Responsibility for transmission planning in the National Electricity Market (NEM) is shared between:

  • the Australian Energy Market Operator (AEMO) in its role as National Transmission Planner (NTP)
  • Jurisdictional planning bodies, for each region of the NEM:
    • NSW and ACT - TransGrid
    • Queensland – Powerlink
    • South Australia – ElectraNet
    • Tasmania - Transend

Long terms strategic planning

Long-term strategic planning focusses on the need for major new investments and has a longer-term focus (e.g. more than ten years).

Long-term strategic planning is undertaken by AEMO in its role as NTP and includes the development of the National Transmission Network Development Plan (NTNDP), which provides a holistic, strategic vision of the transmission network over the next 20 years. It focuses on national transmission flow paths (i.e. those areas of the transmission network connecting major generation or demand centres). Planning is undertaken over a number of different scenarios, covering different economic and government policy outcomes, demand forecasts and also generation scenarios

The NTP also publishes the:

Short term planning

Short-term planning focuses more on the near-term, and is driven by specific investment needs. Short-term planning is undertaken by the jurisdictional planning bodies, who produce Annual Planning Reports (APRs) which:

  • draw upon the high-level strategic plan (NTNDP), but detail more specific investment needs and drivers
  • contain details of potential network investments, given forecast loads
  • under the National Electricity Rules (NER)
    • must cover at least the next 10 years, but there is typically an emphasis on the next 2-3 years
    • for demand must include
    • for constraints must include information relating to constraints in their network, and associated network developments
    • for proposed network agreements:
      • for all proposed augmentations must include:
        • brief description of project
        • reason for augmentation
        • proposed solution
        • total cost of solution
        • how it relates to the NTNDP.
      • for all replacement expenditure must include
        • brief description of project
        • date it will become operational
        • purpose of asset
        • total cost of assets.

Project specific planning and investment decision-making

Project specific planning relates to a particular investment need, and culminates in a particular investment decision.

In some other markets project specific planning is undertaken as part of the development of the short-term plans. However, in the NEM there is a separate and distinct process for individual investment decisions, specifically the application of either the:

  • Regulatory Investment Test for Transmission (RIT-T) – this is applied for all investments greater than $5m in value
  • Non RIT-T assessments – all other assets (e.g. $5m or less in value) must be planned in least cost over the life of the investment

In these processes, a detailed cost-benefit assessment is undertaken to identify the investment option that has the highest net benefits

Based on these assessments the TNSP then makes the investment decision.

Regulatory Investment Test for Transmission

Under the NER, the Australian Energy Regulator (AER) must publish the RIT-T. The AER must also develop and publish RIT-T application guidelines, to provide guidance on the operation and application of the RIT-T .

The purpose of the RIT-T is to identify the transmission investment option, which maximises net economic benefits and, where applicable, meets the relevant jurisdictional or NER based reliability standards.

TNSPs:

  • must plan and develop their network to meet reliability standards (i.e. minimise costs)
  • can also undertake investment where that investment would result in a net market benefit, but are not necessarily to meet a specific reliability requirement.

Investments to meet the RIT-T must maximise the Net Market Benefit.

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National framework for distribution network planning and expansion

The national framework establishes a nationally consistent annual planning and reporting cycle and project assessment process. It consists of:

  1. Distribution network annual planning and reporting process:
    1. Distribution annual planning review
    2. Distribution annual planning report (DAPR)
  2. Demand side engagement obligations
  3. Distribution investment project assessment process:
    1. Regulatory investment test for distribution (RIT-D)
    2. Dispute resolution process

Distribution annual planning review

Each DNSP is required to undertake an annual planning process covering a minimum forward planning period of five years for its distribution assets (and ten years for dual function assets).

The forward, minimum five year, period commences on a date deemed appropriate by each DNSP.

The planning process applies to distribution network assets and activities undertaken by DNSPs that would be expected to have a material impact on the distribution network in the forward planning period.

In carrying out the planning process, DNSPs are, at a minimum, required to:

  • prepare forecasts of maximum demands for the relevant network assets;
  • identify (based on those forecasts) system limitations; and
  • take into account non-network options when considering investment options.

Distribution annual planning report

DNSPs must publish a Distribution annual planning report (DAPR) setting out the results of the distribution annual planning review for the forward planning period. DNSPs must publish their DAPR by the date specified in jurisdictional electricity legislation or, if no such date is specified, by 31 December. The DAPR must include the information specified in the NER (schedule 5.8 ) .

Demand side engagement obligations

DNSPs must develop a demand side engagement strategy which sets out the strategy for engaging with non-network providers and considering non-network options for addressing system limitations.

DNSPs must document their demand side engagement strategy in a demand side engagement document which

  • has content requirements specified in NER (schedule 5.9)
  • is published by no later than 31 August 2013
  • is reviewed and revised at least once every three years.

DNSPs must establish and maintain a demand side engagement facility by which parties can register their interest in being notified of developments related to distribution network planning and expansion .

Regulatory investment test for distribution

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The regulatory investment test for distribution (RIT-D) has two key components:

  1. A cost benefit test
  2. Procedures (project assessment process) which includes
    • project specification
      • exempt projects
      • cost threshold assessment (>$5m).
    • screening for non-network options.

The non-networks options report consultation includes:

  • application of the RIT-D which includes a:
    • draft project assessment report consultation
    • final project assessment report.

The RIT-D establishes the processes and criteria to be applied by DNSPs in order to identify investment options which best address the needs of the network. It is applicable in circumstances where a network problem exists and the estimated capital cost of the most expensive potential credible option to address the identified need is more than $5 million.

Certain types of projects and expenditure are exempt from the RIT-D, including projects initiated to address urgent and unforeseen network issues.

In summary, the RIT-D requires DNSPs to assess the costs and, where appropriate, the benefits of each credible investment option to address a specific network problem to identify the option which maximises net market benefits (or minimises costs where the investment is required to meet reliability standards).

Under the RIT-D, the quantification of market benefits is optional. The NER states that a DNSP may quantify each class of market benefits where it considers that:

  • any applicable market benefits may be material; or
  • the quantification of market benefits may alter the selection of the preferred option.

However, where a project is not driven by reliability corrective action, a DNSP would need to quantify both the applicable costs and market benefits in order for the preferred option to have a positive net market benefit.

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Dispute resolution process

The National Electricity Rules include a dispute resolution process that is open to all projects subject to the RIT-D.

Relevant parties are able to raise disputes with the AER in relation to the conclusions made by the RIT-D proponent in a final project assessment report, on the grounds that:

  • the RIT-D proponent has not applied the RIT-D in accordance with the Rules; or
  • there was a manifest error in the calculations performed by the DNSP in applying the RIT-D.

The AER may then either reject a dispute, or make a determination on the dispute, and the timeframes for doing so will depend on the complexity of the dispute.

The AER may only make a determination which directs a DNSP to amend its final project assessment report where the DNSP has not correctly applied the RIT-D in accordance with the rules, or where the DNSP has made a manifest error in its calculations.

Joint planning arrangements

DNSPs are required to undertake joint planning with the owners of any connected networks where there are issues affecting multiple networks. DNSP-DNSP joint planning obligations are less prescriptive than the equivalent arrangements for TNSP-DNSP joint planning.

Under DNSP-DNSP joint planning, DNSPs must carry out the requirements of the RIT-D for projects identified under the joint planning process.

Under DNSP-TNSP joint planning, the relevant NSPs must carry out the requirements of the RIT-T for projects identified under the joint planning process. The RIT-T requires a broader range of market benefits be assessed thus ensuring any applicable market benefits are appropriately considered.

However, there is some flexibility for the RIT-D to be carried out where none of the potential options to address the network issue include a transmission component with an estimated capital cost greater than $5 million (RIT-T cost threshold level).

In these instances, opportunities for the delivery of material market benefits is likely to be limited.