About Generation Offers and Dispatch

The information below is provided to new participants wishing to offer into New Zealand’s electricity market. Contact the Market Operations team at [email protected] if you have specific questions.

Offer Systems

Generators above 10 MW in capacity are required to submit Code-compliant offers of their generation. Offers are made to the System Operator via the Wholesale Information Trading System (WITS). WITS is hosted by NZX. You can read more information on the Electricity Authority's webpage, including for how to gain access.

You can make generation offers using an offer system, or a third party can make offers on your behalf. 

• If offering by yourself, many will upload files using systems known as Electricity and Load Market Offer (ELMO) or Zero-priced Offer of Electricity (ZOE). We can suggest others to help you, if required.
• If offering via a third party, you will need to do the commercial arrangements with them.

Dispatch Systems

To receive and acknowledge dispatch requests from the System Operator, you need to set up a dispatch system, as signalled as part of our Operational Data Integration workstream. There are two options, both of which receive the same instructions from the market system. Receiving dispatch via Inter-control Centre Communications Protocol (ICCP) is useful where operational data exchange is part of day-to-day power system operations, whereas Web Services functions without deep operational integration. 

As with offers, you may either manage dispatch yourself using a dispatch system you will need to build, test and commission, or you can arrange for a third party to receive dispatch on your behalf. 

• If receiving dispatch yourself, we can provide some documentation to assist (see the dispatch documents below for a start). 
• If receiving dispatch via a third party, you will need to do the commercial arrangements with the third party and set up data exchange with them. Please note that data exchange testing between the System Operator and your dispatch system needs to be successfully completed at least 4 weeks prior to first electrically connecting to the power system.

Here are some more points to consider when making the choice of dispatch system:

Essential Dispatch Documents

Dispatch 101: Key Information for Generation Asset Owners

Read through the information under the headings below to familiarise yourself with the essential facts about how generation offers function.

Electricity Market

The System Operator schedules and dispatches generation based on the bids and offers made by purchasers and generators. Generators offer electricity into the electricity market. Purchasers bid for electricity. 

Pricing

The New Zealand wholesale market is designed to dispatch generation based on bids and offers with locational marginal pricing (nodal pricing). This method allows the market to arrive at the overall lowest cost dispatch solution. For this purpose, the market also co-optimises the cost of energy dispatch with the cost and quantity of reserve needed to cover the loss of generation or HVDC transfer.

The market settles on an ex-post basis with 30 minute trading periods and a price for each of the over 200 nodes in the market model. Generators are paid for the output produced in a trading period, at the final price for the trading period, at the node to which they are connected. Dispatch occurs every five minutes through formal dispatch instructions sent electronically. 

Generation Offers

All generation offered under the trading rules in Part 13 of the Code is dispatched through the offer process in real time. There is no provision for dispatch rights based on any bilateral arrangement or hedge arrangements between generators and retailers.

All generation over 10 MW–if directly grid-connected or embedded within a distribution network–must offer. The Electricity Authority may require embedded generation below 10 MW to provide intended output data if the Authority agrees this will assist the System Operator in meeting its principal performance objective (PPO).

Different dispatch rules exist for intermittent (wind and solar) generation and certain types of co-generation plant, reflecting the characteristics of these generators.  Participants can change their offer up to ‘gate closure’ (the point at which changes to offers can no longer be made for commercial reasons. For most generation, this is currently 1 hour ahead of dispatch beginning for the applicable trading periods. See clause 13.17 of Part 13 of the Code). Several schedules are provided to participants up to a week in advance, giving an indication of the likely dispatch quantities and prices.

There is currently no binding ahead or unit commitment market as in some overseas jurisdiction.

No Right of Capacity

A connection to the power system does not result in any capacity rights for that connected party. Generators connecting to the Grid should be aware that existing or future congestion on the Grid may affect the ability of a generator to deliver its energy to the market. 

No Right of Dispatch

Connection to the power system and participation in the electricity market does not guarantee that the System Operator will dispatch a generator at all. A generator may not be dispatched where:

• there is sufficient lower priced generation to meet demand (see below); or
• there are constraints on the power system that limit the amount of electricity that the generating unit can produce (see below); or
• the generator is non-compliant with the AOPOs and Technical Codes.

Sufficient Lower Priced Generation

Dispatch is based on offer price. A generating plant may not be dispatched if there is sufficient lower priced generation offered to meet system demand.

At times, clearing prices may drop to close to zero if there is a surplus of generation that wants to run irrespective of the clearing price. This typically happens at times of low system demand–overnight in summer, and at other times when there is a very high proportion of hydro generation relative to total system demand due to full storage catchments and strong inflows.

Negative priced offers are not allowed; however, there is a Must Run Dispatch Auction (MRDA) where generators can bid for rights to offer at $0.00 per MWh. The quantity of generation that can be cleared in this auction is limited to 80% of the minimum system demand. All other generation must offer at $0.01 per MWh or above.

Rules for the dispatch of intermittent (wind and solar) generation and type B co-generation plant effectively see them dispatched to their current output. However, due to the offer price, system constraints or times of excess generation, intermittent generation may need to “spill” in the same way that can happen with hydro generation at times. 

Holding rights to offer at $0.00 per MWh from the MRDA does not guarantee dispatch. Reserve co-optimisation or constraints could result in dispatch being less than the quantity offered at times, particularly during periods of low demand. In some cases, this may put thermal generating units below minimum running limits, requiring the plant operators to disconnect the generating unit.

Constraints on the Power System

Transmission constraints on the Grid may also affect generation dispatch. The System Operator analyses generation schedule information to identify when and where a constraint may have to be applied to ensure the power system remains within capability. The market system will bring on higher cost generation within a constrained region once a constraint limit is reached.

Details of the permanent transmission constraints applied by the System Operator are available on this webpage.

Ancillary Services Cost Allocation

The costs of procuring of ancillary services are allocated to participants as set out in Clauses 8.55 to 8.70 of Part 8 (Common quality) of the Code.

Some ancillary services costs are allocated to generators:

• The availability costs of instantaneous reserves for a trading period are allocated to generators when their generating unit's output is above 60 MW.
• An event charge is payable by generators if their assets cause an under-frequency event.
• Non-compliant generators with dispensations are allocated a share of reserve costs related to their non-compliance.

Generation plants with certain capability may also be able to be offered or tendered to provide ancillary services. Please see our Ancillary Services webpage for further information.

Co-optimisation of Energy and Reserve

The New Zealand power system currently has single generating units of up to 380 MW output dispatched. Single generating units or multiple generators on a single connection can be constrained back at times due to the co-optimisation of reserve in the market model.

In determining the least cost solution for each 30 minute trading period, the market system co-optimises the cost and quantity of instantaneous reserve (reserve) needed to cover either the loss of the largest generating unit connected, or group of generators on a single connection, or at-risk HDVC transfer at that time.  Where the cost of the reserve to cover the loss of either of these three cases is more than dispatching energy from other generators, the market system will dispatch the largest generating unit, or group of generators on a single connection (or adjust the HVDC transfer by re-dispatching generation in one island to the other) below where it might otherwise clear based on its offer price alone. 

Reserve is offered through the market in a similar way to energy offers. Reserve is offered as generator response or interruptible load. There can be times where reserve prices are as high as, or higher than, energy offers. There are also times when there is insufficient reserve to cover the full output of the largest generating unit or at-risk HVDC transfer. In such situations, the System Operator may constrain back large generating units, at-risk HVDC transfer or a group of generators on a single connection.

Common situations where generation unit dispatch can be constrained by reserves include:

• when reserve prices may be high relative to energy prices; and
• times where prices are low and close to zero. 

In some situations (i.e. low load), reserve co-optimisation has resulted in large generators being dispatched below minimum running levels and having to disconnect.