  \linebreak \begin{flushright}
   \it{... and so, if gas is critical for industrial recovery, why waste it heating houses?}
     \end {flushright}

“Over half of Australians still rely on gas as a source of energy, but few realise that there’s a more cost-effective, energy-efficient option – heat pumps” AGL

With traditional east coast gas reserves in decline¹, industry and government argue new gas supply from the likes of Narrabri² or import terminals is essential for post-COVID industrial recovery. Lead-times on new production mean addressing allocation is likely to secure more supply in the short-term. As much is recognized in the federal government’s ADGSM³, which delivers about ~200 TJ/day each year. Here we address the broader issue of allocation by asking to what extent can non-critical fuel switching - gas to electricity - help alleviate supply issues? Despite the ADGSM, LNG exports have seen a substantial diversion of Queensland CSG production away from domestic markets. We argue that fuel switching together with reservation of a small fraction of CSG production, in line with pre-2015 levels, can substantially alleviate critical industrial gas supply issues with significant additional benefits. We provide two policy prescriptions

Figure 1: East Coast gas production by region

PP 1. Switch ~50% of the current Victorian domestic and commercial gas heating demand to elecricity delivering an additional ~180 TJ/day above 2019 levels to domestic markets

PP 2. Reserve a minimum 550 TJ/day from Queensland CSG production delivering an additional 170 TJ/day above 2019 levels to domestic markets

Together, PP1 and PP2 more than compensate the looming 330 TJ/day Victorian committed supply deficit¹ with each contributing almost as much as Narrabri. We note that fuel switching is implicit in our Paris commitments, and is an obligation.

how is east coast gas currently allocated?

Figure 2: East Coast gas production by region less allocations to the Curtis Island Demand zone used for LNG export.

In 2019, total east coast gas production averaged ~5180 TJ/day of which 9.745^{4} TJ/day was allocated to LNG exports (1880%) and about -9.381^{4} TJ/day (-1810%) to LNG processing at Curtis Island, leaving a balance of about 1550 TJ/day (30%) for the domestic market. CSG production in Queensland accounted for 77% of total production (~4010 TJ/day), of which 9% (~380 TJ/day) was allocated to the domestic market. This compares to the average of 550 TJ/day from CSG in the period 2010-2013, prior to the first LNG exports in 2015. In effect, notwithstanding the impact of the ADGSM, some 180 TJ/day has been diverted from Queensland domestic supply to LNG export. Of the domestic allocation industry uses ~45%, domestic and commercial heating ~32%, power generation ~23%. In Victoria, 55% of demand is for domestic and commercial heating, 30% for industry and 15% for power.

Figure 3: Victorian gas production showing strong seasonality averaging about 910 TJ/day.

alternatives to new supply?

We consider two alternatives to new supply: fuel-switching of domestic heating loads and reservation. With efficient electrical heat-pump alternatives such as reverse cycle air-conditioners now widely available, fuel switching of heating loads is now plausible. Fuel switching of ~50% of Victorian gas heating demand saves about 180 TJ/day. Reserving CSG production at the 2010-2013 average delivers an additional 170 TJ/day to domestic markets equivalent to an additional 5% of export demand. Gas use in LNG processing can be substantially electrified and therefore contribute materially to the domestic market supply balance. At ~80 TJ/day, electrifying 25% of LNG processing demand would contribute about half the additional required PP2 CSG reservation.

Figure 4: Victorian gas allocation to domestic and commercial sectors mainly for heating.

where would the additional energy come from?

Switching 50% of the Victorian gas heating load to heat pumps, adds about 2.0 GW to Victorian peak winter power demand⁵, with the total annual demand requirement equivalent to the output of about 1.5 GW of installed wind power assuming a capacity factor of 35%.

with added benefits

for households, the possibility of just one connection fee instead of two saving around $350/year
for gas transmission, mitigation of looming winter peak day adequacy issues⁶
for electricity consumers, a more productive power grid (~6% higher utilisation) with reduced unit costs, and reduced incentives for gaming by market participants through practices such as shadowing gas prices⁷
for investors, further incentives for renewable power generation
for Australians, time for the hydrogen/alternative economy to arrive without costly supply-side investments and their associated risks

2019 gas allocation and supply data

total east coast gas demand, excluding LNG ~1550 TJ/day
Queensland CSG production ~4010 TJ/day
Victorian gas production ~910 TJ/day
total east coast industrial gas demand, excluding LNG ~720 TJ/day
Victorian domestic and commercial gas heating ~360 TJ/day
LNG exports ~9.745^{4} TJ/day
LNG processing ~-9.381^{4} TJ/day

Figure 5: Wholesale electricity prices doubled as LNG exports increased across 2016, adding 14 billion to the traded value substantially due to the practice of shadowing the gas price.

On the gas fired recovery

how is east coast gas currently allocated?

alternatives to new supply?

where would the additional energy come from?

with added benefits

2019 gas allocation and supply data

Footnotes