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    Victoria heads for gas shortage [NGW Magazine]


The state government has lifted its ban on conventional onshore natural gas exploration, but it seems like the move is too little, too late. [NGW Magazine Volume 5, Issue 8]

by: Andrew Kemp

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Victoria heads for gas shortage [NGW Magazine]

Australia’s Victoria State is set to experience a natural gas supply shortfall within the next five years, despite the local government’s newly announced plans to reopen conventional onshore gas exploration.

The state leadership has bowed to scientific research showing that Victoria has conventional gas resources that can be extracted with minimal risk to the environment. However, new projections by the Australian Energy Market Operator (Aemo) have poured cold water over hopes that the state’s onshore can make a meaningful contribution to production in the coming years.

With Victoria’s producing gas fields in decline, and new onshore developments unlikely to come online before 2023, Aemo has forecast the state will begin experiencing supply deficits from 2024.

Lifting the ban

Victoria’s Labor government announced on March 16 that it intended to introduce two bills to parliament: one to allow a restart of onshore conventional gas exploration from July 1, 2021 and the other to amend the state constitution to enshrine a permanent ban on hydraulic fracturing and coal-bed methane (CBM) exploration.

The Liberal-National Coalition government imposed a moratorium on new CBM licences and fracking approvals in August 2012, before widening this to include conventional exploration in June 2014. When the Labor Party came to power in December 2014 it extended the moratorium.

Commenting on the lifting of the ban, state premier Daniel Andrews said: “We’re backing the science to create jobs, boost energy supply and support regional communities across the state.”

Andrews was referring to the three-year investigation by the Victorian Gas Program (VGP), which found that there were no conventional onshore development scenarios that demonstrated a “material impact on ground and surface water quality or quantity.”

The VGP’s report estimated that the state’s onshore prospective resource amounted to 128-830 petajoules (3.33-21.62bn m³), with a median (P50) estimate of 547 PJ. The VGP said the western, central and eastern areas of the onshore Otway Basin along with the central onshore area of the Gippsland Basin were prospective for onshore gas. Andrews has said any new gas production would be reserved for the Victorian market.

While there is no onshore production in the state, development could start from financial year 2023-24, according to the VGP’s report. However, the state’s onshore resources are not expected to meet Victoria’s forecasted shortfalls or to affect demand and prices.

AEMO shared this in its latest Victorian Gas Planning Report (VGPR) and Gas Statement of Opportunities (GSOO) report, published March 27.

Supply shortfall

Aemo has projected that supply from existing and committed gas developments will meet expected demand across eastern and south-eastern Australia until at least 2023, provided that spot LNG exports are redirected to the domestic market if needed.

Total east coast gas production is projected to fall from 2,031 PJ in 2020 to 1,947 PJ in 2024, despite an increase in committed gas developments over the past year.

The body said supply from existing and committed gas developments in the country’s south would fall by more than 35% over the next five years. Victoria’s consumption is projected to fall slightly from 216 PJ in 2020 to 208 PJ in 2014 while supply is expected to fall steeply from an estimated 361 PJ in 2020 to 201 PJ in 2024.

Aemo said either additional southern supply sources would need to developed, LNG import terminals progressed or pipeline limitations addressed otherwise gas supply restrictions and cuts to gas-powered generation (GPG) during peak winter days from 2024 were likely.

While the above figures point to a 7 PJ supply shortfall emerging in 2024, Aemo has warned that the unexpected early closure of several mature fields in the Gippsland Basin – forecast to cease production between mid-2023 and mid-2024 – could create supply gaps during Victoria’s peak winter days in 2023.

Meeting demand until the end of the market operator’s 2020-2039 outlook period will require the development of more uncertain reserves and resources across eastern and south-eastern Australia. Aemo said there was also a risk that anticipated projects might not even progress.

Australian developers Woodside Petroleum and Santos have already slashed their investment budgets in late March in direct response to the collapse in oil prices. Woodside has delayed final investment decisions (FIDs) on the Scarborough, Pluto expansion and Browse LNG projects, while Santos has deferred FID on the Barossa backfill project. Local independent Beach Energy, meanwhile, has said it will slash its investment budget by 30%.

The combination of the coronavirus (Covid-19) pandemic’s destruction of demand and energy market oversupply has seen international oil and gas prices slide to multi-year lows and could have serious implications for the domestic gas market.

Problem solving

Aemo said early analysis suggested that Covid-19 would reduce global LNG demand for 2020, which could see Queensland CBM producers divert excess gas to east coast buyers over the next year.

While local consumers will benefit in the short run, the long-term consequences may be less positive. The interconnected nature of the regional market means that changes in Victoria’s gas supply picture are felt by its neighbouring states. As the southern state’s gas supplies tighten there will be less to export to New South Wales and South Australia, which will have to rely more heavily on Queensland’s production.

Aemo has already warned that production from existing and committed southeastern gas developments can only provide adequate supply until 2023-2025 in conjunction with the diversion of spot LNG export cargoes to the domestic market. Beyond this point, however, major southbound pipeline infrastructure upgrades will be needed in order to deliver more gas from northern states.

While new supplies from currently uncommitted projects could still be brought into production during the next five years to change the operator’s outlook, an uncertain investment environment complicates matters. A prolonged period of low energy prices will weaken developer balance sheets, leading to additional project delays similar to those already reported.

With existing Victorian gas production set to decline, the state’s onshore unlikely to deliver material volumes in the short to mid-term and a permanent ban on unconventional waiting in the wings, the east coast market will either have to look to LNG imports or unconventional gas developments in other states for respite.

Aemo has said domestic supply gaps could be pushed back by as much as four years if the NSW is able to fulfil its agreement with the federal government to deliver 70 PJ per year of gas to the local market by 2023. While it remains unclear where NSW will find the extra gas, the Narrabri CBM project has been cited as a priority project as have the proposed Port Kembla and Port of Newcastle LNG terminals.

Nearly half of Oz gas ‘unviable’

Relying on gas supplies from other states, especially Queensland, has been cited as one of the solutions to Victoria’s problem. However, a report by Rystad Energy has suggested that the collapse in gas prices is threatening the viability of the high-cost coalbed methane projects in Queensland. This has the potential to create further uncertainty about future gas supplies to Victoria.

“If today’s low prices persist, Rystad Energy has estimated that nearly 42% of Australian gas resources would be rendered uneconomic,” it said.

Asian gas prices have dropped from highs of more than $11/mn Btu in late 2018 to just $2.7/mn Btu in March 2020. In Australia, close to 30% of gas production is derived from high-cost CBM sources.

With LNG prices now so low, Australian east coast gas prices have tumbled from over $6/mn Btu in 2019 to $2.30/mn Btu, the report said. This represents a big issue for east coast producers, as Rystad says delivered prices below $4/mn Btu are insufficient to support long-term CBM production. And the crash in oil prices will feed through into term LNG sales agreements.

Also, at current Japan Customs Cleared-linked netback gas prices, 42% of Australia’s gas resources as of 2020 would be marginal or uncommercial, while two thirds of Australia’s discovered but undeveloped resources are at risk under the current pricing levels.

Another consultancy EnergyQuest was a little more bullish however, saying that the LNG projects would survive but not thrive. It expects export revenues in 2020-2021 (July-June) to drop to A$30bn (US$19bn) from the expected A$50bn revenue in 2019-2020 as lower oil prices feed through into realised LNG prices in the coming few months.

Subhead: Arrow gives thumbs-up to CBM

Low prices notwithstanding, Arrow Energy, a 50-50 joint venture comprising Shell and PetroChina, sanctioned the start of the first phase of its Surat gas project in southern Queensland, with construction set to begin this year.

Arrow produces 140mn ft³/d, enough to meet around 40% of Queensland domestic demand or around 10% of Australian east coast domestic demand, Shell said.

“Today’s decisions by PetroChina, Shell and Arrow demonstrate commitment to and confidence in Queensland and the Australian market at a time of global economic turmoil from Covid-19 and against the backdrop of sustained low oil prices,” Arrow CEO Cecile Wake said. “This significant investment comes at a critical time and will cement Arrow’s position as a major producer of natural gas on the east coast.”

First gas is due in 2021. Over the full 27-year life of the Surat gas project, Arrow expects to develop around 5 trillion ft3 of natural gas, which will be liquefied for export or sold at home.

Shell did not put a price tag on the project but Queensland state premier told journalists it was worth A$10 ($6.4)bn.

-- Shardul Sharma