Keep an eye on the gas main

Despite the environmentalist chorus, the single most important issue for east coast power supply in the next 10 to 15 years is how much gas will be available for domestic use and what it will cost.

Read the media, and especially the energy-related electronic media, and you are told over and over again about the importance of wind farms, rooftop solar arrays and large-scale solar generation.

In real life, however, what matters is not the power supply system some people would like to have, but the one we've got and how it will change in a decade or so.

The one we've got is certainly in continuous change, reflecting both patterns of demand and moves by policymakers, but most of the flags it is flying at the moment signal a greater role for gas, which in turn has implications for end-user costs.

As an example of how the east coast market changes, take two financial years, using the Energy Supply Association yearbook for the data.

In 2010-11 (the latest available data), demand, responding to both the bruised economy and a number of factors impacting on households, was lower than in 2008-09.

As a result electricity sent out by power stations on the east coast in 2008-09 was 211.7 terawatt hours versus 208.4 TWh in 2010-11.

There was a fairly strong change in the mix of supply, however.

In 2008-09 brown and black coal generators held 84 per cent of the east coast market, with gas back at 9 per cent, hydro-electric power at 5.4 per cent and wind at 1.3 per cent.

In 2010-11, the coal contribution fell back to 79 per cent.

Gas fell back, too, being just 8.2 per cent.

Boosted by the change in the weather, hydro power was able to deliver 7.6 per cent and wind, pushed by the requirements of the RET, rose to 2.5 per cent.

But what the 2020 generation mix will be – and where demand for electricity will stand – is all conjecture at the moment, coloured by what more than a few want to see.

There are numerous factors at work.

What will happen to the economy and to manufacturing in particular? Factories account for 28 per cent of electricity demand.

What will happen to household electricity bills? (I think they will more or less double by 2020.) And how will users react? Homes account for another 26 per cent of power consumption.

Will any of the brown coal plants be closed as a result of federal government contracts to promote abatement?

Will the current renewable energy target, which requires 20 per cent of power use to be green (and mainly, in reality, to be produced by wind farms), be met? There are contrary gusts of rhetoric on this issue at present.

Just how much extra power capacity will the Queensland resource development program (LNG trains and new coal mines) require? Almost certainly, most of it will be gas-fired.

How will New South Wales resolve its impending "energy crisis” – so described by the state energy minister – as existing gas contracts from Victoria and South Australia expire just after mid-decade?

What will east coast gas prices be as the LNG trains "hoover up” resources, to use AGL Energy's Michael Fraser's term?

When will the shale gas resources of the Cooper Basin and other areas be commercially available and what will its arrival do to east coast prices?

The Energy Supply Association sees two key things:

First, it forecasts that energy sent out by east coast power stations in 2020-21 will be 18.4 per cent higher than what it expects for the current (2012-13) financial year, driven by a more than 35 per cent leap in production in Queensland.

Second, it sees a big jump in the use of gas for generation.

Here the ESAA outlook covers the whole country. It sees national requirements rising from 343 PJ in 2010-11 to 558 PJ in 2020-21.

Pull out the usage in the West and the Northern Territory, and I estimate that the association is forecasting a rise of about 64 per cent in power station use of gas on the east coast.

This is the equivalent of adding another New South Wales, at today's consumption in the state by 1.1 million businesses and households, to the east coast market.

What now comes sharply in to focus is the price of gas.

To illustrate the impact it can have, consider the forecasts published by the Bureau of Resources & Energy Economics back in December (modelling that is being redone at present to help the federal government finalise the energy white paper, which rumour has it will be further delayed in publication beyond mid-September).

BREE's December outlook saw generation produced on the east coast in 2019-20 at 271 TWh, rather higher than the later ESAA perspective, which is 248 TWh.

Were gas prices to go through the roof we could, according to BREE, expect both a 7 per cent in cut demand (it looks nationally) and a 39 per cent reduction is the use of gas by generators, with the power sales gains going to black and brown coal plants rather than wind farms.

What gas costs is not just an issue for power station owners, of course.

According to ESAA, direct use of gas by householders is doing the opposite to their electricity consumption: between 2008-09 and 2010-11 residential demand rose from 129 PJ to 145 PJ and the association sees it standing at 156 PJ at the end of the decade.

The wholesale price of gas accounts for about 26 per cent of the household bill, with network costs at 53 per cent and retail services accounting for 15 per cent. If the wholesale price doubles, which some analysts are predicting for the east coast, the average customer price goes up by about 40 per cent.

All of this is above and beyond the carbon price – and, as has been pointed out recently, the tax-on-a-tax effect of the GST.

The big point is that you can have an arm-waving discussion about solar power or the alleged health effects of wind farms if you like, but the main energy game right now is the gas business.

There's another ESAA yearbook stat that highlights this: it reports that investors have 22,915 MW of gas plant capacity development under consideration for the east coast, 75 per cent of it located in Queensland and NSW.

For context, this is the current grid-connected generation capacity in Victoria and Queensland put together.

The cost of these projects would be about $35 billion.

All of them won't be built in any time frame we need to consider, but their existence on the planning table tells its own story.