What drives electricity prices? Demand? Fuel costs? Losses? Transmission constraints? Carbon costs? The cost of new generation? Inflows? Well they all have an impact to a certain degree. The time frames vary but the answer in the long run is surprising, especially given that we are currently running at over 80% renewable generation.
By Greg Sise, 3 March 2017
When we look at spot prices it is rather difficult to discern what drives electricity prices because of the volatility created by the ups and downs of inflows into the hydro lakes.
Residential and SME customers don’t typically pay spot prices: they pay prices which respond with quite a lag behind the key factors driving spot prices, and which are also influenced by the non-energy costs of electricity including line charges.
On the other hand, the largest customers and independent retailers regularly go to market for contracts which average 2.5 years in length, and the prices in this market segment respond rapidly to changes in the underlying drivers of spot prices.
Prices of large fixed-price electricity contracts make up the Energy Link fixed price contract indices: the main index includes all fixed price variable volume contracts over 1 MW in size and all standard hedge contracts (known as contracts for differences) over 0.25 MW. The main index is referenced to the Haywards node in Upper Hutt.
The prices in this market segment are driven by market participants taking positions on how they expect spot prices to evolve over time. Energy Link started calculating the index in February 2009 and before that a similar index was published by M-Co (now NZX Energy) and before that by New Zealand Tariff and Fuels, so we have an index reaching right back to August 1996.
The chart shows the electricity index (in $/MWh) and also MBIE’s annual average wholesale price of piped natural gas (also in $/MWh), along with the ratio of the electricity index to the wholesale gas prices. The gas price average is made up primarily of prices of gas sold under contract to electricity generators, Methanex (currently new Zealand’s largest consumer of natural gas), and one or two other very large gas consumers. Gas contracts tend to be long term, so the MBIE average lags behind marginal changes in the wholesale price (but it is the best data we have).
What the chart shows is that the electricity-gas ratio barely moved between 2015 and 1999. There is a period from 2001 to 2004 when the ratio shot up with rapidly rising electricity prices, caused by the first dry year price spike in 2001, followed by repricing of gas from the giant Maui field in 2003, but otherwise the ratio has remained within the narrow range between 2.5 and 3.4.
Is this a coincidence? Is it surprising?
To understand what is going on here we must look at the two major types of generation that may be “on the margin” in the electricity spot market: large hydro systems, and gas-fired thermal stations, which together make up 70% of the market. The gas-fired generators have very significant short run marginal costs which are driven by the price of natural gas. There is still some coal-fired generation at Huntly but the coal competes with gas for market share so the price of this generation tends to follow that of its gas-fired competitors.
The major hydro generators have very low short run marginal costs, but they must “shadow” the gas-fired generators in terms of the prices they offer for their output. For example, if the hydro is offered above the price of gas-fired generation then the lakes will fill up and there will be excessive spill. If the hydro is offered below the price of gas-fired generation then the lakes will empty out and there will be a shortage of electricity.
Either way, it would not be good for the market, nor for consumers. So the major hydro systems tend to “shadow” the gas-fired generators: if the price of gas goes up then the hydro has to be offered at higher prices, and vice versa.
And it just so happens that gas-fired generating stations have efficiencies ranging from 35% to 52%, with marginal stations tending to be at the lower end: which means that the prices offered by the major hydros are around three times (1/0.35) the price of the gas on average. Hey presto!
It’s not all a one-way street, however: what’s happening in the electricity market can also drive gas prices. For example, gas generation has fallen over the last few years, which reduces demand for gas. At the same time, Methanex’s increased gas consumption has offset this, but there is still potential for falling demand from the electricity generators to put downward pressure on gas prices. Furthermore, gas-fired generation competes with baseload renewable generation (wind and geothermal, for instance) which puts downward pressure on electricity prices, and hence electricity generators are working hard to find cheaper gas to remain competitive in the long term.