Amplitude Energy Delivers Record Full-Year Results as East Coast Supply Project Nears FID

Amplitude Energy (ASX: AEL) has delivered record underlying earnings before interest, tax, depreciation, depletion, exploration, evaluation and impairment (EBITDAX), production, sales revenue, and adjusted cash from operations in FY26, as stronger gas volumes, higher realised prices, and lower unit costs lifted margins.

Sales revenue rose 7% to $285.8 million and underlying EBITDAX increased 12% to $191.8m at a 67% margin, while adjusted cash from operations climbed 19% to $191.0m and operating cash flow more than doubled to $180.3m.

Group production increased 3.5% to a record 27.6 petajoules equivalent, led by higher Sole output and improved performance at the Orbost Gas Processing Plant (OGPP), while the average realised gas price rose 5% to $10.36 per gigajoule.

Amplitude Energy is now pursuing a near-term final investment decision (FID) on the East Coast Supply Project (ECSP), with the discovered Annie and Artisan fields underpinning the development and Juliet exploration drilling imminent ahead of targeted first gas in 2028.

Orbost Drives Operating Leverage

Gippsland Basin production rose 7.2% to 24.3 petajoules, equivalent to 66.5 terajoules per day, as Sole production increased and sulphur-processing improvements, debottlenecking, and capacity work lifted OGPP performance.

Trials above OGPP’s previous 68 TJ/day nameplate capacity continued through the second half, with the plant stable above 70 TJ/day before setting a daily record of 74.7 TJ and averaging 73.5 TJ/day in July.

Production expenses fell 8% to $57.0m and group unit production costs declined 11% to $2.07/GJ, while a further $13.4m of annualised cash flow improvement took cumulative annualised improvement since FY24 to more than $50m.

Underlying profit after tax increased to $45.0m from $9.1m, although Amplitude recorded a $27.2m reported loss after tax largely because it wrote off exploration costs associated with the non-commercial Elanora and Isabella drilling.

Cash and cash equivalents rose to $137.5m at 30 June, drawn debt fell to $175.2m and net debt dropped 85% to $37.6m after $118.6m of capital expenditure during FY26.

ECSP Near Investment Decision

Initial ECSP drilling found the Elanora target water-bearing and gas-bearing sands at Isabella that did not support commercial development after flow testing, with the rig received on 15 August for Juliet before the planned Annie development well.

Amplitude Energy’s agreed purchase of a 50% interest in the discovered Artisan gas field remains conditional after a successful development-well flow test satisfied a key condition, with consideration including a $58.3m cash payment on completion and a capped production royalty.

Two binding foundation gas sales agreements cover 8.75 PJ per year from Amplitude Energy’s share of ECSP production for initial four-year terms, conditional on drilling outcomes including minimum reserve bookings and field deliverability as well as FID.

Subsea development engineering and long-lead orders are complete, with Amplitude Energy targeting FID in the first quarter of FY27 and first gas in 2028 while expecting to fund ECSP capital expenditure from existing cash and underlying organic cash generation.

“We are on track to achieve transformational growth through the ECSP, one of the most significant sources of new domestic gas supply currently being advanced in south-east Australia,” chief executive officer Jane Norman said.

Strong Resource Outlook

Proved and probable (2P) gas and oil reserves stood at 26.7 million barrels of oil equivalent (MMboe), with the reduction from 31.1 MMboe largely reflecting 4.5 MMboe of FY26 production and no material reserve revisions.

Contingent resources in the 2C category increased by 2.5 MMboe to 50.8 MMboe, driven by a 3.1 MMboe booking for the Sole-5 infill opportunity and a 0.4 MMboe uplift at Patricia Baleen, partly offset by 1.0 MMboe removed after Otway Basin permit relinquishments.

Amplitude Energy is progressing the Patricia Baleen restart toward its next engineering phase in the second half of 2026, targeting a low-cost return of existing wells through OGPP while preserving Longtom as a potential backfill option.

For FY27, Amplitude Energy is guiding production of 26.6–28.5 PJe, production expenses of $58–64m, other cash expenses and costs of sales of $27–31m and capital expenditure of $250–310m excluding decommissioning, with the production range allowing for a planned OGPP shutdown and natural field decline and the spending range excluding uncommitted Nestor drilling and the Artisan upfront payment.

“Looking ahead to FY27, our priority is to pursue growth via the ECSP on schedule and on budget while maintaining our strong base business—this includes reaching final investment decision on the ECSP development phase in the near term and continuing to optimise cash flows from our base business,” Ms Norman added.