Submitted on March 12, 2021

 By Greg Sise, posted by Claudia McHerron, 15th March 2021 


A question came up recently from someone that subscribes to our free newsletters:  how do we sell our generation into the electricity market?  As this is a question that comes up often, it’s a good opportunity to provide some guidance in a post.


The answer to this question depends to an extent on the scale of the generation, because there is a big difference between how you would sell electricity generated by a 3 kW solar panel sitting on your house’s roof, and a 300 MW solar farm sitting on some marginal land in the central North Island:  they are different in size by a factor of 100,000.


The answer also depends on whether the generation is grid-connected.  We distinguish two types of connection for generation.  The first type is grid-connected, which means that it connects directly to Transpower’s transmission grid, which runs the length of the country.


Also connected to Transpower’s grid are local networks, such as the Vector network that connects consumers in Auckland.  Smaller generators tend to be connected to these local networks, so are not grid-connected:  we refer to them as ‘embedded generators’ (EGs) because they are embedded in a local network.  EGs often also get called distributed generators or DGs.


However, there is a common set of market requirements that govern the connection of generators, large or small, embedded or grid-connected, and that is that it must all be sold into the spot market.


With one exception, which occurs when a generator is on a consumer’s site, and when it generates, its output does not make it beyond the site.  Put another way, the energy it generates never makes it onto the local network, or if grid-connected, onto the grid.  A common example are the solar panels on rooftops. 


But even small-scale solar installations can send power back in the local network (we say they ‘inject’ power onto the local network).  In this case, the consumer who has the solar panels on their roof or beside their industrial facility, usually has an electricity retailer from whom they buy electricity when their solar panels don’t produce enough electricity for their needs, e.g. at night. 



In this case, their retailer usually buys the injected electricity back at a price, and then sells this electricity into the spot market, receiving whatever the spot price happens to be at the time. 


Large commercial and industrial consumers also typically receive payments from their electricity retailers.  But, when an EG gets larger, there are more alternatives to consider. 


As an example, let’s suppose that we plan to build a 60 MW windfarm (that’s between 15 and 20 wind turbines based on turbines currently common in New Zealand) on a site leased from rural a landowner.  We first need to talk to the lines company that owns the local network about the details of our connection not the local network: let’s suppose we build a short power line to connect the windfarm to the local network.  Our windfarm also needs an electricity meter which measures the generation, and hence the amount of electricity that we are going to sell. The metering has to record the total energy generated by half hour so that it matches up with the spot market, which trades every half hour (“48 x 7”).



Our options for selling the windfarm’s output are to sell direct into the spot market, or to sell to a company that is already a spot market participant (SMP) as either a generator or retailer or both (called a gentailer).


If we sell direct, then we have to become a generator class SMP and comply with the rules of the spot market, which are many and varied, and include having to make ‘offers’ to generate for every half hour.  An offer consists of up to five pairs of offers bands which tell the spot market how much you are prepared to generate at any particular price. Suppose in a particular half hour that you forecast being able to generate 45 MW, so you might offer the first 30 MW at a price of $1/MWh (0.1 c/kWh), then another 10 MW at $15/MWh, another 5 MW at ($20/MWh).  Then you have to be prepared and able to respond to ‘dispatch’ instructions from the spot market operator (known as the System Operator, and currently a service provided by Transpower).  You might get dispatched for 35 MW, so you have to comply with instruction to the best of your ability.  As a windfarm, you do have some leeway on compliance because you can’t forecast your windfarm’s output perfectly, and this leeway is currently 30 MW.


But let’s suppose you can generate the 35 MW.  Based on your offers, this put you on your second offer band with a price of $15/MWh, and so you expect to be paid at least $15 for every MWh you produce during this particular half hour.  You might be paid more if the spot price turns out a little higher, but you won’t be paid less.


This may sound complicated, but most windfarms offer $0.01/MWh for all of their forecast output, which means they are very likely to always get dispatched for their forecast output.


However, there is another complication.  When it comes to month end, the spot market works out how much your windfarm generated in every half hour of the month, and applies the half hourly spot price to work out how much you will get paid.  The catch is, that these calculations are based on what you sold to the spot market at the point of connection of the local network to transmission grid, not on what the meter at your windfarm recorded.


So at the start of each month, all SMPs have to perform a reconciliation of the generation and purchases from the spot market, the latter if you are an electricity retailer or a large consumers that buys directly from the spot market.  In your case, you do this by taking the reading on your windfarm’s meter and multiplying it by the loss factor that applies to your windfarm in your local network:  these are published by the local lines company.


For example, suppose your windfarm connects to the local network over quite a long power line, which has significant electrical losses.  This means that what arrives at the local network is less than what shows on the meter at your windfarm.  The local lines company works out the losses, and gives you a ‘loss factor’ that you apply to the metered generation.  If that loss factor is 0.98, for example, and your metered recorded 17.5 MWh for a half hour (that would be an average of 35 MW for the half hour) then you would submit 0.98 x 17.5 = 17.15 MWh to the spot market as your generation for that half hour.


If the spot price was $50/MWh in that half hour, your revenue for the half hour would be $50 x 17.15 = $857.50/MWh.


As an SMP, you will also have to pay market levies to the Electricity Authority, which is responsible for governance and operation of the spot market, and the SMP is likely to charge you the costs of their services in respect of the interface to the spot market, which usually amounts to a few $/MWh.


That’s quite a complex process, which many EGs don’t want to have to bother with, so they often prefer to contract with a company that is already an SMP.  The SMP contracts with you to buy the output of your windfarm at the meter, or close to it, and pay you the spot market revenue, as calculated above taking into account the local losses.


EGs also hear bad stores about how spot prices move around a lot:  these stores are completely true!  If you’re selling into the spot market, even if the spot prices on average pay all the costs of your windfarm, you can have months or years in a row when prices are low (full hydro lakes, for example) and months or years in a row when prices are high (low hydro lakes, fuel shortages, for example).  The average price over a long period of time may work out just fine, but you have to ask yourself the question:  can I survive a long period when spot prices are low and I can’t recover all of my costs?


As a result, EGs more often than not want the SMP that manages the interface to the spot market to buy all of their output at a fixed price, regardless of the actual generation any given period.  This type of arrangement is known as a ‘Fixed Price Variable Volume’ (FPVV) contract or a Power Purchase Agreement (PPA).


‘Nirvana’ for an EG is to sell all their generation to an SMP on a PPA with a nice high price, and a small fee for the market interface service, on a long-term contract (10 years or more).  This type of arrangement is an attractive proposition to take to lenders if you need to raise debt to finance the construction of your EG.


Finding such a PPA can be a challenge, and is a topic for another day.