 Note 5 below]
 Expected Annual Unserved Energy value [See
                                                              $-k         $-k         $-k         $-k         $-k         $-k         $-k         $-k         $-k             $-k
 Note 6 below]
Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3. "Annual energy at risk" is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
    outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
    station.




                                                                                                                                                                    Page 7 of 8
2010 Transmission Connection Planning Report                                                                                                             Risk Assessment: TTS




 THOMASTOWN TERMINAL STATION UNDER N-1 OUTAGE CONDITIONS (B34 TRANSFORMER GROUP)
 Detailed data: Magnitude and probability of loss of load

 Distribution Businesses supplied by this station:                     Jemena EN (100%), SPI Electricity (0%)
 Normal cyclic rating with all plant in service:                       500 MVA (Summer peaking)
 Summer N-1 Station Rating:                                            314 MW, 340 MVA [See Note 1 below for interpretation of N-1]
 Winter N-1 Station Rating:                                            397 MVA

Station: TTS34 66kV                                           2011        2012        2013         2014         2015         2016         2017         2018         2019         2020
50th percentile Summer Maximum Demand (MVA)                    285         294         306          316          323          330          339          348          355         364
Summer % Overload [See Note 2 below]                           0%          0%          0%           0%           0%           0%           0%           2%           4%           7%
50th percentile Winter Maximum Demand (MVA)                    238         244         254          262          267          272         279          285          290          N/A
Winter % Overload [See Note 2 below]                           0%          0%          0%           0%           0%           0%           0%           0%           0%          N/A
Annual energy at risk (MWh) [See Note 3 below]                  0           0           0            0            0            0            0            8           23           60
Annual hours at risk [See Note 4 below]                         0           0           0            0            0            0            0            2            3            6
Expected Annual Unserved Energy (MWh) [See
                                                               0.0         0.0          0.0         0.0          0.0          0.0          0.0          0.1          0.3          0.7
Note 5 below]
Expected Annual Unserved Energy value [See
                                                              $- k         $- k        $- k         $- k         $- k         $- k        $- k         $5 k         $15 k        $39 k
Note 6 below]
Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
                                           th
2. This is the percentage by which the 50 percentile forecast maximum demand exceeds the N-1 capability rating.
3. "Annual energy at risk" is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an
    outage with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6. The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
    station.




                                                                                                                                                                   Page 8 of 8
2010 Transmission Connection Planning Report                                                             Risk Assessment: WETS



WEMEN TERMINAL STATION (WETS)

Wemen Terminal Station (WETS) is currently under construction, and is expected to be
commissioned early in 2011. WETS will initially consist of one 70 MVA 235/66 kV
transformer supplying part of the 66 kV network previously supplied by RCTS. This
configuration will be the main source of supply for approximately 3,900 customers in the
Wemen and Ouyen areas. The station supply area will include Wemen and Boundary Bend
along the Murray River and the Ouyen region.

Magnitude, probability and impact of loss of load

WETS demand will be summer peaking.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N-1”
rating at 35°C ambient temperature. As WETS will initially have one transformer the “N-1”
rating is zero.

The initial WETS load will include a transfer of load from Red Cliffs Terminal Station (RCTS).

                                                      WETS Summer Peak Forecast

        90.0


        80.0
                                                                                                                  (N) rating @ 35 deg C
                                           Actuals                 Forecasts
        70.0
                                                                      10% Weather Probability Forecast

        60.0
                                                                                                          50% Weather Probability Forecast

        50.0
  MVA




        40.0


        30.0


        20.0


        10.0


                                                                                                                  (N-1) Rating @ 35 deg C
         0.0
               2005   2006   2007   2008   2009      2010   2011      2012     2013    2014     2015     2016   2017     2018     2019       2020
                                                                          Year




The bar chart below depicts the energy at risk with the single transformer out of service,
after implementation of the contingency plan to transfer load away to RCTS, for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast
is expected to exceed the N-1 capability rating. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.




                                                                                                                                    Page 1 of 5
2010 Transmission Connection Planning Report                                                                                     Risk Assessment: WETS



                                                      Annual Energy and Hours at Risk at WETS (after load transfers away)

                                                           Hours at risk (LH Scale)   Energy at risk (MWh) (LH Scale)   Customer Value (RH Scale)

                                 4500                                                                                                                      $900,000


                                 4000                                                                                                                      $800,000


                                 3500                                                                                                                      $700,000
    MWhr at Risk/Hours at Risk




                                 3000                                                                                                                      $600,000


                                 2500                                                                                                                      $500,000


                                 2000                                                                                                                      $400,000


                                 1500                                                                                                                      $300,000


                                 1000                                                                                                                      $200,000


                                  500                                                                                                                      $100,000


                                    0                                                                                                                      $0
                                           2011     2012         2013          2014     2015          2016       2017     2018        2019          2020
                                                                                               Year

Comments on Energy at Risk

For a major outage of the single transformer at WETS a contingency plan will be
implemented to transfer load from WETS to RCTS. After taking this load transfer into
account, there will be insufficient capacity at the station to supply all remaining demand at
the 50th percentile temperature for about 588 hours in 2020. The energy at risk at the 50th
percentile temperature under N-1 conditions, after load transfers, is estimated to be 4,111
MWh in 2020. The estimated value to consumers of the 4,111 MWh of energy at risk is
approximately $377 million (based on a value of customer reliability of $91,680/MWh) 1 . In
other words, at the 50th percentile demand level, after transferring load away but in the
absence of any other operational response that might be taken to mitigate the impact of a
forced outage, a major outage of the transformer at WETS in 2020 would be anticipated to
lead to involuntary supply interruptions that would cost consumers $377 million.

It is emphasised however, that the probability of a major outage of the transformer occurring
over the year is very low at 1% per annum, whilst the expected annual unavailability of the
transformer is 0.217%. When the energy at risk (4,111 MWh for 2020) is weighted by this
low unavailability, the expected unsupplied energy is estimated to be 8.9 MWh. This
expected unserved energy is estimated to have a value to consumers of around $816,000
(based on a value of customer reliability of $91,680/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year 2 . Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2020 is estimated to be 5,553 MWh. The estimated value to
consumers of this energy at risk in 2020 is approximately $509 million. The corresponding
value of the expected unserved energy is $1,103,000.

1
                                        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3,
                                        weighted in accordance with the composition of the load at this terminal station.
2
                                        As noted in Section 4.1, the 50th percentile demand forecast is used in each year.



                                                                                                                                                           Page 2 of 5
2010 Transmission Connection Planning Report                                     Risk Assessment: WETS



These key statistics for the year 2020 under N-1 outage conditions after load transfers away
are summarised in the table below.

                                                                        MWh           Valued at consumer
                                                                                       interruption cost
Energy at risk, at 50th percentile demand forecast                      4,111              $377 million

Expected unserved energy at 50th percentile demand                         8.9               $816,000

Energy at risk, at 10th percentile demand forecast                      5,553              $509 million

Expected unserved energy at 10th percentile demand                       12.0               $1,103,000



Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

•        Installation of an additional 70 MVA 235/66 kV transformer at WETS.

•        Demand reduction: There is an opportunity for voluntary demand reduction to
         reduce loading at the station during times of network constraint.

•        Embedded generation, connected to the WETS 66 kV bus, may defer the need for
         capacity augmentation at WETS.

Preferred option(s) for alleviation of constraints

As already noted, a contingency plan to transfer load to RCTS using the 66 kV network
between WETS and RCTS will be implemented when WETS is initially commissioned as a
single transformer station.

In the absence of any commitment by interested parties to offer network support services by
installing local generation or through demand side management initiatives that would reduce
load at WETS, it is proposed to install an additional 70 MVA 235/66 kV transformer at
WETS. On the basis of the load at risk at this station after taking into account the available
load transfer capacity (4,111 MWh at risk in 2020, valued at $377 million), Powercor
proposes that the additional capacity should be installed by around 2020.

The capital cost of installing an additional transformer at WETS is estimated to be
$12 million. The cost of establishing, operating and maintaining an additional transformer
would be recovered from network users through network charges, over the life of the asset.
The estimated total annual cost of this network augmentation is $1.2 million. This cost
provides a broad upper bound indication of the maximum contribution from distributors which
may be available to embedded generators or customers to reduce forecast demand and
defer or avoid the transmission connection component of this augmentation. 3 Sections 1.4
and 1.5 of this report provide further background information to proponents of non-network


3
        A Rule change proposal is presently before the AEMC to enable distributors to make these payments
        and    recover     the    costs   from     customers   (see     http://www.aemc.gov.au/Electricity/Rule-
        changes/Open/DNSP-recovery-of-transmission-related-charges.html). The Rule change, if accepted,
        would replicate the previous regulatory arrangements in Victoria..



                                                                                                    Page 3 of 5
2010 Transmission Connection Planning Report                    Risk Assessment: WETS



solutions to emerging constraints. Powercor would welcome proposals from proponents of
non-network solutions

Subject to the availability of the SPI PowerNet spare 220/66 kV transformer for rural areas
(refer to Section 4.5), this spare transformer can be used to temporarily replace a failed
transformer to minimise the transformer outage period.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy. The energy at risk, hours at risk
and expected unserved energy are after implementation of the contingency plan to transfer
load to RCTS.




                                                                                 Page 4 of 5
2010 Transmission Connection Planning Report                                    Risk Assessment: WETS



Wemen Terminal Station
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:                 Powercor (100%)
                                                                  MW      MVA
Normal cyclic rating with all plant in service                            77  via 1 transformer
Summer N-1 Station Rating:                                        0       0   [See Note 1 below for interpretation of N-1]
Winter N-1 Station Rating:                                        0       0

Station: WETS                                             2011          2012       2013        2014        2015         2016        2017        2018         2019        2020

50th percentile Summer Maximum Demand (MVA)                 0.0          48.9       51.8        53.9        55.4        63.9         64.9        65.9        67.0         68.1
Summer % Overload [See Note 2 below]                        0.0         > 100      > 100      > 100        > 100       > 100       > 100        > 100       > 100       > 100
50th percentile Winter Maximum Demand (MVA)                25.0          26.7       27.9        28.7        29.3        32.8         33.3        33.8        34.3         34.9
Winter % Overload [See Note 2 below]                      > 100         > 100      > 100      > 100        > 100       > 100       > 100        > 100       > 100       > 100
Annual energy at risk (MWh) [See Note 3 below]              0.0         312.6      658.0     1079.3       1484.7      1967.9      2392.1       2889.0      3460.7      4111.3
Annual hours at risk [See Note 4 below]                     0.0          88.5      153.0      219.8        276.8       341.8       400.8        460.3       522.0       588.3
Expected Annual Unserved Energy (MWh) [See
                                                            0.0           0.7        1.4         2.3         3.2          4.3         5.2         6.3          7.5         8.9
Note 5 below]
Expected Annual Unserved Energy valued in
accordance with the value of customer reliability in
                                                             $0       $62,087   $130,709   $214,402    $294,922    $390,913     $475,171    $573,867    $687,428     $816,676
September 2009 as advised by AEMO. [See Note 6
below]

Notes:
1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.   This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating. As the N-1 capacity rating at WETS is 0 an overload exists at
     all times under normal conditions and the value of this parameter is not meaningful.
3.   “Annual energy at risk” at WETS is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating after load transfers
     away.
4.   “Annual hours per year at risk” at WETS is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating after load
     transfers away.
5.   “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
     with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal
     station.



                                                                                                                                                                      Page 5 of 5
2010 Transmission Connection Planning Report                                                        Risk Assessment: WMTS 22 kV



WEST MELBOURNE TERMINAL STATION 22 kV (WMTS 22 kV)

Magnitude, probability and impact of loss of load

WMTS 22 kV is a summer critical station consisting of two 165 MVA 220/22 kV transformers,
which supply CitiPower’s distribution network. The terminal station provides major 22 kV supply
to the West Melbourne area including Melbourne Docks, Docklands Areas, North Melbourne
(including a railway substation), Parkville and Carlton, and the northern and western inner
Central Business District and surrounding areas.

The graph below depicts the station’s operational N rating for all transformers in service and the
N-1 rating (at 35 and 40 degrees ambient temperature), and the latest 10th and 50th percentile
maximum demand forecasts for the next ten years. The N-1 ratings are restricted by over-
voltage limits on transformer tapping. The forecast demands include the effects of any future
load transfer works that have been committed.


                                          WMTS 22kV Summer Peak Forecasts
         190

                 N Rating @ 35 deg C
         170
                  N Rating @ 40 deg C
                                           10% Probability Demand Forecasts
         150
   MVA




                N-1 Rating @ 35 deg C
         130
                 N-1 Rating @ 40 deg C

         110                                                                  50% Probability Demand Forecasts



         90
                                            Actuals               Forecasts


         70
               2004         2006         2008         2010           2012           2014           2016          2018          2020
                                                                    Year


The graph shows that if no forced outages of transformers occurred at WMTS 22 kV over the
forecast period for 50th percentile demand then there would be no interruption of supply to
customers. For 10th percentile demand there would be insufficient capacity to supply the
forecast load by 2018.

The bar chart below depicts the energy at risk with one transformer out of service for the 50th
percentile demand forecast, and the hours per year that the 50th percentile demand forecast is
expected to exceed the N-1 capability rating. The line graph shows the value to consumers of
the expected unserved energy in each year, for the 50th percentile demand forecast.




                                                                                                                 Page 1 of 5
2010 Transmission Connection Planning Report                                                       Risk Assessment: WMTS 22 kV




                                                Annual Energy and Hour at Risk and
                                               Expected Customer Value at WMTS 22kV


             Hour at Risk                       MWh at Risk          Consumer expected $ value (RH scale)




                               5,000                                                                               $1,800,000
          MWH & Hour at Risk




                               4,000                                                                               $1,500,000
                                                                                                                   $1,200,000
                               3,000
                                                                                                                   $900,000
                               2,000
                                                                                                                   $600,000
                               1,000                                                                               $300,000
                                  0                                                                                $0
                                       2011   2012   2013     2014   2015   2016    2017   2018    2019     2020

                                                                        Year




Comments on Energy at Risk

For an outage of one transformer at WMTS 22 kV during the summer period, it is expected that
from 2014 onwards, there would be insufficient capacity at the station to supply all demand at
the 50th percentile temperature.

By 2015, the energy at risk at the 50th percentile temperature under N-1 conditions is estimated
to be 113 MWh. Under these conditions, there would be insufficient capacity to meet demand
for 33.3 hours in that year. The estimated value to consumers of this energy at risk in 2015 is
approximately $10.3 million (based on a value of customer reliability of $90,948 per MWh). 1 In
other words, at the 50th percentile demand level, and in the absence of any other operational
response that might be taken to mitigate the impact of a forced outage, a major outage of one
transformer at WMTS 22 kV over the summer of 2015 would be anticipated to lead to
involuntary supply interruptions that would cost consumers $10.3 million.

It is emphasised however, that the probability of a major outage of one of the two transformers
at WMTS 22 kV occurring over the year is very low, at about 1.0% per transformer per annum,
while the expected unavailability per transformer per annum is 0.217%. When the energy at risk
(113 MWh in 2015) is weighted by this low unavailability, the expected unserved energy is
estimated to be around 0.5 MWh. This expected unserved energy is estimated to have a value
to consumers of approximately $45,000.

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each year.
Under more extreme summer temperature conditions (that is, at the 10th percentile level), the

1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in
        accordance with the composition of the load at this terminal station.



                                                                                                               Page 2 of 5
2010 Transmission Connection Planning Report                                      Risk Assessment: WMTS 22 kV



energy at risk in 2015 is estimated to be 772.7 MWh. The estimated value to consumers of this
energy at risk in 2015 is approximately $70.3 million. The corresponding value of the expected
unserved energy is approximately $305,000 in 2015.

These key statistics for the year 2015 under N-1 outage conditions are summarised in the table
below.

                                                                       MWh         Valued at consumer
                                                                                    interruption cost
Energy at risk, at 50th percentile demand forecast                       113           $10.3 million

Expected unserved energy at 50th percentile demand                        0.5             $45,000

Energy at risk, at 10th percentile demand forecast                     772.7           $70.3 million

Expected unserved energy at 10th percentile demand                        3.4            $305,000



If one of the two transformers at WMTS 22 kV is taken off line during peak loading times and the
N-1 station rating is exceeded, the OSSCA 2 load shedding scheme which is operated by SPI
PowerNet’s NOC 3 will act swiftly to reduce the loads in blocks to within safe loading limits. Any
load reductions that are in excess of the minimum amount required to limit load to the rated
capability of the station would be restored after the operation of the OSSCA scheme, at zone
substation feeder level in accordance with CitiPower’s operational procedures.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

1. Upgrade a 22 kV critical zone substation in the Central Business District to 66 kV for
    permanent supply from the proposed Brunswick Terminal Station (BTS 66 kV) by around
    2014 4 . This will allow the transfer of a significant amount of load from WMTS 22 kV to the
    proposed BTS 66 kV.

2. Demand reduction in response to schemes aimed at encouraging voluntary demand
   reduction during times of network constraint may enable the deferral of the need for
   augmentation. The amount of demand reduction would be taken into consideration when
   determining the optimum timing for the capacity augmentation.

3. Embedded generation in the order of 70 MVA will help to defer the need for augmentation.
   However, this option is unlikely to be the most cost-effective in view of the need to retire and
   replace the aged and inefficient 22 kV distribution assets by around the end of this decade.




2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operations Centre.
4
        Subject to SPI PowerNet’s timely delivery of the required works at BTS.



                                                                                           Page 3 of 5
2010 Transmission Connection Planning Report                                Risk Assessment: WMTS 22 kV



Preferred network option(s) for alleviation of constraints

In May 2008, CitiPower undertook a Regulatory Test for the upgrade of Brunswick Terminal
Station (BTS) with 66 kV supply. The Regulatory Test was undertaken under the market
benefits limb of the National Electricity Rules (NER) to address the overall distribution loading
constraint in the Central Business District supply areas and to alleviate the heavily loaded West
Melbourne Terminal Station. CitiPower’s application of the Regulatory Test confirmed that
establishment of the new BTS 66 kV supply source (with two 225 MVA 220/66 kV transformers)
is the most cost-effective option for addressing the network constraints

In 2010, the City of Moreland rejected the planning permit submitted by SPI PowerNet. A new
planning proposal is being prepared for Council approval. A new Regulatory Test is to be
undertaken in 2011 due to the expected increased cost of establishing BTS. Subject to the
outcomes of the Regulatory Test and planning approval processes, the revised date for the
commissioning of BTS is 2014 5 . Any further delays resulting from the planning process and
increase in SPI PowerNet’s project delivery lead times will be beyond the control of CitiPower.

The new BTS 66 kV would gradually offload WMTS 66 kV and WMTS 22 kV, and provide a new
66 kV point of connection for the Central Business District supply. The new BTS 66 kV could
also offload the heavily loaded 66 kV terminal station at Richmond (RTS) by permanently
picking up supply of three zone substations which RTS currently supplies (Refer to the WMTS
66 kV risk assessment report and the RTS 66 kV risk assessment report).

On this basis, CitiPower plans to implement load transfers away from WMTS 22 kV once BTS is
upgraded to 66 kV to address the network constraints. Prior to the upgrade of BTS, CitiPower
proposes to implement the following temporary measures to cater for an unplanned outage of
one transformer at WMTS 22 kV under critical loading conditions:

    •   maintain contingency plans to transfer load to the adjacent 66 kV point of supply;

    •   reduce WMTS 22 kV target voltage during an emergency to alleviate over-voltage on
        transformer tapping, while maintaining supply to customers in accordance with
        Distribution Code requirements; and

    •   fine-tune the OSSCA scheme settings in conjunction with NOC to minimise the impact
        on customers of any load shedding that may take place.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




5
        Subject to SPI PowerNet’s timely delivery of the necessary works.



                                                                                     Page 4 of 5
2010 Transmission Connection Planning Report                                           Risk Assessment: WMTS 22 kV


     WEST MELBOURNE TERMINAL STATION 22 kV
     Detailed data: Magnitude and probability of loss of load
     Distribution Businesses supplied by this station:                  CitiPower (100%)
     Station operational rating (N elements in service):                172 MVA via 2 transformers (Summer peaking)
     Summer N-1 Station Rating:                                         107.0 MW (129.0 MVA) [See Note 1 below for interpretation of N-1]
     Winter N-1 Station Rating:                                         123.7 MW (144.0 MVA)


 Station: WMTS 22 kV
                                                             2011       2012       2013        2014         2015          2016         2017          2018          2019         2020
 50th percentile Summer Maximum Demand
                                                            114.6      120.6       126.6      132.7        140.3         146.6         153.0        159.5         166.1        172.8
 (MVA)
 Summer % Overload [See Note 2 below]                          Nil         Nil        Nil     2.9%          8.7%        13.6%         18.6%        23.7%         28.8%         34.0%
 50th percentile Winter Maximum Demand
                                                             96.2      101.3       106.1      110.9        115.8         120.8         125.8        130.9         136.1        141.3
 (MVA)
 Winter % Overload [See Note 2 below]                          Nil         Nil        Nil        Nil            Nil         Nil           Nil           Nil          Nil           Nil
 Annual Energy at Risk (MWh) [See Note 3
                                                                 0          0           0          6       113.0           369           829        1,569         2,710        4,413
 below]
 Annual Hours at Risk [See Note 4 below]                       0.0        0.0        0.0         5.8         33.3         69.8         121.5        191.3         298.0        448.8
 Expected Annual Unserved Energy (MWh)
                                                               0.0        0.0        0.0         0.0            0.5         1.6           3.6          6.8         11.8          19.2
 [See Note 5 below]
 Expected Annual Unserved Energy value [See
                                                              $0k         $0k        $0k        $2k         $45k        $145k         $327k         $619k      $1,070k       $1,742k
 Note 6 below]

Notes:
1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.   This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3.   “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
4.    “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5.   “Expected annual unserved energy” means “Annual energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage
     with a duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.4.
6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.




                                                                                                  Page 5 of 5
2010 Transmission Connection Planning Report                                                                       Risk Assessment: WMTS 66 kV



WEST MELBOURNE TERMINAL STATION 66 kV (WMTS 66 kV)

Magnitude, probability and impact of loss of load

WMTS 66 kV is a summer critical station consisting of four 150 MVA 220/66 kV transformers.
The terminal station is shared by CitiPower (87%) and Jemena Electricity Networks (13%). The
terminal station provides major supply to the western Central Business District, including
Docklands areas, as well as the inner suburbs of Northcote and Brunswick West in the north,
and Kensington, Flemington, Footscray and Yarraville in the west.

Following the commissioning of the fourth transformer in 2002, WMTS 66 kV is now operating
with one of the four transformers on “Normal Open Auto-close” duty (i.e. on hot stand-by with a
facility for automatic closing upon forced outage of any one of the three normal-running
transformers). This arrangement facilitates control of the 66 kV fault level to within the terminal
station fault rating. With this transformer operating arrangement, the N rating will be
approximately equal to the N-1 rating (i.e. equal to the capacity of three transformers), thus
imposing a restriction that the terminal station should not be loaded beyond the N-1 rating at
any time.

Following the extremely hot summer in 2009, SPI PowerNet expressed concern regarding the
operating temperature of the WMTS 220/66 kV transformers. In order to avoid operating the
WMTS transformers at temperatures that would result in accelerated aging, SPI PowerNet has
reduced the WMTS Terminal Station summer cyclic ratings by about 5.5% to 497 MVA at 35ºC
ambient and about 10% to 463 MVA at 43ºC ambient. This would result in dramatically
exacerbating the load at risk at WMTS 66 kV.
The graph below depicts the station’s N-1 rating (approximately equal to the N rating) at 35ºC
and 40ºC, and the latest 10th and 50th percentile maximum demand forecasts during the
summer periods over the next ten years. The forecast demands include the effects of any
future load transfer works that have been committed by DBs.



                                                      WMTS 66kV Summer Peak Forecasts
         750.0
                                                                          10% Probability Demand Forecasts
         700.0
                  WMTS 4th Transformer
                     Installed 2002
         650.0

         600.0                                                                                                                  50% Probability Demand
                                                                                                                                      Forecasts
         550.0                    N = N-1 Rating @ 35 deg C
   MVA




                                   N = N-1 Rating @ 40 DegC                                             SP Ausnet Revised N = N-1 Rating @ 35 deg C
         500.0

         450.0                                                                                   SP Ausnet Revised N = N-1 Rating @ 43 DegC

         400.0
                                                         Actuals           Forecasts
         350.0

         300.0
                 2004           2006             2008              2010         2012             2014              2016            2018               2020
                                                                                Year


The graph shows that there would be insufficient capacity at WMTS 66 kV to supply the forecast
10% percentile and 50% percentile demands by around 2011 and 2012 respectively. Action will
be required from 2011/12 to minimise the load at risk under N and N-1 conditions.




                                                                                                                             Page 1 of 7
2010 Transmission Connection Planning Report                                             Risk Assessment: WMTS 66 kV



The bar chart below depicts the energy at risk (under normal system operating conditions with
one transformer on “Normal Open Auto-close” duty) for the 50th percentile demand forecast, and
the hours per year that the 50th percentile demand forecast is expected to exceed the rated
capacity under both N and N-1 conditions. The line graph shows the value to consumers of the
expected unserved energy in each year, for the 50th percentile demand forecast.




                                               Annual Energy and Hour at Risk and
                                              Expected Customer Value at WMTS 66kV

                                      Hour at Risk     MWh at Risk    Consumer expected $ value (RH scale)



                             35,000                                                              $4,000,000,000

                             30,000                                                              $3,500,000,000
        MWH & Hour at Risk




                                                                                                 $3,000,000,000
                             25,000
                                                                                                 $2,500,000,000
                             20,000
                                                                                                 $2,000,000,000
                             15,000
                                                                                                 $1,500,000,000
                             10,000
                                                                                                 $1,000,000,000
                              5,000                                                              $500,000,000

                                 0                                                               $0
                                      2011 2012 2013   2014 2015 2016 2017   2018 2019 2020

                                                               Year



Comments on Energy at Risk

With the existing transformer operating arrangement at WMTS 66 kV, it is expected that by
around 2012, there would be insufficient capacity to supply all demand at the 50th percentile
temperature under both N and N-1 conditions. Under the present arrangements (with one of the
four transformers operating with on “Normal Open Auto-close” duty), the expected unserved
energy is equal to the energy at risk, whenever loading exceeds the capacity of three
transformers.

By 2013, the energy at risk and the expected unserved energy under N and N-1 conditions is
approximately 163.8 MWh at the 50th percentile demand forecast. Under these conditions,
there would be insufficient capacity to meet demand for about 15.5 hours in that year. The
estimated value to consumers of the energy at risk in 2013 is approximately $16.4 million (at a
value of customer reliability of $100,276 per MWh). 1 In other words, at the 50th percentile
demand level, and in the absence of any other operational response that might be taken to
mitigate the impact of a forced outage, the existing load forecast for 2013 implies a level of
involuntary supply interruption that would cost consumers approximately $16.4 million.



1
        The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in
        accordance with the composition of the load at this terminal station.



                                                                                                Page 2 of 7
2010 Transmission Connection Planning Report                            Risk Assessment: WMTS 66 kV



It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each year.
Under more extreme summer temperature conditions (that is, at the 10th percentile level), the
energy at risk in 2013 is estimated to be 5,795 MWh. The estimated value to consumers of this
energy at risk in 2013 is approximately $581 million.

These key statistics for the year 2013 under both N and N-1 conditions are summarised in the
table below.

                                                              MWh        Valued at consumer
                                                                          interruption cost

Energy at risk, at 50 percentile demand forecast             163.8            $16.4 million

Expected unserved energy at 50 percentile demand             163.8            $16.4 million

Energy at risk, at 10 percentile demand forecast             5,795            $581 million

Expected unserved energy at 10th percentile demand           5,795            $581 million



If the total station load exceeds the N and N-1 station ratings, the OSSCA 2 load shedding
scheme which is operated by SPI PowerNet’s NOC 3 will act swiftly to reduce the load in blocks
to within safe loading limits. Any load reductions that are in excess of the minimum amount
required to reduce load to the rated capability of the station would be restored after the
operation of the OSSCA scheme, at zone substation feeder level in accordance with CitiPower’s
and Jemena Electricity Network’s operational procedures.

Feasible options for alleviation of constraints

The following options are technically feasible and potentially economic to mitigate the risk of
supply interruption and/or to alleviate the emerging constraint:

    1. Permanent load transfer from WMTS 66 kV to the proposed BTS 66 kV (Brunswick
       Terminal Station) connection point. This is part of the integrated plan for the
       establishment of the new BTS 66 kV (refer to the Risk Assessment Report for BTS
       66 kV) and could be achieved by:

        1.1 Permanent subtransmission transfer of two Central Business District zone
            substations from WMTS 66 kV to the proposed BTS 66 kV.

        1.2 High voltage distribution transfer of excessive load from all critical zone substations
            in the Central Business District areas supplied from WMTS 66 kV to the upgraded
            zone substation supplied from the proposed BTS 66 kV.

        1.3 Forming “Normal Open” 66 kV subtransmission ties between WMTS 66 kV and
            BTS 66 kV in the longer term to facilitate the bulk subtransmission transfer of normal
            supply of two zone substations from WMTS 66 kV to the new BTS 66 kV. The new
2
        Overload Shedding Scheme of Connection Asset.
3
        Network Operation Centre.



                                                                              Page 3 of 7
2010 Transmission Connection Planning Report                            Risk Assessment: WMTS 66 kV



            subtransmission ties will provide back-to-back capacity support between the two
            terminal stations, WMTS 66 kV and BTS 66 kV.

    2. Contingency plans to transfer load to the adjacent terminal stations under transformer
       outage conditions. This option can only mitigate the risk of supply interruption at
       WMTS 66 kV, but cannot defer the need for the new 66 kV terminal station at BTS.
       (Note that BTS will supply the Central Business District upgraded zone substation to
       resolve the overall distribution loading constraint in the Central Business District supply
       areas. Refer to the Risk Assessment Reports for BTS 66 kV, RTS 66 kV and
       WMTS 22 kV). This option requires the following works to be carried out:

        •    Increase the N rating to the normal four-transformer capacity level (i.e. with all the
             four transformers operating on load) such that the station could be loaded up to
             beyond the N-1 rating under normal conditions; and

        •    Implement contingency plans to transfer load away from WMTS 66 kV to reduce
             total station load to within the normal station N-1 rating under transformer outage
             conditions.

        The N rating could be increased to the normal four-transformer capacity level and the
        requirement for “Normal Open Auto-close” duty on the hot stand-by transformer could be
        removed by:

        •   installing a 66 kV series reactor across the 66 kV bus tie with an “auto-switching”
            scheme to control the 66 kV station fault level; and

        •   re-arranging the 66 kV subtransmission network into two groups separated by the
            66 kV bus tie series reactor for station fault level control.

        Contingency plans could be put in place to transfer load to the adjacent terminal stations
        via the 66 kV subtransmission and 22 kV / 11 kV / 6.6 kV distribution networks under
        transformer outage conditions. With all four 220/66 kV transformers operating on load,
        WMTS 66 kV will be equipped with higher 24-hour and 2-hour short time emergency
        ratings to allow excessive load to be transferred away within a short time frame under
        transformer outage contingency conditions. WMTS and RTS (Richmond Terminal
        Station) are interconnected at subtransmission level on “Normal Open” condition via a
        66 kV switching station in the Melbourne Central Business District. The magnitude of
        load that can be transferred to RTS 66 kV is dependent on the available spare capacity
        of the 66 kV subtransmission interconnecting network at the time of emergency at
        WMTS 66 kV. No incremental cost would be required to achieve this load transfer
        capability.

    3. A contingency plan to utilise the capacity of the “Normal Open" 220/66 kV transformer
       could be put in place to temporarily avoid exposure to load shedding by OCCSA 4 under
       the 10th percentile summer ambient temperature conditions with no transformer outage.
       This can be done by radially supplying one zone substation (about 110 MVA of load) by
       a single transformer, while the other three transformers supply the remaining terminal
       station loads.


4
        Overload Shedding Scheme of Connection Asset



                                                                              Page 4 of 7
2010 Transmission Connection Planning Report                                Risk Assessment: WMTS 66 kV



    4. The transmission connection asset owner, SPI PowerNet, has indicated their intention to
       redevelop WMTS by replacing all aged assets at WMTS, including 220 kV switchgear,
       220/66 kV transformers and 66 kV switchgear, by their next regulatory period. Bringing
       forward the SPI PowerNet replacement program and replacing the ageing four 150 MVA
       transformer with three 225 MVA transformers will maintain the existing N-1 rating at
       WMTS and increase the N rating. This option can only mitigate the risk of supply
       interruption at WMTS 66 kV, but cannot defer the need for the new 66 kV terminal
       station at BTS.

    5. Demand reduction may be achievable through customer schemes that encourage
       voluntary demand reduction during times of network constraint. The amount of demand
       reduction depends on the customer uptake and would be taken into consideration when
       determining the optimum timing of the capacity augmentation.

    6. Embedded generation in the order of about 150 MVA, will help to defer the need for
       augmentation.

Subject to availability, installation of SP Ausnet’s spare 220/66 kV transformer for metropolitan
areas, to temporarily replace a failed transformer at WMTS 66 kV, will minimise any transformer
outage period.

Preferred network option(s) for alleviation of constraints

In May 2008, CitiPower undertook a Regulatory Test for the upgrade of Brunswick Terminal
Station (BTS) with 66 kV supply. The Regulatory Test was undertaken under the market
benefits limb of the National Electricity Rules (NER) to address the overall distribution loading
constraint in the Central Business District supply areas and to alleviate the heavily loaded West
Melbourne Terminal Station. CitiPower’s application of the Regulatory Test confirmed that
establishment of the new BTS 66 kV supply source (with two 225 MVA 220/66 kV transformers)
is the most cost-effective option for addressing the network constraints.

In 2010, the City of Moreland rejected the planning permit submitted by SPI PowerNet in
relation to the proposed development of BTS. A new planning proposal is being prepared for
Council approval. A new Regulatory Test is to be undertaken in 2011 due to the expected
increased cost of establishing BTS. Subject to the outcome of the Regulatory Test and planning
approval process, the revised date for the commissioning of BTS is 2014 5 . Any further delays
resulting from the planning process or an increase in SPI PowerNet’s project delivery lead times
will be beyond the control of CitiPower.

The new BTS 66 kV station would gradually offload WMTS 66 kV and WMTS 22 kV, and
provide a new 66 kV point of connection for the Central Business District supply, thereby
reducing the reliance on WMTS 66 kV. The new BTS 66 kV station could also offload the
heavily loaded 66 kV terminal station at Richmond (RTS) by permanently picking up supply of
three zone substations which RTS currently supplies (Refer to the RTS 66 kV risk assessment
report).

On this basis, CitiPower plans to implement gradual load transfers away from WMTS 66 kV
immediately after BTS is upgraded to 66 kV to address the network constraints at WMTS 66 kV.
Prior to the upgrade of BTS, CitiPower and Jemena Electricity Networks propose to utilise the
“Normal Open” transformer capacity and/or implement demand management programs to

5
        Subject to SPI PowerNet’s timely delivery of the necessary works.



                                                                                  Page 5 of 7
2010 Transmission Connection Planning Report                        Risk Assessment: WMTS 66 kV



reduce load demand below plant ratings under system normal conditions. In addition, CitiPower
and Jemena Electricity Networks will work closely with SPI PowerNet to examine the economics
of bringing forward SPI PowerNet’s replacement program, to:

•       replace the ageing four 150 MVA transformers with three 225 MVA units at WMTS or
        alternatively, to

•       install a 66 kV series reactor across the 66 kV bus tie and re-arrange the
        subtransmission loops into two separate groups (that was highlighted in Option 2 and 4
        of the previous section) where the N rating will be increased.

It should be noted that the proposed replacement works by SPI PowerNet will only mitigate the
risk of supply interruption at WMTS 66 kV in the short term, and cannot defer the need for the
new 66 kV terminal station at BTS.

The table on the following page provides more detailed data on the station rating, demand
forecasts, energy at risk and expected unserved energy.




                                                                          Page 6 of 7
2010 Transmission Connection Planning Report                                           Risk Assessment: WMTS 66 kV


     WEST MELBOURNE TERMINAL STATION 66 kV
     Detailed data: Magnitude and probability of loss of load
     Distribution Businesses supplied by this station:              CitiPower (87%), Jemena Electricity Networks (13%)
     Station operational rating (N elements in                      497 MVA via 4 transformers with one transformer on "Normal Open Auto-close" duty [Note 7]
     service):                                                      (Summer peaking)
     Summer N-1 Station Rating:                                     442.3 MW (497.0 MVA) [See Note 1 below for interpretation of N-1]
     Winter N-1 Station Rating:                                     512.9 MW (570.0 MVA)


Station: WMTS 66kV
                                                            2011        2012       2013        2014       2015        2016        2017          2018         2019          2020
50th percentile Summer Maximum Demand (MVA)                 478.0       499.6      527.2      550.1      573.2       596.9       621.6          646.5       671.9          698.0
Summer % Overload [See Note 2 below]                         Nil        0.5%       6.1%       10.7%      15.3%       20.1%       25.1%         30.1%        35.2%         40.4%
50th percentile Winter Maximum Demand (MVA)                 367.8       385.1      407.3      427.0      445.7       464.8       484.8          505.1       526.2          548.2
Winter % Overload [See Note 2 below]                         Nil         Nil        Nil         Nil        Nil         Nil         Nil           Nil          Nil           Nil
Annual Energy at Risk (MWh) [See Note 3 below]               0.0         0.6       163.8      785.2      2,186       4,792       9,062         15,033       23,067        33,894
Annual Hours at Risk [See Note 4 below]                      0.0         0.8       15.5        49.5       98.0       263.3       263.3          366.5       496.8          668.5
Expected Annual Unserved Energy (MWh) [See Note
5 below]
                                                             0.0         0.6       163.8      785.2       2,186      4,792        9,062        15,033       23,067        33,894


Expected Annual Unserved Energy value [See Note 6
below]
                                                           $0.0M       $0.1M      $16.4M     $78.7M      $219M      $481M        $909M        $1,507M      $2,313M       $3,399M


Notes:
1.   “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2.   This is the percentage by which the 50th percentile forecast maximum demand exceeds the N-1 capability rating.
3.   “Annual energy at risk” is the amount of energy in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
                                                                                          th
4.    “Annual hours per year at risk” is the number of hours in a year during which the 50 percentile demand forecast exceeds the N-1 capability rating.
5.   Because of the “Normal Open Auto-close” duty on one transformer at FBTS, “Expected annual unserved energy” is equal to the “annual energy at risk”.
6.   The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3, weighted in accordance with the composition of the load at this terminal station.
7.   The N and N-1 ratings are approximately equal due to the restriction of “Normal Open Auto-close” transformer duty. The N rating will be increased to about 700MVA when the
     restriction is removed.




                                                                                              Page 7 of 7
2010 Transmission Connection Planning Report                                                                          Risk Assessment: WOTS


WODONGA TERMINAL STATION (WOTS 66 kV and 22 kV)

Wodonga Terminal Station is the main source of supply for a significant part of north
eastern Victoria. The supply is via two 330/66/22 kV three-winding transformers with a
nominal rating of 75 MVA each. This terminal station supplies Wodonga centrally as well
as the area from Rutherglen in the west to Corryong in the east. The Hume Power
Station is connected to the WOTS 66 kV bus and can supply up to 50 MVA into WOTS
66 kV bus, offsetting the load on the transformers. SPI Electricity (SPIE) is responsible
for the transmission connection and distribution network planning for this large region.

Magnitude, probability and impact of loss of load

The risk of supply interruption at Wodonga Terminal Station (WOTS), for a single
contingency event has been assessed in previous Transmission Connection Planning
Reports as being unacceptable for summer 2012/13. Accordingly, proposals were invited
by 30 June 2009 from proponents of non-network solutions as alternatives to network
augmentations. Currently SPIE is negotiating with a proponent who is expected to be
able to provide non-network support allowing SPIE to defer the network augmentation.

WOTS is a summer peaking station and growth in summer peak demand at WOTS 66 kV
and 22 kV together has averaged around 2 MW (2%) per annum in recent years. The
growth is forecast to continue at this level for the next few years. To accurately assess
the transformer loading, the 66 kV and 22 kV loads need to be considered together
because of the physical arrangement of the transformer windings. The recorded peak
demand in summer 2010 was 95.5 MW (98.6 MVA), which was approximately 5 MW
lower than the 2009 peak of 101 MW (107 MVA) due to the comparatively mild summer
in 2010.

The graph below depicts the 10th and 50th percentile summer maximum demand forecast
together with the station’s operational “N” rating (all transformers in service) and the “N-1”
rating at an ambient temperature of 35°C. The combined 66 kV and 22 kV load at WOTS
are not expected to reach the “N” summer station rating prior to 2020, but are already
exceeding the “N-1” rating at the 50th percentile summer demand level.

                                       WOTS 66 kV and 22 kV combined Summer Peak Forecasts


        180.0




        160.0
                       (N) Rating @ 35 deg C



        140.0


                                                                            10% Weather Probability Forecast
  MVA




        120.0


                                                                                                           50% Weather Probability Forecast
        100.0




         80.0
                  (N-1) Rating @ 35 deg C                     Actuals        Forecasts



         60.0
                2003    2004    2005   2006    2007   2008   2009   2010   2011   2012   2013   2014   2015    2016   2017   2018   2019      2020
                                                                              Year




                                                                                                                                           Page 1 of 6
2010 Transmission Connection Planning Report                                                                                         Risk Assessment: WOTS


The combined 66 kV and 22 kV winter maximum demand at WOTS is less than the
summer maximum demand, while the winter rating is higher than the summer rating.
With the current winter load forecasts, peak winter demand at WOTS 66 kV and 22 kV is
not expected to reach the “N -1” winter station rating within the planning horizon out to
2020.

The bar chart below depicts the energy at risk with one transformer out of service for the
50th percentile demand forecast, and the hours per year that the 50th percentile demand
forecast is expected to exceed the “N-1” capability. The line graph shows the value to
consumers of the expected unserved energy in each year, for the 50th percentile demand
forecast.




                                                             Annual Energy and Hours at Risk at WOTS (Single Contingency Only)

                                            Hours at Risk (LH scale)        Energy at Risk MWhrs (LH scale)          Customer Value (RH scale)
                                   12000                                                                                                                $3,500,000


                                                                                                                                                        $3,150,000
                                   10500

                                                                                                                                                        $2,800,000
                                    9000
                                                                                                                                                        $2,450,000
    MWhr at Risk / Hours at Risk




                                    7500
                                                                                                                                                        $2,100,000


                                    6000                                                                                                                $1,750,000


                                                                                                                                                        $1,400,000
                                    4500

                                                                                                                                                        $1,050,000
                                    3000
                                                                                                                                                        $700,000

                                    1500
                                                                                                                                                        $350,000


                                      0                                                                                                                 $0
                                           2011       2012         2013     2014       2015          2016     2017       2018        2019        2020
                                                                                              Year




Comments on Energy at Risk - Assuming embedded generation is not
available

As already noted, WOTS is a summer peaking station and all of the energy at risk occurs
in the summer period. Therefore, the comments below focus on the energy at risk over
the summer period.

For a major outage of any one of the two 330/66/22 kV transformers over the entire
summer period, there will be insufficient capacity at the station to supply all demand at
the 50th percentile temperature for about 398.5 hours in summer 2013/14. The energy at
risk under N-1 conditions is estimated to be 3,490 MWh in summer 2013/14. The
estimated value to consumers of the 3,490 MWh of energy at risk is approximately
$231.7 million (based on a value of customer reliability of $66,407/MWh). 1 In other
words, at the 50th percentile demand level, and in the absence of any other operational
response that might be taken to mitigate the impact of a major outage of any one of the

1
                                       The value of unserved energy is derived from the sector values given in Table 1 of Section 2.3,
                                       weighted in accordance with the composition of the load at this terminal station.



                                                                                                                                                        Page 2 of 6
2010 Transmission Connection Planning Report                                       Risk Assessment: WOTS


two 330/66/22 kV transformers at WOTS over the summer of 2013/14, a major outage
would be anticipated to lead to involuntary supply interruptions that would cost consumers
$231.7 million.

It is emphasised however, that the probability of a major outage of one of the two
transformers occurring over the year is very low, at about 1.0% per transformer per
annum, whilst the expected unavailability per transformer per annum is 0.217%. When
the energy at risk (3,490 MWh for summer 2013/14) is weighted by this low unavailability,
the expected unsupplied energy is estimated to be around 15.1 MWh. This expected
unserved energy is estimated to have a value to consumers of around $1 million (based
on a value of customer reliability of $66,407/MWh).

It should also be noted that the above estimates of energy at risk and expected unserved
energy are based on an assumption of moderate summer temperatures occurring in each
year. Under more extreme summer temperature conditions (that is, at the 10th percentile
level), the energy at risk in 2013/14 is estimated to be 5,157 MWh. The estimated value
to consumers of this energy at risk in 2013/14 is approximately $342.5 million. The
corresponding value of the expected unserved energy is approximately $1.5 million.

These key statistics for the year 2014 under N-1 outage conditions are summarised in the
table below.

                                                                        MWh           Valued at consumer
                                                                                       interruption cost
Energy at risk, at 50th percentile demand forecast                      3,490               $232 million

Expected unserved energy at 50th percentile demand                       15.1                $1.0 million

Energy at risk, at 10th percentile demand forecast                      5,157              $342.5 million

Expected unserved energy at 10th percentile demand                       22.3                $1.5 million



If one of the 330/66/22 kV transformers at WOTS is taken off line during peak loading
times and the “N-1” station rating is exceeded, then the Overload Shedding Scheme for
Connection Assets (OSSCA) which is operated by SPI PowerNet’s TOC 2 to protect the
connection assets from overloading 3 , will act swiftly to reduce the loads in blocks to within
safe loading limits. If OSSCA operation does occur, any load reductions that are in
excess of the amount required to limit load to the rated capability of the station would be
restored at zone substation feeder level in accordance with SPI Electricity’s operational
procedures after the operation of the OSSCA scheme.

If OSSCA operates at WOTS, it would automatically shed about 60 MVA of load, affecting
approximately 13,000 customers.



2
    Transmission Operation Centre.
3
  OSSCA is designed to protect against transformer damage caused by overloads. Damaged transformers
can take months to replace which can result in prolonged, long term risks to reliability of customer supply.




                                                                                                  Page 3 of 6
2010 Transmission Connection Planning Report                        Risk Assessment: WOTS


Comments on Energy at Risk - Assuming embedded generation is available

The previous comments on energy at risk are based on the assumption that there is no
embedded generation available to offset the 330/66/22 kV transformer loading.

SPI Electricity is currently negotiating arrangements for network support with a proponent
who is expected to establish a new power station at Wodonga. An agreement for network
support will allow a network augmentation to be deferred for at least 4 to 5 years.

In addition to the new power station described above, the generation from Hume Power
Station (HPS) can also be fed into the WOTS 66kV bus and is capable of providing up to
50 MVA. This generation can also be connected to the TransGrid 132 kV Network in New
South Wales. The generation from HPS is dependent on water releases from Hume Dam
for irrigation and the water level in the dam, and can vary widely from year to year. There
is therefore presently no guarantee that generation from HPS will be available to offset
transformer loading at WOTS.

Feasible options for alleviation of constraints.

On the assumption that SPI Electricity’s present negotiations with the new power station
at Wodonga lead to the agreement of suitable network support arrangements, the
following options can be considered in the future when constraints again emerge:

1. Addition of Power Factor Correction Capacitors

The station is currently running with a power factor of around 0.97 at summer peak. At
this power factor the use of additional capacitors to reduce the MVA loading would bring
marginal benefits.

2. Install a 3rd 330/66/22 kV transformer at WOTS

Installation of a third transformer at WOTS is a relatively simple, technically feasible
option for augmenting the station. The site can accommodate an additional 330/66/22 kV
transformer.

3. Demand reduction

There may be potential to obtain some form of load relief by demand reduction.
Commercial and industrial loads account for approximately 60% of the peak load and
these areas could be targeted for special tariff incentives.

4. Embedded generation

As discussed above, there already exists embedded generation connected to WOTS and
this is expected to be expanded with an additional power station that will contract for
network support. Further embedded generation in the form of a network support
agreement with HPS, another generator in the order of 20-30 MVA connected to the
WOTS 66 kV bus or expansion of the new power station would help to defer the need for
augmentation.




                                                                                 Page 4 of 6
2010 Transmission Connection Planning Report                          Risk Assessment: WOTS


Preferred network option(s) for alleviation of constraints

As already noted, SPI Electricity is currently negotiating arrangements for network
support with a proponent who is expected to establish a new power station at Wodonga.
An agreement for network support will allow a network augmentation to be deferred for at
least 5 years. In the meantime, before network support arrangements are in place, it is
proposed to implement the following temporary measures to cater for an unplanned
outage of any one of the 330/66/22 kV transformers at WOTS under critical loading
conditions:

    •   rely on Hume Power Station generation to reduce loading on the remaining WOTS
        330/66/22 kV transformer;

    •   fine-tune the OSSCA scheme settings in conjunction with TOC to minimise the
        impact on customers of any load shedding that may take place to protect the
        connection assets from overloading; and

    •   Monitor the load growth to ensure the load at risk is within the forecasts.




                                                                                      Page 5 of 6
2010 Transmission Connection Planning Report                                    Risk Assessment: WOTS




The table below provides more detailed data on the station rating, demand forecasts, energy at risk and expected unserved energy assuming
network support is not available.

WODONGA TERMINAL STATION 66kV and 22kV Loading (WOTS)
Detailed data: Magnitude and probability of loss of load
Distribution Businesses supplied by this station:   SPI Electricity (100%)
Normal cyclic rating with all plant in service      162 MVA via 2 transformers (Summer peaking)
Summer N-1 Station Rating (MVA):                    81
Winter N-1 Station Rating (MVA):                    87

Station: WOTS 66kV & 22kV                                 2011       2012       2013        2014        2015        2016        2017         2018         2019         2020
50th percentile Summer Maximum Demand (MVA)              100.9      103.0      107.0        108.6       111.1       113.4       116.0       118.3        121.3         124.2
Summer % Overload [See Note 2 below]                    24.6%      27.2%      32.1%        34.1%       37.1%       40.0%       43.2%       46.0%        49.7%         53.3%
50th percentile Winter Maximum Demand (MVA)               79.8       79.1       78.9         79.0        79.7        79.7        80.0        80.5         81.0          81.0
Winter % Overload [See Note 2 below]                        Nil        Nil        Nil         Nil         Nil         Nil          Nil         Nil          Nil          Nil
Annual energy at risk (MWh) [See Note 3 below]          1488.8     1932.6     3005.9      3489.8      4386.7      5396.4      6654.1       7887.0       9737.6      11702.4
Annual hours at risk [See Note 4 below]              228.2    272.8    357.5      398.5      487.4      569.1      657.0      745.0      857.2      958.9
Expected Annual Unserved Energy (MWh) [See
                                                      6.45     8.37    13.03      15.12      19.01      23.38      28.83      34.18      42.20      50.71
Note 5 below]
Expected Annual Unserved Energy value [See Note 6
                                                  $428,415 $556,126 $864,975 $1,004,239 $1,262,332 $1,552,879 $1,914,799 $2,269,588 $2,802,098 $3,367,512
below]



Notes:
1. “N-1” means cyclic station output capability rating with outage of one transformer. The rating is at an ambient temperature of 35 degrees Centigrade.
2. This is the percentage by which the forecast maximum demand exceeds the N-1 capability rating.
3. “Annual energy at risk” is the amount of energy in a year during which the 50th percentile forecast exceeds the N-1 capability rating.
4. “Annual hours per year at risk” is the number of hours in a year during which the 50th percentile demand forecast exceeds the N-1 capability rating.
5. “Expected annual unserved energy” means “Energy at risk” multiplied by the probability of a major outage affecting one transformer. “Major outage” means an outage with
    duration of 2.6 months. The outage probability is derived from the base reliability data given in Section 4.3.
6. The value of unserved energy is derived from the sector values given in Table 1 of section 2.3, weighted in accordance with the composition of the load at this terminal
    station.




                                                                                                                                                                  Page 6 of 6

				
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