Understanding the impact on Transpower's systems … · Transmission Pricing Methodology –Impact Assessment Understanding the impact on Transpower's systems and processes December

Transmission Pricing Methodology – Impact Assessment

Understanding the impact on Transpower's systems and processes

December 2012

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Restrictions and disclaimers

This paper has been prepared solely for the purposes stated herein and should not be relied upon for any other purpose.

To the fullest extent permitted by law, PwC accepts no duty of care to any third party in connection with the provision of this paper and/or any related information or explanation (together, the “Information”). Accordingly, regardless of the form of action, whether in contract, tort (including without limitation, negligence) or otherwise, and to the extent permitted by applicable law, PwC accepts no liability of any kind to any third party and disclaims all responsibility for the consequences of any third party acting or refraining to act in reliance on the Information.

We have not independently verified the accuracy of information provided to us. Accordingly, we express no opinion on the reliability, accuracy, or completeness of the information provided to us and upon which we have relied.

The statements and opinions expressed herein have been made in good faith, and on the basis that all information relied upon is true and accurate in all material respects, and not misleading by reason of omission or otherwise.

The statements and opinions expressed in this paper are based on information available as at the date of the paper.

We reserve the right, but will be under no obligation, to review or amend our paper, if any additional information, which was in existence on the date of this paper was not brought to our attention, or subsequently comes to light.

This paper is issued pursuant to the terms and conditions set out in our engagement letter of 9 November 2012 and the Terms of Business attached thereto.

TPM Impact Assessment

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Jeremy CainChief Regulatory AdvisorTranspower96 The Terrace PO Box 1021Wellington

20 December 2012

Dear Jeremy

Review of the impact of the changes to the Transmission Pricing Methodology

In accordance with the terms of our contract dated 9 November 2012, we attach our final report summarising the results of our review of the impact of the Transmission Pricing Methodology changes proposed by the Electricity Authority.

If you require any clarification or further information, please do not hesitate to contact me.

Yours sincerely

Grant Dennis Partner

PricewaterhouseCoopers, 113-119 The Terrace, Wellington 6140, New ZealandT: +64 (4) 462 7000, F: +64 (4) 462 7001, www.pwc.com/nz

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Executive summary

Background

The Electricity Authority (the Authority) is currently undertaking a review of the Transmission Pricing Methodology (TPM) and has released a consultation paper for feedback from the industry (Transmission Pricing Methodology: issues and proposal – 10 October 2012) by 1 March 2013. The Authority has proposed a shift in pricing allocation based on the principle of „the party that benefits should pay‟.

The purpose of the report is to assess the impact of the proposed changes to Transpower‟s systems and processes. It is to be published by Transpower during the consultation period to help inform debate.

Terms of reference

We have been asked to:

• understand the current state of Transpower‟s processes and systems that support the current TPM

• assess the impacts of the Authority‟s proposed changes on Transpower‟s systems and processes

• provide an estimation of the timeframes and Transpower‟s costs associated with implementing and then operating the Authority‟s proposed changes (the base case)

• undertake a basic sensitivity analysis on two alternative scenarios to understand how adjusting key input assumptions affects implementation timeframes and costs:

• Scenario A – a moderate adjustment of the base case

• Scenario B – a more material adjustment of the base case.

• identify areas of ambiguity within the Authority‟s proposed changes in relation to the implementation by Transpower.

Excluded from the scope was:

• reviewing the suitability or economic benefit of the Authority‟s proposal

• considering the timeframe and costs associated with Transpower developing the Authority's guidelines into detailed pricing methodology.

Our approach

Our assessment of the impact of the Authority‟s proposed changes and basic sensitivity analysis on two alternative scenarios put forward by Transpower is based on:

• reviewing the Authority‟s consultation paper and other documentation provided by Transpower

• information provided by key stakeholders at Transpower, Energy Market Services (EMS) and the Authority. (See Appendix E for a full list of stakeholders).

We used this information to:

• map Transpower‟s current business processes and systems that support the TPM

• assess and rate the impacts of proposed changes to the TPM

• identify options for implementation of the proposed changes

• estimate the cost and timeframes of implementing and then operating the new TPM.

Due to the high level of design and impact assessments able to be performed at this stage of the submission process, the cost estimates noted in this report are indicative. Given this, they may vary by +/-50%. Further refinement will be possible once a more detailed TPM is developed and subsequent detailed design activities are undertaken.

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The TPM allocates revenue to customers through three charges

The TPM aims to ensure that the full costs of the transmission services are allocated to promote competition, reliable supply and efficient operation of the electricity industry.

The current TPM allocates Transpower‟s annual maximum allowable revenue each year to customers through three charges.

• A connection charge – to recover the cost of AC connection assets that connect Customers to the grid

• A high voltage direct current (HVDC) charge – to recover the cost of the link between the North and South Islands

• An interconnection charge – to recover the remaining costs of the grid not covered under connection or HVDC charges

How Transpower’s systems and processes support the current model

Annually, Transpower undertakes a pricing round (June – December) that determines the transmission customers‟ charges (see figure 1) for the subsequent pricing year (1 April – 31 March). Four teams execute and support the current TPM process in Transpower and there are a number of manual handoffs between these teams during the seven month process. There is extensive customer interaction needed to confirm asset information and customers‟ forecast demand. Delays are common.

Seven systems (see figure 2) support the TPM process with information required to be manually uploaded between the systems.

Figure 1: Current state process

Figure 2: Map of Transpower’s systems supporting the current TPM

Executive summaryCurrent state

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The Authority‟s proposal states that it aims to shift pricing allocation to a principle of „the party that benefits should pay‟. The detail of this change is set out in the table below.

There will be significant impacts on Transpower’s systems, processes and on Transpower’s customers

Based on the assessment of the current processes and systems, the changes proposed by the Authority will increase the frequency and level of complexity by:

• requiring what is currently an annual process to be completed monthly – this will require automation of systems, processes and customer data collection

• requiring updates to the seven systems that support the current TPM to reflect the proposed changes

• introducing the Market System into the TPM process – the Market System includes the SPD, RMT and SFT models

• introducing the use of new metering and private benefits data

• requiring redesign of processes which impacts all four teams involved in executing the process.

Significant sector engagement will be required to ensure effective delivery of the Authority‟s proposal. Transmission customers will be impacted by variable monthly charges and are likely to require additional summary reports and raw data to understand their charges. Therefore additional ongoing support from Transpower‟s internal customer facing team will be required.

Estimated time frames and cost

Significant effort will be required to implement the changes given the scale of the impact described above. We estimate a programme of work will take 18 months to reach a go-live date with indicative implementation costs of $13 million.

Indicative ongoing costs to support the Authority‟s proposed changes is $4 million over 5 years. 6

Executive summaryThe Authority’s proposal – The base case

Charge The Authority’s proposed change

Estimated level of impact (against

current TPM)*

Market approach• Loss and constraint excess(LCE)• FTR Auctions

Add the current approach to the Electricity Industry Participation Code 2010 (the Code) l

Market-like approach• Long term contracts

Change the rules relating to the classification and valuation of assets and introduce a customer disputes process

l

Exacerbators pay• kvar charge

Introduce a new charge for recovering the costs of static reactive support l

Beneficiaries pay• Value of private benefit (Scheduling, Pricing, Dispatch (SPD) model)

Use the SPD model to allocate residualcosts to the parties that benefit based upon their share of injection to, or power drawn from, the national grid within a trading period

l

Administrative approach:• RCPD/RCPI• Prudent Discount Policy (PDP)

•Introduce a Regional Coincident Peak Injection (RCPI) charge to recover residual charges along with the current Regional Coincident Peak Demand (RCPD) charge•Allow distributors to opt out of RCPD charge•Refine the Prudent Discount Policy

l

Figure 3: Impact assessment of the Authority’s proposed change

*The level of impact assessment criteria used can be found in the approach section on page 13.

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The first alternative, scenario A, proposes a number of changes including moving the pricing cycle from monthly to quarterly and use of simplified rules for the „beneficiary pay‟ charge (see table below).

A shift to quarterly pricing will reduce ongoing impact

The first alternative scenario to the base case, reduces the ongoing impact to teams involved in the TPM process, eases complexity of implementation by using assumptions to simplify the Market System and reducing the number of assets in scope. However, there is still a significant additional level of complexity required by:

• requiring updates to the seven systems that support the current TPM to reflect the proposed changes

• introducing the Market System into the TPM process

• introducing new metering and private benefits (SPD model) data

• requiring redesign of processes which impact all four teams involved in executing the process.

The impact to transmission customers will be reduced (when compared to the Authority‟s proposal) as charges will only be set quarterly. Customers will still require significant additional engagement with Transpower‟s customer facing teams to understand their charges.


Significant effort will be required to implement the changes given the scale of the impact described above. We estimate a programme of work will take 16 months to reach a go-live date with indicative implementation costs of $11.5 million.

Indicative ongoing costs to support scenario A is $4 million over 5 years.

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Executive summarySensitivity analysis – Alternative scenario A

Charge Alternative scenario A

Estimated level of impact

(against current TPM)*

Market approach• LCE and FTR Auctions No change lMarket-like approach• Long term contracts No change lExacerbators pay• kvar charge No change lBeneficiaries pay• Value of private benefit (SPD model)

Use assumptions to reduce complexityin the Market System, reduce assets included from an estimated 140 to 70

l


Allow all or no distributors to opt out of the RCPD charge

l

Figure 4: Impact assessment of scenario A


Draft for discussion only

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Scenario B is a more material change to the base case proposed by the Authority. It includes a move to annual pricing, and using a further simplified set of rules for the „beneficiary pay‟ charge.

Calculating charges annually significantly reduces impact

Scenario B, reduces complexity further from the base case proposed by the Authority however the scenario still requires:

• changes to all seven of the systems that support the current TPM

• introducing the Market System into the TPM process.

Due to the reduction in complexities outlined above, the implementation, ongoing support needs and impact on Transpower‟s customers will be reduced.


We estimate a programme of work will take 16 months to reach a go-live date with indicative implementation costs of $10 million.

Indicative ongoing costs to support scenario B is $1.3 million over 5 years.

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Executive summarySensitivity analysis – Alternative scenario B

Charge Alternative scenario B

Estimated level of impact

(against current TPM)*


No change l


No change lExacerbators pay• kvar charge

No change l

Beneficiaries pay• Value of private benefit (SPD model)

Use a simple set of assumptions to reduce complexity. Reduce assets included from an estimated 140 to 10

l


No change l

Figure 5: Impact assessment of the scenario B


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Table of contents


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Background and context ..................................................................................................................................... 10

The current TPM process.................................................................................................................................... 14

The Authority‟s proposal – Impact assessment ................................................................................................. 19

Alternative scenario A – Impact assessment ..................................................................................................... 29

Alternative scenario B – Impact assessment ..................................................................................................... 38

Appendices........................................................................................................................................................... 47

Appendix A – Assumptions ..................................................................................................................... 48

Appendix B – Glossary of terms.............................................................................................................. 53

Appendix C – Option assessment for Zemindar..................................................................................... 55

Appendix D – Option assessment for the Market System...................................................................... 57

Appendix E – Key stakeholders consulted ............................................................................................ 60

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Background and context


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Background

Transpower‟s revenue is set by the Commerce Commission (under part 4 of the Commerce Act) who apply price-quality regulation. This process sets out the maximum allowable revenue that Transpower can recover for a regulatory period (typically 4-5 years). The purpose of the TPM is to determine how to allocate the allowable revenue between Transpower‟s customers.

The Authority has recently identified a number of changes affecting the electricity market that represent a material change of circumstances (as defined in clause 12.86 of the Electricity Industry Participation Code 2010). These changes include:

a) Investments in the national electricity grid in excess of $2.6 billion

b) Significant changes to the regulatory framework with the Authority replacing the Electricity Commission in 2010 and approval of Grid investments moving to the Commerce Commission.

Due to these material changes, the Authority is reviewing the arrangements for determining how the costs of operating, maintaining and extending the transmission grid are allocated. The Authority has released a consultation paper (Transmission Pricing Methodology: issues and proposal – 10 October 2012) and is seeking feedback from the industry by 1 March 2013.

Details of the Authority‟s proposal can be found on page 20.

Terms of reference

The purpose of this report is to assess the impacts and implications of the Authority‟s proposal and complete basic sensitivity analysis on two alternative scenarios put forward by Transpower, on Transpower‟s systems and processes.

This report provides an assessment of the timeframes and associated costs to implement the proposed changes and identifies areas of ambiguity within the Authority‟s proposal. It is to be published by Transpower during the consultation period to help inform debate.

Due to the high level information available for this review, effort and costs in this report are indicative (+/- 50% variance) and further due diligence is required.

The report does not comment on nor review the suitability of the Authority‟s proposal or its economic benefit to the sector or to Transpower.

Background


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Our approach

Our assessment of the impact of the Authority‟s proposed changes and basic sensitivity analysis on two alternative scenarios put forward by Transpower is based on:

• reviewing the Authority‟s consultation paper and other documentation provided by Transpower

• information provided by key stakeholders at Transpower, Energy Market Services (EMS) and the Authority. (See Appendix E for a full list of stakeholders).

We used this information to:

• map Transpower‟s current business processes and systems that support the TPM

• assess the impacts of proposed changes to the TPM

• identify options for implementation of proposed changes

• estimate the cost and timeframes of implementing the proposed changes.

Approach


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Review changes to the TPM based on consultation

Map current state business process and systems that support the TPM

Asses impact

and options

Develop project

roadmap including ambiguity and risks

Figure 6: Our approach

Structure of report

The report has been structured as follows:

• Background – sets out the context to the report and how we approached the review

• Current State – outlines the systems, process and teams that support the current TPM

• Impact Assessment - for the base case and each of alternative scenarios, the following structure has been followed:

a) Summarise the proposed scenario

b) Provide an overview of the impact of the proposed changes to Transpower‟s process, technology, people and sector engagement

c) Assess the impact on Transpower‟s processes

d) Assess the impact on Transpower systems and identify possible implementation options where appropriate

e) Outline the indicative implementation timeframes and costs

f) Outline the ongoing costs for the proposed changes (over five years).

Further supporting material is provided in the attached appendices.

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Assessing the impact to the current TPM

The high level information in the Authority‟s consultation paper and the short time frames for the review means the estimates in this report are indicative and based on the judgement of the team undertaking the review and information available. Further analysis will be required, as the Authority‟s consultation develops, to validate the assumptions and therefore the cost and time estimates.

The assessment criteria used to determine the level of impact of the proposed scenarios on Transpower‟ s systems and processes is described in the table below.

Approach (cont…)


13

Figure 7: Assessment criteria for level of impact

Level of impact (colour)

Definition

High (red) System/process requires major redesign and enhancement to meet the proposed requirements

Medium (amber) System/process requires moderate redesign and enhancement to meet the proposed requirements

Low (green) System/process requires minor redesign and enhancement to meet the proposed requirements

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The current TPM process


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Purpose of the TPM

The outcome sought by the TPM is to ensure the full costs of transmission services are allocated. The costs of transmission services derive from Transpower operating, maintaining, upgrading, extending and owning the national grid.

Every year, the TPM requires Transpower to determine the allocation of the transmission charges amongst transmission customers that will allow it to recover its maximum allowable revenue for that year.

Components of the TPM

The elements of the TPM can be summarised as:

a) A connection charge that recovers the cost of the dedicated Alternating Current (AC) assets connecting a distributor, major user or a generator to the national grid

b) A High Voltage Direct Current (HVDC) charge that recovers the cost of the link between the North and South Islands. This charge is paid by the South Island generators based on their share of peak injections

c) An interconnection charge that recovers the cost of assets used to transmit power between a Grid Injection Point (GIP) and a Grid Exit Point (GXP). The charge is paid by customers taking power off the Grid at each GXP at which they have assets connected to the national grid.

The current TPM also includes a Prudent Discount Policy (PDP). Its purpose is to discount transmission charges in order to avoid customers bypassing existing national grid assets. The PDP allows Transpower to discount charges for a party who can demonstrate that an alternative project would result in lower overall costs to them as a customer, than the current Transpower charges.

What are the components of the current TPM?


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How does Transpower deliver the TPM?The current process is completed annually

The process map on the left (Figure 8), describes at a high level the current steps taken, the supporting systems and the points of customer engagement, to allocate the transmission charges under the current TPM.

The process is completed annually over a seven month period (typically June – December).

The processes and steps are predominantly manual. They involve accessing and updating documents on Transpower‟s shared drive and SharePoint application.

The teams involved in executing the current process are discussed on the page 18.

A glossary of the systems and terms relating to the process map can be found in appendix B.

16Figure 8: Transpower’s current state TPM process Source: Transpower

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Seven systems support the current TPM process

The system diagram (Figure 9) below shows at a high level how Transpower‟s systems interact to support the current state process.

All interfaces between the systems are manual and require users to upload the data into the target system. This is currently completed on an annual basis, except for the capacity data, which is received monthly from Energy Market Services (EMS) and loaded into MDR.

What systems support the TPM?

Figure 9: Map of Transpower’s systems supporting the current TPMSource: Transpower

After the cost and asset information is loaded into Zemindar it is then added to the customer website where transmission customers are required to approve the information. The Planning and Regulatory team completes the allocation process (in Zemindar) once approval has been received from customers.

Further descriptions of the systems can be found in Appendix B.

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There are four teams involved in delivering the current process

The teams involved with executing and supporting the current TPM process are Finance; Customer; Planning and Regulatory; and Information Services and Technology (IST).

The high level delivery process steps and the number of full time equivalents (FTEs) involved in the process are outlined in Figure 10 below.

The level of FTE support required for the TPM is annualised at 5.5 FTE. There is a dedicated focus from these individuals during the peak of the pricing round (June – December).

The FTE numbers reflect the average level of support to the process throughout the year as they also undertake other functions.

What teams deliver the TPM?


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Figure 10: Teams and their role in delivering the TPMSource: Transpower

Team involved in the process:

High level process steps

Number of staff:

Annual FTE equivalent

effort:

Determine AC assets

Determine demand and

customer allocation

Determine maintenance and operating

costs

Determine customercharges

Invoice customers

Finance 4 4 4 6.0 1.0

Customer 4 4 4 7.0 2.5

Planning and Regulatory

4 4 4 4 4.0 1.5

IST 4 4 4 4 4 3.0 0.5

Total 20.0 5.5

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The Authority’s proposal – Impact assessment


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The charges are allocated according to each charging option and in descending order. For example the loss and constraint excess (LCE) charges will be allocated first and then the residual is moved down to the contracts and so forth.

The Authority’s proposal

The party that benefits should pay

The Authority‟s consultation document for the TPM states that the changes are based on the principle of „the party that benefits should pay‟. The intention being to provide a robust and durable methodology that will allow customer charges to shift over time without a need for review as is the case at present.

The charging options proposed by the Authority are outlined in Figures 11 and 12 below and described in further detail on the following page.

Charging option Asset/service covered by charge

Expected % of costs recovered*


Entire Grid 5-20%


Connection 15%

Exacerbators pay• kvar charge Static Reactive support 0.2%

Beneficiaries pay• Value of private benefit (SPDmodel)

% of HVDC and interconnection

30-60%

Administrative approach• RCPD/RCPI• Prudent Discount Policy (PDP)

Residual costs 5-50%

Market approach

Market-like approach

Exacerbators pay

Beneficiaries pay

Administrative

approaches

* Percentages recovered by the charges will vary but will always add up to 100% of the revenue as defined by the Commerce Commission.

Figure 11: Funnel approach to charging

Figure 12: Summary of charging optionsSource: Transmission Pricing Methodology: Issues and proposal paper

Prices set monthly

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The following summary provides further details on the Authority‟s proposal. For full details, refer to the Transmission Pricing Methodology: issues and proposal – 10 October 2012.

1) Market approach – Confirm the existing arrangements used in the spot market to pay for transmission services.

The spot market uses the Scheduling, Pricing and Dispatch (SPD) model to dispatch generation by taking into account security constraints in the national grid and estimated energy losses between the GIP and GXP. The presence of losses and constraints causes differences in the spot prices and produces surplus funds (called loss and constraint excess or LCE). The Authority‟s proposal will add the current approach to the Electricity Industry Participation Code 2010 (the Code) which governs participants within the electricity industry.

The proposal will codify the current arrangements for use of the LCE and future Financial Transmission Rights (FTR) auction proceeds where they are used to offset components of the transmission charges (connection and HVDC) but the current arrangements for distributing LCE from interconnection assets will be changed.

2) Market-like approach – Modify the existing connection charge process by:

a) Requiring assets classed as connection assets to remain in this class until replaced or decommissioned

b) Valuing assets at their actual replacement cost

c) Introducing a process for disputes between Transpower and its customers to be referred to the Authority for resolution.

3) Exacerbator charge - Introduce a charge that recovers the costs associated with providing static reactive support services. These services are assets that provide reactive power (measured in VAR‟s) to support the required voltage for operating the system.

4) Beneficiary pay - Change the approach for recovering part of the interconnection and HVDC services by using the SPD model (part of the Market System) to allocate any residual charge (left over from 1, 2 and 3 above).

The costs will be charged to the parties that benefit based upon their share of injection to or power drawn from the national grid within a trading period (30 minutes). This approach would only apply to assets worth more than $2 million and approved after 28 May 2004 and pole 2 of the HVDC link.

5) Administrative approach – Transmission charges not recovered through the methods above will be recovered through two approaches:

a) The Regional Coincident Peak Demand (RCPD) and Regional Coincident Peak Injection (RCPI). This charge will apply to generators, direct connect users, distributors and retailers. Transpower is expected to calculate the charges so that each raises half the residual balance.

b) Distributors will have the ability to opt out of this charge.

c) Extending the PDP to include certain scenarios when transmission charges would cause load to disconnect and invest in generation

The Authority’s proposal (cont…)


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Impact assessment of the Authority’s proposed changes

The table below outlines the assessed impact of the Authority‟s proposal on Transpower‟s process, technology, people and level of sector engagement.

The level of impact assessment criteria used can be found in the approach section on page 13. The rationale for the rating (red, amber or green) is noted in the table.

The Authority’s proposal will impact the following areas


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ChargeThe Authority’s

ChangeLevel of impact

Impact on:

Process Technology People Sector Engagement

Market approach

• LCE

• FTR Auctions

Add the current approach to the Electricity Industry Participation Code 2010 (the Code) l

The process steps involved in assigning LCE will require updating and new business rules determined

Allocating LCE to specific corresponding assets will require added complexity to the pricing engine


• Long term contracts

Require assets classed as connection assets to remain in this class until replaced or decommissioned

l

The process steps involved in confirming connection assets will require updating and new business rules determined

The FMIS system that holdsasset information will need to be updated to reflect the change

Require assets to be valued at their actual replacement cost

Valuation of assets is currently done using a building block approach – this process will need to be updated or replaced

The FMIS system that holdsasset information will need to be updated to reflect the change

Customers are likely to expect more information due to the increased cost to them.

This increased engagement will affect the customer facing teams

Increased effort will be required to work with the sector to understand the process and reasons behind the change

Introduce a process for disputes between Transpower and its customers to be referred to the Authority for resolution

A new process is required to allow customer charges to be updated should the Authority consider a disputed charge

The pricing engine and invoicing system will require additional functionality and increased flexibility to allow for changes to customer charges

This change will impact both the customer facing teams who communicate with the customers and the Authority, and who will make the adjustments

The sector will need to be made aware of the dispute and resolution process

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ChargeThe Authority’s

ChangeLevel of impact

Impact on:

Process Technology People Sector Engagement

Exacerbators pay

• kvar charge

Introduce a new charge for recovering the costs of static reactive support

l

EMS will need to make an adjustment to the file (from GMMS) sent to Transpower to include kvar data

A change to MDR and the pricing engine will be requiredso the new data can be stored, and used to calculate the charge.

FMIS, SharePoint and Billing Prep will need to be updated to accept the kvar charge information for the purposes of invoicing customers

The Planning and Regulatory team will be required to complete the new steps required to support this additional charge.

There will be monthly reports required for customers – refer to Sector Engagement

Additional communications and reporting will need to be made available to customersallow them to understand this charge.

The kvar metering data will need to be included in the raw data provided to customers via the customer website

Beneficiaries pay

• Value of private benefit (SPD model)

Use the SPD model (part of the Market System) to allocate any residual costs left over from the charges outlined above. The costs will be charged to the parties that benefits based upon their share of injection to or power drawn from the national grid within a trading period

l

New business processes will be required to support the beneficiaries-pay charge as there will be new and frequent data feeds coming from the Market System and Retail Reconciliation System.

The process of preparing, validating and sending customer invoices will become more complex due to the variable nature of the new beneficiaries-pay charge

Significant redesign of the pricing engine will be required to understand and use the outputs from the Market System to calculate the beneficiaries pay charge.

The volume and frequency of feeds into the pricing engine will increase from annually to daily or monthly

Planning and Regulatory and Finance teams will be impacted due to the changes in the monthly charging calculations and invoice process.

The customer facing teams will require greater interaction with customers, particularly over the first year after rollout. The number of relationships managed will increase as retailers and purchasers are included

Transmission customers will need to be communicated with more frequently and monthly reporting made available to allow them to understand this charge via the customer website

Administrative approach:

• RCPD/RCPI

• Prudent Discount Policy (PDP)

Transmission charges not recovered through the methods above to be recovered through Regional Coincident Peak Demand (RCPD) and Regional Coincident Peak Injection (RCPI) charges.

Distributors can opt out of RCPD charge

l

EMS will need to add RCPI data to the file that is sent to Transpower.

New processes will be required to allow distributors to opt out of the RCPD charge

Refer to Exacerbators pay kvar charge above

Interface with retail reconciliation system will be required to allocate charges to wholesale market purchasers and sellers.

The Planning and Regulatory team will be required to complete new procedures required to support this additional charge.

Additional report (containing RCPI information) will need to be made available to each customer, similar to the current RCPD report.

The RCPI metering data will need to be included in the raw data provided to customers.

Refine the Prudent Discount Policy l Low impact

The Authority’s proposal will impact the following areas (cont…)

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The Authority’s proposal – Impact on processes

The way assets are classified and valued will change

New approach

Change to inputs for the current connection charge

Business processes for charging customers will change to accommodate the monthly billing cycle

New data will be required from the Market System to determine inputs for the beneficiaries pay charge.

A redesign of the charging process will be required to handle the new allocation rules: beneficiaries pay charge, the exacerbators pay charge and to allocate the residual amount between the alternative approaches.

Business process will be updated to support the changes

Additional data will be loaded into the pricing engine and processing will increase to monthly

Customers will need to be informed on the new charges and additional processes, e.g. Dispute process, understanding monthly bills. Reporting and data will need to be made available to customers to assist with understanding the of the charges

High Impact

Medium Impact

Low Impact

Additional metering data (RCPI and kvar) will be required from EMS to the MDR system

The proposed process will need to be completed monthly

The proposed changes will require Transpower to allocate transmission charges on a monthly basis instead of annually. This means that the current process will need to be upgraded to cope with significant additional complexity and compressed from the current 6 month price setting process to a monthly price setting and billing cycle. It is expected that where possible, steps (such as interfaces) will need to be automated in order to achieve the processing timeframe.

Assessing the impact to the TPM process

Figure 13 shows the impact of the proposed changes on the current TPM process.

The level of impact assessment criteria used can be found in the approach section on page 13.

24Figure 13: Impact of the Authority’s proposal on current state

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Significant change is required to Transpower’s systems

All of the systems that support the TPM are affected by the proposed changes. Zemindar and the introduction of the Market System are most affected and require the biggest change to meet the requirements.

Assessing the impact to Transpower’s systems

Figure 14 shows the level of impact of the proposed changes on the systems that support the TPM. It also outlines the possible implementation options that could deliver the required changes.


The Authority’s proposal – Impact on systems

Zemindar does not have the current capability to support the required changes. New functionality would need to be developed specifically for Zemindar and a complete redesign of the allocation process and interfaces.

Two options were considered to implement the changes: enhance Zemindar or implement a new business solution. Based upon our preliminary assessment, the replacement of Zemindar is considered the preferred option. Refer to appendix C for further details on each option

The increased frequency of feeds (monthly) will require automated interfaces between the source and target systems instead of the current manual process.

Additional inputs into the process will be required –including kvar and RPCI data

The current Market System acts as the electricity wholesale market clearing engine. It performs approximately 2000 calculations („solves‟) per day. To determine the „party that benefits‟ using the Market System, approximately 6720 alternate scenarios (counter-factuals) need to be calculated (based upon 140 assets meeting the criteria). This is seen as a significant technical processing activity.

Three options to deliver the changes have been identified: scale the existing Market System, setup a new instance or build a be-spoke solution. Further investigation is required to determine the appropriate solution. Refer to appendix D for further details on each option

Kvar and RCPI data will need to be provided by EMS

Additional reporting and raw data will need to be made available to customers on a monthly basis via the website for all TPM charges

Minor updates will be required to accommodate the new data requirements

High Impact

Medium Impact

Low Impact

Figure 14: Impact of the Authority’s proposal to systems/interfaces

New interface required to support pricing process (beneficiaries pay charge)

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Implementation of the proposed changes is estimated to require 18 months elapsed time

The scale of impact to Transpower‟s systems and processes means that significant effort will be required to implement the necessary changes. Based upon a standard Software Development Life Cycle (SDLC) and using our experience with large scale technology programmes, we estimate that 18 months elapsed time will be required.

This level of effort will require a programme of work to be established with the appropriate governance, business change and project management resources.

Confirmation of the TPM guidelines by the Authority is a critical dependency

Confirmation of the TPM guidelines by the Authority is a critical input into the work programme as it provides the key requirements and outcomes that Transpower should be seeking to achieve. Any changes to the proposal could increase or decrease the effort, technical achievability, associated costs and the implementation timeframes.

The Authority’s proposal – Implementation timeframes


26

Figure 15: Implementation timeframe – Authority’s proposal

The approach chosen for roll out and time/cost required will depend on the TPM changes confirmed and level of customer engagement required

The time/cost required to draft the TPM rules is not included

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Indicative cost to implement the proposed changes is ~$13M

The indicative implementation cost has been estimated using the information provided by Transpower and our experience with large programmes of work.

The table below shows the estimated costs across the major work streams.

Work Stream Effort (days) Cost ($M)

Technology 5300 – 5900* 6.9 – 7.8*

Business process 500 0.7

Change management 550 1.1

Sector engagement 250 0.5

Project management/governance

800 1.6

Hardware/Software N/A 1.7

Total 7,400 – 8,000 12.5 – 13.4

The Authority’s proposal – Implementation costs


A number of key assumptions have been made

To establish the estimates, we have made a number of assumptions. The key assumptions are noted below, and the full set can be found in appendix A.

1. Costs exclude GST

2. The level of accuracy in the estimates is +/-50%

3. To implement the changes, it is expected that Transpower will utilise its external support partners

4. Costs reflect the preferred implementation options (as identified in page 25). Further due diligence is required to confirm these options and costs may change depending on the outcome of this further investigation

5. Transpower will lead the engagement with the sector

6. The approach taken for rollout will depend on the changes implemented and level of engagement required from Transpower‟s customers to understand the new TPM. Additional time and cost will need to be factored in for the chosen approach.

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Figure 16: Indicative costs – Authority’s proposal

* The range reflects the possible technology options available to deliver the proposed Market System changes. See page 25 for the options considered

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Additional FTE’s will be required to support the new TPM process

The complexity of the proposed changes and move to monthly operations will require an increase to the resources available to the teams that support and execute the TPM. Specifically, the increase in ongoing costs will support:

• Increased communication with customers as their charges will vary month to month and more frequent discussions on charges are likely to be required. The first year is expected to require a higher level of engagement with customers as they develop their understanding of the allocation process

• A wider set of customers will need to be engaged as the beneficiaries pay and administrative charges will apply to retailers

• Added complexity for the Planning and Regulatory and Finance team in executing the TPM process (refer to page 24), as new data is added to the process and calculations move from an annual to a monthly cycle

• Additional reporting and raw data sets will need to be uploaded to the customer website on a monthly basis should customers want to validate their charges

• The changes to the technology systems and interfaces means that additional resources will be required for IST to support and maintain the systems

• Costs are in 2012 dollars and exclude GST.

For the full list of assumptions, please refer to Appendix A.

The Authority’s Proposal – Ongoing costs

28

Team Year 1 Year 2 and ongoing

FTE Increase Cost($000) FTE Increase Cost($000)

Finance 1 85 1 85

Customer 2.5 212 1 85

Pricing, Regulatory 2.5 213 2 170

IST 2.5 228 1.25 114

Non-personnel costs - 340 - 340

Total 8.5 1,078 5.25 798

Figure 17: Indicative timeline – Authority’s proposal

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Alternative scenario A –Impact assessment


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Alternative scenario A is summarised in Figures 18 and 19 below and described in further detail on the following pages.

Alternative scenario A – Overview

An alternative to the Authority’s proposal

Transpower has asked us to explore two alternatives scenarios to test the sensitivity of timeframe and cost estimates from the Authority‟s proposal. The first alternative, scenario A, proposes a shift in the complexity of the charges which reduces the impact on Transpower‟s systems and processes when compared to the Authority‟s proposal.

Charging option Asset/service covered by charge & estimate costs recovered*

Alternative scenario A


Entire Grid 5-20%

No change


Connection 15%

No change


Static Reactive support0.2%

No change


% of HVDC and interconnection 30-60%

•Use simplified SFT/RMT for the Market System•Reduce number of assets included to 70 with 10 additional assets per year thereafter


Residual costs 5-50%Allow all or no distributors to opt out of the RCPD charge

Market approach


Exacerbators pay

Beneficiaries pay

Administrative approach

•Percentages recovered by the charges will vary but will always add up to 100% of the revenue as defined by the Commerce Commission.

Figure 18: Funnel approach to charging under alternative scenario A

Figure 19: Summary of changes to charging options for alternative scenario A Source: Transpower

Prices set quarterly based on last 12 months

30TPM Impact Assessment

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Alternative scenario A will impact the following areas

Charge Level of impact Alternative scenario AHow the change will impact implementation and ongoing

costs

Pricing allocation frequency l

Set the charging cycle to quarterly, instead of monthly, based on the last 12 months

Monthly calculations and supporting processes will be reduced from monthly to quarterly which will reduce the work load for the teams involved

Market approach

• Loss and constraint excess (LCE)

• FTR Auctions

l No change

Market-like approach Long term contracts l No change

Exacerbators paykvar charge l No change

Beneficiaries pay


l

Reduce the complexity of the Market System by using a small set of assumptions regarding assets for the simultaneous feasibility test (SFT) and the reserve management tool (RMT)

Use of assumptions will reduce the required complexity of the Market System

Reduce number of assets from 140 to 70 with an additional 10 assets added per annum thereafter

Reduction of the number of assets this charge applies to would reduce the amount of scenarios the Market System would be required to run

Reduce counterfactual complexity used by the Market System by limiting the variables for each asset by applying assumptions

Use of assumptions will reduce the complexity of the Market System

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Impact assessment of alternative scenario A

The table below outlines the assessed impact of alternative scenario A on Transpower process, technology, people and sector engagement and is contrasted against the impact of the Authority‟s proposal.


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Alternative scenario A will impact the following areas (cont...)


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Charge Level of impact Alternative scenario AHow the change will impact implementation and ongoing

costs


• RCPD/RCPI


l

No change

All distributors must decide to opt in or out of the RCPD residual charge – instead of allowing only some to opt out

This change will still require supporting processes to be set up, however it will be easier to embed the processes as there will be clear responsibility for the charge

No change

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Alternative scenario A – Impact on processes

New approach

As per the impact of the Authority‟s proposal



Same as Authority‟s proposal except for processing of customer allocations will be quarterly instead of monthly


High Impact

Medium Impact

Low Impact

The alternative proposal will require the TPM to be completed quarterly

By calculating the transmission charges on a quarterly basis and simplifying the proposed changes to the Market System, the impact on the TPM process will be reduced.

Assessing the impact on processes of scenario A

Figure 20 shows the impact of alternative scenario A on the current TPM process and is contrasted against the impact of the Authority‟s proposal.


33



Figure 20: Impact of alternative scenario A on current state

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Significant change will still be required to Transpower’s systems

The seven systems that support the current TPM will require changes to deliver the alternative scenario. However, the simplified SFT/RMT rules will reduce the effort required to implement the „beneficiary pays‟ charge.

Assessing the impact to Transpower’s systems

Figure 21 shows the impact of alternative scenario A on Transpower‟s systems and is contrasted against the impact of the Authority‟s proposal.


Alternative scenario A– Impact on systems

As per Authority‟s proposal

As per Authority‟s proposal except feeds will change to quarterly

The alternative rules for determining the beneficiary pays charge will result in fewer calculations (solves) being required – approximately 3360 solves per day instead of 6720. The simplified SFT/RMT models will also reduce the implementation effort by utilising a set of assumptions instead of the full model.



As per Authority‟s proposal except data will need to be available quarterly


High Impact

Medium Impact

Low Impact

34Figure 21: Impact of the alternative scenario A on systems/interfaces


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Implementation of the proposed changes will be reduced to 16 months

Alternative scenario A has reduced the complexity of the implementation, when compared with the Authority‟s proposal but all of the systems that support the TPM will still require changes. Based upon a standard SDLC and using our experience with large scale technology projects, we estimate that 16 months elapsed time will be required to implement the proposed changes.

As per the assessment of the Authority‟s proposal, a programme of work will need to be established with the appropriate governance, business change and project management resources to implement the proposed changes.

Confirmation of the TPM guidelines by the Authority is still critical

Confirmation of the TPM guidelines (whether in line with this alternative scenario or otherwise) by the Authority is still a critical input to the work programme. Any changes to the proposal could increase or decrease the effort, associated costs and the implementation timeframes.

Alternative scenario A – Implementation timeframes

35Figure 22: Implementation timeframe – Alternative scenario A


The time/cost required to draft the TPM into rules is not included

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Indicative cost to implement alternative scenario A is $11.5M

The indicative implementation cost has been estimated using the information provided by Transpower and our experience with large programmes of work. It reflects the scale of changes required to Transpower systems and processes. The table below shows the costs across the major work streams and highlights the change from the Authority‟s proposal.

Work Stream Effort (days) Cost ($M)Change against

Authority

Technology 5,200 – 5,800* 6.8 – 7.5*

Business process 500 0.7 -




650 1.0

Hardware/Software N/A 1.7 -

Total 7,100 – 7,900 11.3 – 12

Alternative scenario A – Implementation costs


To establish the estimates, we have made a number of assumptions. The key assumptions are noted below. The full set can be found in Appendix A.







36

Figure 23: Indicative costs – Alternative scenario A


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There is a reduced level of ongoing support required

Alternative scenario A will require a smaller increase, when compared to the Authority‟s proposal, in the resources required to support and execute the TPM. Specifically, in addition to the proposed changes identified earlier in the Authority‟s proposal (see page 30) the changes are:

• Increased interaction with customers as their charges will vary quarter to quarter and more frequent discussions on charges are likely to be required

• A wider set of customers will need to be engaged by Transpower‟s customer facing teams as the new beneficiaries pay charge will apply to retailers and other wholesale market participants

• Additional reporting and raw data sets will need to be uploaded to the customer website on a quarterly basis should customers wish to validate their charges



Alternative scenario A – Ongoing costs


37

Team Year 1 Year 2 and ongoing

FTE Increase Cost($000) FTE Increase Cost($000)

Finance 1 85 1 85

Customer 1 85 - -

Pricing, Regulatory 2 170 2 170

IST 2 170 1.25 114

Non-personnel costs - 340 - 340

Total 6 850 4.25 709

Figure 24: Indicative timeline – Alternative scenario A

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Alternative scenario B – Impact assessment


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Market approach


Exacerbators pay

Beneficiaries pay

Administrative approach

Alternative scenario B – Overview

Charging option Asset/service covered by charge & estimate costs recovered*

Alternative scenario B


Entire Grid 5-20%

No change


Connection 15%

No change


Static Reactive support0.2%

No change


% of HVDC and interconnection 30-60%

• Reduce number of assets included to 10 with 2 additional assets added per year thereafter• Counterfactual complexity: single static


Residual costs 5-50%No change

* Percentages recovered by the charges will vary but will always add up to 100% of the revenue as defined by the Commerce Commission.

Figure 25: Funnel approach to charging under alternative scenario B

Figure 26: Summary of changes to charging options for alternative scenario BSource Transpower

Prices set annually based on last 12 months

39


Further reduction of complexity in the implementation of the „beneficiaries pay ‟ charge will reduce the impact on systems.

Alternative scenario B is summarised in Figures 25 and 26 below and described in further detail on the following pages.

An alternative to the Authority’s proposal

Alternative scenario B, put forward by Transpower for sensitivity analysis, further simplifies the changes when compared to alternative scenario A.

A move to annual pricing will reduce the impact both internally, on processes and systems, and on transmission customers. It will also reduce the level of ongoing support required for the TPM.

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Impact assessment of alternative scenario B

The table below outlines the assessed impact of alternative scenario B on Transpower process, technology, people and sector engagement and is contrasted against the impact of the Authority‟s proposal.

.


Alternative scenario B will impact the following areas

40

Charge Level of impact Alternative scenario B How the change will impact implementation

Pricing allocation frequency l

Set the charging cycle to annually, instead of monthly, based on the last 12 months

Pricing calculations and supporting processes will be changed to annually which will reduce the work load for the teams involved in the TPM process

Market approach

• LCE and FTR Auctions l No change


• Long term contracts l No change

Exacerbators pay

• kvar charge l No change

Beneficiaries pay


l

Reduce the complexity of the charge by usinga simplified bespoke solution (using the vectorised SPD (vSPD) model)

Use of a simplified set of assumptions and vSPD model will reduce the effort required to implement the beneficiary pays charge

Change the definition of assets for this charge from an estimated 140 assets to 10 assets with 2 added per year thereafter

Reduction in the number of assets this charge applies to would reduce the amount of scenarios the bespoke solution would be required to run

Reduce counterfactual complexity used by a simplified SPD model by having no variables (single static)

Use of assumptions will reduce the complexity of the bespoke solution

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Alternative scenario B will impact the following areas (cont...)


41

Charge Level of impact Alternative scenario B How the change will impact implementation


• RCPD/RCPI


l No change

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Alternative scenario B – Impact on processes

As per the Authority proposal

Change to inputs for the current connection charge

The invoicing processes will need to change to reflect the new charges

New data will be required from the bespoke solution to determine inputs for the beneficiaries pay charge.

Additional data will be loaded into the pricing engine and processing will be done annually

Customers will need to be engaged on the beneficiary pays charge and additional processes e.g. Dispute process.

Additional reporting and data will need to be made available to customers on an annual basis

High Impact

Medium Impact

Low Impact

The alternative scenario will require the TPM to be completed annually

By calculating the transmission charges on a annual basis, removing two of the charges and simplifying the proposed changes by utilising a simplified SPD model the impact on the TPM process will be significantly reduced when compared to the Authority‟s proposal.

Assessing the impact on processes of scenario B

The following diagram shows the impact of alternative scenario B on the TPM process and is contrasted against the impact of the Authority‟s proposal.


42Figure 27: Impact of alternative scenario B on current state

New approach

New functionality to the pricing engine will be required to accommodate this charge

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Alternative scenario B will require a reduced level of change to Transpower’s systems

All of the systems that support the current TPM are affected by this alternative scenario. The most significant change will occur with the implementation of simplified SPD model.

Assessing the impact on Transpower’s systems

The following diagram shows the impact of alternative scenario B on the TPM process and is contrasted against the impact of the Authority‟s proposal.


Alternative scenario B– Impact on systems

As per the Authority‟s proposal except processing will continue annually

The alternate rules for determine the beneficiary pays charge will result in fewer additional calculations („solves‟) – approximately an additional 240 instead of 720 required by the Authority‟s proposal.


High Impact

Medium Impact

Low Impact

43Figure 28: Impact of the alternative scenario B on systems/interfaces

As per Authority‟s proposal except feeds will change to annually




As per Authority‟s proposal except data will need to be available annually

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Implementation of the scenario B is estimated to require 16 months of elapsed time

Alternative scenario B has reduced the complexity of the implementation and only four of the systems that support the TPM are affected. Based upon a standard SDLC and using our experience with large scale technology projects, we estimate a minimum of 16 months elapsed time will be required to implement the required changes.

As per the assessment of the Authority‟s proposal, a programme of work will need to be established with the appropriate governance, business change and project management resources to implement the proposed changes.

Confirmation of the TPM guidelines by the Authority is critical

Confirmation of the TPM guidelines (whether in line with this alternative scenario or otherwise) by the Authority is still a critical input to the work programme. Any changes to the proposal could increase or decrease the effort, associated costs and the implementation timeframes.

Alternative scenario B – Implementation timeframes


44Figure 29: Implementation timeframe – Alternative scenario A


The time/cost required to draft the TPM into rules is not included

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Indicative cost to implement alternative scenario B is ~$10M

The indicative implementation cost has been estimated using the information provided by Transpower and our experience with large programmes of work. It reflects the scale of changes required to Transpower systems and processes. The table below shows the costs across the major work streams and highlights the change from the Authority‟s proposal.

Work Stream Effort (days) Cost ($M)Change against

Authority

Technology 4,800 – 5,100* 6.3 – 6.6*

Business process 500 0.7 -




650 1.0

Hardware/Software N/A 0.7

Total 6,700 – 7,000 9.8 – 10.1

Alternative scenario B – Implementation costs


To establish the estimates, we have made a number of assumptions. The key assumptions are noted below. The full set can be found in Appendix A.







45

Figure 30: Indicative costs – Alternative scenario B


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There is a small increase in the level of ongoing support required

Alternative scenario B will require a smaller increase, as compared to the Authority‟s proposal, in the resources available to the teams that support and execute the TPM. Specifically, the proposed changes will require:

• Increased engagement with customers as the TPM is now more complex and more frequent discussions on charges are likely to be required. The first year is expected to require a higher level of engagement with customers as they develop their understanding of the allocation process

• Additional reporting and raw data sets will need to be uploaded to the customer website on a annual basis should customers wish to validate their charges



Alternative scenario B – Ongoing costs


46

Team Year 1 Year 2 Year 3 and ongoing

FTE Increase

Cost($000)FTE

IncreaseCost($000)

FTE Increase

Cost($)

Finance - - - - - -

Customer - - - - - -

Planning & Regulatory

2 170 1 85 - -

IST 1 85 1 85 1 85

Non-personnel costs - 130 - 130 - 130

Total 3 385 2 300 1 215

Figure 31: Indicative timeline – Alternative scenario B

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Appendices


47

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The following assumptions apply to all three of the options discussed in the report.

• Costs exclude GST and are in 2012 dollars

• The daily rates used in the calculation of the implementation costs reflect current market rates. The daily rates used are:

• $1300 for the technology and business process work streams

• $2000 for the change management, sector engagement and project management work streams.

• The indicative annual FTE salaries were provided by Transpower. They are:

• $85,000 per annum for an analyst

• $115, 000 per annum for a team leader/manager

• Implementation costs include the first month of support after go-live

• The technology work stream includes costs for system/interface changes and testing effort

• Applications will be on hosted on Transpower‟s virtualised environment

• Ongoing non-personnel costs (hardware and software) have been calculated at 20% per annum of the initial purchase cost

• Any costs relating to the implementation of system changes for Transpower‟s customers have not been included

• Transpower will lead the engagement with the sector once the TPM guidelines have been developed

• The programme is expected to follow Transpower‟s standard Software Delivery Life Cycle and associated stage gates

• The Board approval and independent audits of the TPM process will continue on an annual basis

• Allocation of charges for the „beneficiary pay‟ charge will require final data that has been approved by the clearing manager (NZX). Costs for NZX to provide the required data have not been included. This means the „beneficiary pay‟ charge will not be calculated in real time

• Allocation of charges for the „beneficiary pay‟ charge will require allocations at each GXP from the Retail Reconciliation system. Costs for the Reconciliation Manager to provide the required data have not been included

• Changes to the Energy Market Exchange (eM6) system have not been included in the implementation costs. The eM6 system has load and price information and RCPD that is provided to customers in near real time and is supported by EMS

• MMS will be replaced by the Asset Management Information System by December 2013 and so any interface development will be between AMIS and the Pricing Engine.

Appendix A: Assumptions General assumptions


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Phase Definitions for implementation

The following phase definitions and associated activities have been used.

Strategy & Assess - Focuses on mobilising the project team and assessing the current state. Specifically the activities are:

• mobilisation of the project team and governance

• covers base-lining of existing processes/systems/information.

• building the initial business case and benefits management

• undertake stakeholder/organisation impact analysis.

Design - Focuses on developing the target state view of the systems/processes/requirements and the change management activities required. Specifically the activities are:

• design target system architecture

• define target process map (down to level 4)

• define functional/non-functional system requirements and integration requirements

• design change management/training approach

• design migration approach.

Build- Focuses on building/customising or configuring the systems and interfaces and the respective testing required.

• build/configure systems, reports and interfaces

• undertake unit/system/integration/user acceptance testing

• build reports.

Implement - Focuses on the activities required to deploy the system into the production environment, the associated training and business acceptance as well as the 1st month of support for the new systems.

• implement systems/interfaces into production

• undertake data migration

• deliver training

• business acceptance

• deliver sector communications.

Appendix A: Assumptions (cont...)General assumptions


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Pricing Engine (Zemindar) changes

• Data migration is required to bring existing pricing data into the new system

• For reporting purposes 12 reports have been estimated as being required. Build effort has been determined by

• 4 reports (simple complexity) @ 10 days effort for each

• 4 reports (medium complexity) @ 20 days effort for each

• 4 reports (high complexity) @ 35 days effort for each.

Market System

• Data migration is not required

• Pricing for the „beneficiary pay‟ charge will be determined monthly. This also means that assets (that meet the criteria) will be included as they are commissioned

• The schedule development is the construction of the alternative (counterfactual) scenarios. There will be approximately 140 additional scenarios required to be created (based upon initial assessment against the Authority's proposal). This will result in ~6720 additional solves per day which is three times the current workload (currently only ~2000 solves are done per day)

• The Authority‟s proposal requires dynamic resolution of the SFT/RMT systems for a solve for each counterfactual scenario therefore requiring access to data from those systems.

Interfaces

• EMS - MDR/MDR - Pricing Engine will require significant revision as RCPI and kvar information will need to be added

• RCPI information is able to be easily sourced from Grid Injection Points

• FMIS/AMIS - Pricing Engine interfaces will only require minor changes to add additional data and automate the current feed

• Pricing Engine - Billing is a new interface. However, no changes are required to the Billing Engine side

• Market System - Pricing Engine is a new interface

• Retail Reconciliation System – Zemindar is a new interface.

Non-Personnel costs

• Hardware costs relate to the purchase of servers for the Market System and the pricing engine replacement

• Software licences costs include purchase of additional licenses for the Market System, pricing engine replacement and other standard operating software such as Oracle/Windows etc.

Appendix A: Assumptions (cont...) The Authority’s proposal


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Pricing Engine (Zemindar replacement)


• For reporting purposes 12 reports have been estimated as being required. Build effort has been determined by:

• 4 reports (simple complexity) @ 10 days effort for each

• 4 reports (medium complexity) @ 20 days effort for each

• 4 reports (high complexity) @ 35 days effort for each.

Market System


• Schedule development is the construction of the alternative (counterfactual) scenarios. There will be approximately 70 additional scenarios required to be created (based upon alternative scenario A). This will result in an additional~ 3,360 solves per day which is an increase to the current workload

• Scenario A requires dynamic resolution of the SFT/RMT systems for a solve for each counterfactual scenario therefore requiring access to data from those systems.

Interfaces







Non-Personnel costs

• Hardware costs relate to the purchase of servers for the Market System and the pricing engine replacement

• Software licences costs include purchase of additional licenses for the Market System, pricing engine replacement and other standard operating software such as Oracle/Windows etc.

Appendix A: Assumptions (cont...) Alternative scenario A


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Zemindar


Market System

• The bespoke solution, using the vSPD model as a starting point, can be used due to the simplified rules for the beneficiary pays charge


• No additional reporting is required from the vSPD system

• Schedule development is the construction of the alternative (counterfactual) scenarios. There will be approximately 10 additional scenarios required to be created (based upon the alternative scenario B). This will result in an additional 480 solves per day

• Scenario B does not require dynamic resolution of the SFT/RMT systems for each counterfactual scenario due to the simplified rules used for the counterfactual scenarios.

Interfaces







Non-Personnel costs

• Hardware costs relate to the purchase of servers for vSPD and Zemindar

• Software licences costs include purchase of additional licenses for vSPD and other standard operating software such as Oracle/Windows etc.


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Appendix A: Assumptions (cont...) Alternative scenario B

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Appendix B: Glossary of terms


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Term Our understanding

AC asset A Grid asset which is not an HVDC asset. Includes for example – switches, transformers, substations, lines

Asset replacement costs The cost of replacing an asset with a modern equivalent that has the same service potential. If an asset has to be replaced with a higher quality asset, the customer does not currently incur the extra amount

CLADs Connection location asset diagrams are technical diagrams of the entire network

CMIS The Customer Management Information System holds customer contract information

Connection charge The connection charge recovers part of Transpower's AC revenue by charging customers for the cost of providing connection assets (so they are able to connect to the national grid). The customer‟s monthly connection charge is calculated as 1/12 of the annual connection charge which is calculated by Zemindar

Customer asset allocations All connection assets are allocated to the customer or customers that use them. If only one customer utilises an asset then it will be allocated to them at 100%. If more than one customer utilises the asset to connect to the national grid, the allocation will be dependent on the usage of each of the customers

Customer operated switches A switch which is being operated by the customer or customers using it. As Transpower do not pay operating costs for these switches, customers pay a discounted operating component for them

EOC Exceptional Operating Circumstances are services provided by a customer at the request of Transpower and include for example, a request by Transpower to have more power pumped into the national grid. The charges incurred in these scenarios are overridden so the customer is not paying for providing additional services

FMIS The Financial Management Information System holds financial information on assets

GMMS The system used by EMS to store and deliver the RCPD/RCPI and kvar information to MDR

MDR Meter Data Repository is a capacity calculation system which holds metering data and TPM related aggregation business rules. It is used to calculate the capacity measurements for each customer by location to determine the correct allocation of connection assets based on usage

MMS The Maintenance Management System holds operating and maintenance cost information

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Appendix B: Glossary of terms (cont...)


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Term Our understanding

HVDC charge The High Voltage Direct Current charge recovers Transpower's HVDC revenue. The customers monthly HVDC charge is calculated for all HVDC customer at each South Island generation location. The monthly HVDC charge is 1/12 of the annual HVDC charge

Interconnection charge The interconnection charge recovers the remainder of Transpower's AC revenue. Monthly interconnection charges are paid by offtake customers for each connection location at which they have assets connected to the national grid

Market System The current Market System refers to a group of applications including the SPD model which act as the electricity wholesale market clearing engine

OVF file The Offer Volume Forecast file contains anytime maximum demand (AMD), anytime maximum injection (AMI), regional coincident peak demand (RCPD) and historical anytime maximum injection (HAMI) data and is manually uploaded into Zemindar

Retail Reconciliation System The Retail Reconciliation System allocates volumes at GXPs and GIPs to the parties purchasing or selling electricity at that node

RMT When the HVDC link is removed the system reserve requirements would change. These reserve requirements are calculated during market operation by the Reserve Management Tool

SFT The Simultaneous Feasibility Test is a model to calculate the security constrained transmission branch capabilities

SPD The Scheduling, Pricing and Dispatch model is part of the Market System which forecasts the electricity demand for the country and allocates resources to satisfy the demand

Switch Connects customers to the national grid and controls the flow of power

vSPD The vectorised Scheduling, Pricing and Dispatch model is based on the published formulation of the market clearing engine (SPD). It has been developed by the Authority and provides a simplified version of the SPD system run by Transpower

Zemindar Zemindar is the pricing engine for current transmission prices. It is used to produce annual customer rates for the connection, interconnection and HVDC

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The Authority’s proposal and alternative scenario A

For each of the proposed scenarios there are different technology options available to deliver the required functionality. The following table outlines the options available for the customer allocation system (Zemindar) and is based upon information provided by Transpower and our assessment of the changes required.

CriteriaOptions

Replace Zemindar Enhance Zemindar

Complexity of changeHigh – as a new solution will need to be procured, configured and installed into the Transpower environment

High – as the required changes are complex and extensive. Design, and development costs will be significant

Ability to meet requirementsHigh – The solution will be selected on the basis it meets the requirements of the TPM

High – as the enhancements will be developed specifically to meet the requirements

Risks/Benefits

Risks - Transpower may need to undertake an open procurement process that will extend implementation timeframes.- System replacements can be more challenging and complex to undertake

Benefits – Transpower will have a solution based upon current technologies, fully supported and meets the needs of the business

Risks – Zemindar was custom built for Transpower in 1996 and is based upon a legacy technology stack. There are no „support‟ experts for the platform. To enhance the solution, there will have to be a period of up skilling required by IST and its support partner.- It is possible compromises may have to be made due to inherent limitations in the core functionality of Zemindar

Indicative cost (including development, hardware &software)

$4.8M $3.1M

Recommendation

Preferred option for the Authority‟s and alternative scenario (A) as it will deliver a system that is supported and able to better handle future changes to the TPM

Appendix C – Options assessment for Zemindar

55

Notes

The following points apply to each of the options assessed:

1. Further due diligence will be required to confirm the options. This will only be possible once further details on the guidelines have been confirmed

2. Costs estimates may vary by +/- 50%

pwc


The following table outlines the possible options available to deliver the pricing engine functionality for the alternative scenario B.

CriteriaOptions

Replace Zemindar Enhance Zemindar

Complexity of change

Medium– The functionality required to be met by thenew solution is significantly reduced. The new solution will still have to be procured, configured and installed

Medium– The changes required for scenario B are reduced from A and the Authority‟s propsoal but the required functionality will need to be designed and developed

Ability to meet requirementsHigh – The solution will be selected on the basis it meets the requirements of the TPM

High– as the enhancements will be developed specifically to meet the requirements

Risks/Benefits

Risks - Transpower will need to undertake a procurement process that may slow down the implementation timeframes.- System replacements can be more challenging and complex to undertake

Benefits – Transpower will have a solution that is based upon current technologies, fully supported and meets the needs of the business

Risks – Zemindar was custom built for Transpower in 1996 and is based upon a legacy technology stack. There are no experts to support the platform. To enhance the solution, there will have to be a period of up skilling required by IST and its support partner

Benefits – Less complex implementation

Indicative cost $3.9M $3.1M

Recommendation

Preferred option for the Authority‟s and alternative scenario (A) as it will deliver a system that is supported and able to better handle future changes to the TPM

Appendix C – Options assessment for Zemindar (cont…)


56

pwc

The Authority’s proposal

The following table outlines the possible options available to deliver the „beneficiary pay‟ functionality for the Authority‟s proposal and is based upon information provided by Transpower and our assessment of the changes required.

Appendix D – Options assessment for Market System


57

CriteriaOptions

Scale existing Market System Setup a Market System clone Build a be-spoke solution


High - as the change will focus on scaling the existing system.

High – as a new instance of the Market System environment will need to be setup with associated inputs (such as SFT/RMT)

High – This would use vSPD as a base and focussing on productionising, integrating with required inputs and developing the counterfactual scenarios

Ability to meet requirements

High– as the existing system has access to the input systems such as SFT/RMT

High– However there will be costs to integrate the new instance with the existing input systems such as SFT/RMT

Medium– as vSPD is a approximation of the SPD system used by Transpower and it is unknown if it can be developed appropriately productionised to meet the processing requirements.

Risks/Benefits

Risks – It is unknown if the system can be scaled to achieve an additional 6720 solves-The processing will occur in the existing Market System which acts as the wholesale market clearing system thereby potentially affecting the performance of those calculations.- Transpower are undertaking an exercise to determine if critical grid systems and non critical systems should be separated. The outcome of this work may affect the suitability of this option. Benefits – reduced implementation effort as input systems are already integrated

Risks – It is unknown if the system can be scaled to achieve an additional 6720 calculations („solves‟)-Expert advice is likely to be required to implement this solution and availability of such resources may be difficult to procure.

Benefits – Processing for the TPM process is isolated from the wholesale market clearing engine

Risks – As the vSPD model is an approximation of the SPD model, this means that the charge allocation may not be accurate thereby increasing the likelihood of Transpower being challenged on charges by customers.-It is unknown if the SFT/RMT inputs can be integrated into the vSPD system

Benefits – Processing for the TPM process is isolated from the wholesale market clearing engine

Indicative cost $2.5M $3M $1.9M

Recommendation Further investigation is required to determine the appropriate solution

Notes

The following points apply to each of the options assessed for the Market System

1. Further due diligence will be required to confirm the options. This will only be possible once further details on the guidelines have been confirmed

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Alternative scenario A

The following table outlines the possible options available to deliver the Market System functionality for the alternative scenario A.

Appendix D – Options assessment for Market System (cont…)

58

CriteriaOptions



High - as the change will focus on scaling the existing system


High – Changes will focus on integrating with required inputs and counterfactual scenarios

Ability to meet requirements

High– as the existing system has access to the input systems such as SFT/RMT

High– However there will be coststo integrate the new instance with the existing input systems such as SFT/RMT

Medium– as vSPD is a approximation of the SPD system used by Transpower and it is unknown if it can take inputs from SFT/RMT

Risks/Benefits

Risks – It is unknown if the system can be scaled to achieve an additional 3360 solves and there will be additional risk as the processing will occur in the existing Market System which acts as the wholesale market clearing system- Transpower are undertaking an exercise to determine if critical grid systems and non critical systems should be separated. The outcome of this work may affect the suitability of this option.

Benefits – reduced implementation effort as input systems are already integrated

Risks – It is unknown if the system can be scaled to achieve an additional 3360 solves.- Expert advice is likely to be required to implement this solution and availability of such resources may be difficult to procure.

Benefits – A new instance of the Market System removes risk to the existing system which acts as the wholesale market clearing system

Risks – As the vSPD model is an approximation of the SPD model, this means that the charge allocation may not be accurate thereby increasing the likelihood of Transpower being challenged on charges by customers

Indicative cost $2.3M $2.8M $1.9M


pwc


The following table outlines the possible options available to deliver the Market System functionality for the alternative scenario B.

Appendix D – Options assessment for Market System (cont…)

59

CriteriaOptions [DETAILS TO BE CONFIRMED WITH TRANSPOWER]



High- as the change will focus on scaling the existing system


Medium– Changes will focus on integrating with required inputs and counterfactual scenarios

Ability to meet requirementsHigh– as the existing system has access to the input systems such as SFT/RMT

High– However there will be costs to integrate the new instance with the existing input systems such as SFT/RMT

High – as the rules for calculating the counterfactual scenarios have been simplified

Risks/Benefits

Risks – It is unknown if the system can be scaled to achieve an additional 720 solves and there will be additional risk as the processing will occur in the existing Market System which acts as the wholesale market clearing system.- Transpower are undertaking an exercise to determine if critical grid systems and non critical systems should be separated. The outcome of this work may affect the suitability of this option. Benefits – reduced implementation effort as input systems are already integrated.

Benefits – reduced implementation effort as input systems are already integrated

Risks – Expert advice is likely to be required to implement this solution and availability of such resources may be difficult to procure.

Benefits – A new instance of the Market System removes risk to the existing system which acts as the wholesale market clearing system

Risks – As the vSPD model is an approximation of the SPD model, this means that the charge allocation may not be accurate thereby increasing the likelihood of Transpower being challenged on charges by customers. This risk is reduced for this option as the rules are simplified.

Benefits – Use of vSPD removes the risk to the existing whole electricity Market System- Implementation and ongoing support cost will be reduced

Indicative cost $1.9M $2.2M $1.9M


pwc

Name Title Company

Carolyn McArthur Contracts Specialist Transpower

David Lee-Smith Planning and Reporting Manager Transpower

David Leigh Project Accountant Transpower

David Lewis Assistant Analyst Electricity Authority

Derrick Westenra Market Systems & Transmission Applications Manager Transpower

Ian Martin Metering Services Manager EMS

Jeremy Cain Chief Regulatory Advisor Transpower

Matt Tebbs Information Services & Business Applications Manager Transpower

Murray Henderson Market Services Analyst Transpower

Nigel Partridge Business Applications Analyst Transpower

Nikki Stigley Pricing Team Leader, Planning and Regulatory Transpower

Robynne Purdy Revenue Assistant Transpower

Rodrigo Nocete Regulatory Strategy Analyst Transpower

Scott Heard Head of Strategy and Architecture Transpower

Appendix E: Key stakeholders consulted


60

The following people provided information during PwC‟s review of the impact of the Transmission Pricing Methodology changes.

Documents

Understanding the impact on Transpower's systems … · Transmission Pricing Methodology –Impact Assessment Understanding the impact on Transpower's systems and processes December