Chief Strategy Officer / Australia
A pipeline life, a storage tank and a battery sale
- Company revenue
- A$462m
- Year to June 2026; transmission and storage
- Gas transmission pipelines
- 1,140 km
- Four pipelines in Victoria, South Australia and southern New South Wales
- Gas carried in 2025–26
- 118 PJ
- Down from 141 PJ in 2019–20
Decisions & consequences
01Renewing the western pipeline on a 2042 life instead of 2060
In 2023, foundation contracts covering 62 per cent of our western pipeline's capacity were due to expire in June 2024. The 412-kilometre line supplies two regional cities, several industrial sites and two gas-fired peaking stations. Its tariffs had been set on the assumption that customers would keep using it until about 2060. My team expected residential load along the line to keep falling by three to four per cent a year, and both peaking stations' offtake contracts ended in the late 2030s. Renewing on the old basis risked leaving several hundred million dollars unrecovered when the last customers left.
I recommended renewal terms that recovered the remaining capital by 2042. For a ten-year contract that meant a tariff about 14 per cent higher; shorter contracts carried a higher rate. Our general manager of commercial preferred to hold price and protect volume. The largest retailer customer argued that we were asking current users to pay for a decline they had not caused, and one investor-appointed director worried that a published shorter life would unsettle lenders. Those were reasonable objections. I accepted that we would lose some load and that reported profit would fall as depreciation rose.
We explained the methodology to every customer before negotiations began, offered a lower rate for commitments extending beyond 2034 and briefed the lenders ourselves. Renewals covered 88 per cent of the expiring capacity at an average term of seven and a half years. One food manufacturer cut its contracted capacity from nine terajoules a day to four as it brought forward a move to electric boilers, removing about A$5.1 million of annual revenue. Net annual revenue on the line still rose by A$11.4 million, while depreciation increased by A$19 million a year.
Every Corrandale pipeline now has a stated economic-life case that the board reviews annually. Next time I would begin the conversation fourteen months earlier and include the regional councils, who heard about the change from a customer before they heard it from us.
Waiting nine months to contract a second storage tank before building it
By 2024, AEMO's gas outlooks were warning that southern states could face shortfalls on peak winter days later in the decade. Our LNG storage facility in western Victoria, which can send out up to 120 terajoules a day, was fully contracted each winter. Engineering had a design for a second tank that would roughly double the stored volume at an estimated cost of A$268 million. Our chief executive and one shareholder wanted an investment decision in time for first service in winter 2027.
I recommended that we first contract at least 65 per cent of the new capacity under winter-reservation agreements of eight years or more. A market-wide warning is not a customer's commitment, and a storage tank has few other uses if a shortage is resolved by other means, such as new supply or import terminals. The chief executive argued that waiting would cost us the 2027 winter and invite a competing project. She was right on the first point. Our lenders, however, would not provide project debt against uncontracted capacity, which clarified the choice for both shareholders.
The commercial team spent nine months negotiating with retailers and generators. One retailer took capacity elsewhere rather than accept a ten-winter term. By August 2025 we had contracted 71 per cent of the capacity with three retailers and the owner of a gas-fired peaking station, and the board approved the project. The delay raised the estimate to A$291 million through construction escalation, and first service moved to winter 2028. Lenders provided A$200 million of project debt against the contracted revenue.
The tank is under construction and on schedule as I write, so I do not yet claim its returns. What changed is that Corrandale no longer treats an adequacy warning as a demand forecast. I would run the contracting work alongside the engineering design next time, rather than after it, which might have recovered most of those nine months and part of the escalation.
Selling our battery project after its transmission upgrade slipped three years
In 2022 Corrandale began developing a 250-megawatt, four-hour battery on freehold land beside one of our compressor stations in western Victoria. It was our first electricity project, and it mattered to the company's belief that it had a future beyond gas. By 2025 we had spent A$9.6 million on studies, approvals and a connection application, and had signed an agreement with neighbouring landholders that included a A$150,000 annual community fund once the battery operated. The connection relied on a planned regional transmission upgrade. That year its expected completion moved from 2027 to 2030.
I reviewed three options with the project team: hold our place in the connection process and wait, seek a much smaller connection on the existing line, or sell the project to a specialist developer whose portfolio could absorb the delay. Our head of new energy, who had built the project, wanted to wait; he believed the upgrade would eventually arrive and the battery would be valuable. I recommended selling. Corrandale had no other electricity assets to share the overheads, our shareholders had not invested for a five-year development hold and the smaller connection would have made the project uneconomic.
We required the buyer to assume the neighbour agreement and the community fund in full, which reduced the price we were offered. The sale in late 2025 brought A$6.1 million upfront and A$4 million payable when the battery connects, and we booked a A$3.5 million loss. Corrandale retained a land lease worth about A$600,000 a year. Four of the six project staff moved into pipeline and storage roles; two joined the buyer.
We now commit development money to an electricity project only after its connection pathway, including the transmission works it relies on, has been tested. I would also have held community consultation until that test was complete. We asked neighbours to engage with a timetable we could not support, and several of them told me so directly.