Amplitude Energy Greenlights $200M Gas Project Targeting 90 TJ/Day From 2028
Key Takeaways
- Amplitude Energy has taken FID on the ECSP, sanctioning subsea tie-ins of the Annie, Juliet, and Artisan fields into the existing Athena Gas Plant, targeting up to 90 TJ/day gross production from CY2028.
- Revenue is already partially locked in — 35 PJ of Amplitude Energy's share of ECSP production is contracted to EnergyAustralia and AGL via executed Gas Sales Agreements, with FID satisfying the key condition for those agreements to become effective.
- Point-forward development costs are estimated at $190–210 million net to Amplitude Energy's 50% share, with the majority structured as fixed-price or fixed-rate contracts, funded from existing cash and operating cash flow across FY27 and FY28.
- The Nestor exploration well has been sanctioned alongside FID, with a net cost of $70–80 million (50% share) and potential commercialisation as early as CY2028 if a discovery is made, lifting FY27 capex guidance to $320–390 million.
- Juliet-1 has been successfully completed with a peak flow rate of 56.7 MMscf/day, low CO₂ (~1 mol%) and N₂ (~2 mol%) composition, and no formation water recovered — results consistent with pre-drill expectations.
ECSP reaches Final Investment Decision as Amplitude Energy commits to east coast gas growth
Amplitude Energy has taken the Final Investment Decision (FID) to proceed with the development phase of its East Coast Supply Project (ECSP), sanctioning the tie-in of the Annie and Juliet fields, with the Artisan (AJA) field subject to completion of Amplitude Energy’s acquisition of Artisan, in Victoria’s Otway Basin into existing infrastructure. The project targets gross production of up to 90 TJ/day from CY2028, with the AJA fields designed to sustain that output for at least four years from first gas. The ECSP is the company’s largest organic growth project and a cornerstone of its domestic gas supply strategy.
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What the ECSP means for Australia’s east coast gas market
Australia’s east coast gas market is under structural pressure. Declining production from legacy fields has made southern markets increasingly dependent on gas diverted from Queensland and from storage reserves during high-demand periods, particularly when gas-powered electricity generation is called upon.
The ECSP addresses this gap through what the industry calls brownfield development. In simple terms, this means using infrastructure that already exists, in this case the Athena Gas Plant (AGP) in the Otway Basin, to bring newly discovered resources into production faster and at lower cost and risk than building entirely new facilities from scratch. That approach gives Amplitude Energy a materially shorter path to first gas than greenfield alternatives would allow.
Both the Federal Government and the Victorian Government have signalled support for new domestic supply coming online from 2028 onwards, and that policy backdrop aligns directly with the ECSP’s targeted timeline. Amplitude Energy is positioned as a domestic supplier to southern markets at precisely the moment new supply is most needed.
Managing Director and CEO Jane Norman
“Feedback from gas customers continues to suggest strong demand for more gas supply on the east coast at pricing levels attractive for Amplitude Energy. With the Federal and Victorian Governments seeking solutions to east coast gas market tightness from 2028 onwards, there is support from both governments and customers to develop new domestic gas supply, reflecting a growing understanding of the importance of reliable, affordable and lower-emissions domestic gas.”
Project economics, contracting and cost structure
Development costs and funding pathway
Point-forward development costs for the ECSP development phase are expected to be $190–210 million net to Amplitude Energy’s 50% share, covering the period from 1 September 2026 across FY27 and FY28. That range encompasses subsea infrastructure installation, AGP modifications and control system upgrades, pipeline re-lifing, approvals, project management activities, and appropriate contingencies. It also includes the costs of a Nestor subsea tie-in, which are contingent on exploration success at the upcoming Nestor well.
A key risk mitigation point: the majority of development phase costs relate to fixed-cost items or fixed-rate contracts. That structure limits Amplitude Energy’s exposure to cost blowouts during execution. Funding is expected to come from the company’s existing cash reserves and operating cash flow across FY27 and FY28.
Gas Sales Agreements underpin revenue
The revenue foundation for the project is already in place. Key contracting highlights include:
- Gas Sales Agreements (GSAs) executed with EnergyAustralia and AGL
- Total contracted volume: 35 PJ of Amplitude Energy’s share of ECSP production
- FID satisfies a key condition required for these GSAs to become effective
- Diversified pricing exposure across Australia’s southern markets
- Further contracting to be progressed once the drilling phase of the ECSP is complete
Nestor sanction, Juliet-1 results and the drilling campaign
Nestor exploration well sanctioned
Alongside the FID, Amplitude Energy and joint venture partner O.G. Energy have agreed to sanction the drilling of the Nestor exploration prospect. Nestor is a drill-ready prospect close to existing Otway Basin infrastructure that has been preserved as an optional well within the current Transocean Equinox drilling campaign.
The point-forward net cost to Amplitude Energy for Nestor drilling and completion is expected to be $70–80 million (50% share). Cost efficiency is supported by the availability of the Transocean Equinox rig, the planned ‘one-touch’ drilling and completion approach, and low subsea tie-in costs. Upon exploration success, Nestor could potentially be commercialised as early as CY2028, subject to regulatory approvals and licences, using existing Otway Basin infrastructure and the broader ECSP development campaign.
The Nestor sanction has lifted Amplitude Energy’s revised FY27 capital expenditure guidance to $320–390 million, up from $250–310 million. The increase solely reflects the addition of expected Nestor drilling and completion costs, with no other change to FY27 market guidance.
Managing Director and CEO Jane Norman
“We are also excited to confirm the potential expansion of the ECSP via the Nestor well. The planned ‘one-touch’ drilling and completion approach maximises capital efficiency by allowing the well to be completed during the current campaign if a discovery is made.”
Juliet-1 well completion results
The Juliet-1 exploration and development well has been successfully completed, with a clean-up undertaken over 27–28 September 2026. The well is now being suspended, ready for development tie-in as part of the ECSP.
Test results confirm strong flow rates and a gas composition that is favourable for blending with other ECSP fields. Low carbon dioxide and nitrogen levels are a positive attribute for gas quality management across the project.
| Metric | Result |
|---|---|
| Gross pay | 61 metres |
| Net pay | 52 metres |
| Peak flow rate | 56.7 MMscf/day (76/64″ choke) |
| Average stabilised rate | 54.5 MMscf/day |
| CO₂ composition | ~1 mol% |
| N₂ composition | ~2 mol% |
| Formation water | None recovered |
Results to date are broadly consistent with Amplitude Energy’s pre-drill expectations for identified pay, reservoir quality, pressure and gas composition. The Transocean Equinox rig moves to the Annie-2 development well this week.
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Investment case: A clear pathway to materially higher production and earnings from 2028
The FID announcement brings together several elements that collectively define a clear growth thesis for Amplitude Energy. Returns from the ECSP based on the AJA fields are expected to exceed the company’s internal investment hurdle rates, based on mid-case assumptions, and have been tested across a range of commodity price, execution and production scenarios.
Annie and Artisan together are assessed to contain over 120 PJ of gross 2C Contingent Resources combined, providing the resource base underpinning the project’s economics.
Key investor takeaways:
- FID taken with costs mitigated: The majority of development phase costs are fixed-price or fixed-rate contracts, funded from existing cash reserves and operating cash flow
- Contracted revenue base: 35 PJ sold to EnergyAustralia and AGL via executed GSAs, with FID satisfying a key condition for those agreements to become effective
- Production growth: Up to 90 TJ/day gross targeted from CY2028, with at least four years of production from first gas
- Nestor upside: An optional well in the current campaign provides a capital-efficient expansion opportunity, with commercialisation potentially as early as CY2028 if a discovery is made
- Policy tailwind: Both the Federal and Victorian Governments are seeking solutions to east coast gas market tightness from 2028 onwards, directly aligning with the ECSP’s targeted timeline
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