Petroleum exploration activity in the onshore basins of the Northern Territory is mostly focused on the Beetaloo Sub-basin and the Amadeus Basin. Exploration for sub-salt and intra-salt plays for helium and hydrogen accumulations is also focused on the Amadeus Basin.
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Overview
Onshore petroleum exploration activity in the Territory in 2025 was largely focused on the appraisal of shale gas plays in the Beetaloo Sub-basin, with pilot production scheduled to commence in 2026.
Petroleum exploration expenditure in the NT in the 2024 calendar year was $369.7 million, up 469% on the 2023 figure of $78.8 million. The ABS do not provide a breakdown of offshore vs onshore for petroleum expenditure in the NT; however, a significant proportion of this expenditure is likely to have been onshore, primarily in the Beetaloo Sub-basin and Amadeus Basin, with some expenditure also likely to have been incurred offshore. The 2025 calendar results will be available in March 2026.
Since 2010, more than 70 exploration and production wells have been drilled onshore in the Northern Territory and exploration seismic data has been acquired in the McArthur, Amadeus, Pedirka and Georgina Basins. Read on for a detailed review of exploration activities in 2024.
The Beetaloo Sub-basin is a significant depocentre of Mesoproterozoic Roper Group sedimentary rocks of the McArthur Basin that underlies the Mesozoic Carpentaria Basin in the vicinity of Dunmarra and Daly Waters, and is the Territory's most advanced shale gas play. The B-shale of the Amungee Member of the Velkerri Formation is the primary target for shale gas exploration, with demonstrated continuity of gas-rich productive shales across a vast area of the sub-basin. In 2025, Tamboran Resources Corp and Beetaloo Energy Australia Ltd both progressed appraisal activities as they move towards planned pilot production in 2026.Combined 2C Contingent Ressources of shale gas across all operators in the Beetaloo currently totals 7.126 Tcf gas.
Tamboran Resources Ltd, in joint venture with Daly Waters Energy LP and Falcon Oil and Gas Australia Ltd, is the operator on three permits in the central part of the Beetaloo Sub-basin (EP 98, 117 and 76). Tamboran commenced their Shenandoah South Pilot Project drilling program in August 2024, with the spudding of the Shenandoah South-2 (SS-2H ST1) well in EP98, 5 km north of SS-1H. The well was drilled to a total depth of 6300 m in 35 days, including a 3000 m horizontal section. This was followed by the Shenandoah South-3 (SS-3H) well in late 2024. In February 2025, Tamboran announced that they had successfully completed stimulation activities over 35 stages across a 1671 m horizontal section in the Shenandoah South 2H sidetrack (SS-2H ST1) well. The well achieved an average 60-day initial production (IP60) flow rate of 6.8 million cubic feet per day (MMcf/d) over the 1671m stimulated horizontal within the Mid Velkerri B Shale. The average flow rate of 12.4 MMcf/d over a normalized 10,000-foot horizontal section is in line with an average of more than 11,000 wells in the Marcellus Shale dry gas area with production for over a 12-month period.
In July 2025, Tamboran commenced a batch drilling program for three wells (Shenandoah South-4H, -5H and -6H) on the same pad as SS-2H and SS-3H. In October 2025, Tamboran announced all three wells had successfully been drilled and cemented with 10,000-foot horizontal sections within the primary Mid Velkerri B shale target. The three wells were drilled with an average spud-to-target depth of less than 27 days. In December 2025, Tamboran announced it had successfully completed stimulation activities on the Shenandoah South 6H (SS-6H) well, comprising 58 stages across a 10,009-foot (~3,050-metre) stimulated length in the Mid Velkerri B Shale. Stimulation of the remaining three drilled wells (SS-3H, SS-4H, and SS-5H) is planned for the first half of 2026, subject to wet season conditions.
Tamboran have reported that the five wells are expected to deliver the contracted 40 TJ/d volume required under their existing Gas Sales Agreement with the NTG. In September 2025, Tamboran secured approvals to sell appraisal gas and announced its Final Investment Decision on the Shenandoah South Pilot Project. In November 2025, APA Group announced commenced construction of the 37 km Sturt Plateau Pipeline (SPP) connecting the Shenandoah South wells with the Amadeus Gas Pipeline (AGP). The Sturt Plateau Compression Facility will be completed in the first half of 2026 to facilitate the flow from the Tamboran wells in the Sturt Plateau pipeline.
Santos Ltd have EP161 in the eastern Beetaloo Sub-basin in joint venture with Tamboran Resources Corp. EP161 includes the Mount Brown (formerly Tanumbirini)-2H and Mount Brown-3H horizontal wells, and the has a 2C Contingent Gas Resource of 1.88 Tcf gas. During 2025, Santos progressed preparations for a up to three 10,000-foot horizontal well program at the Jibera South and Newcastle South locations in EP 161. Santos plans to undertake the program in 2026 and expects to stimulate each well during the 2027 dry season.
Beetaloo Energy Australia Ltd (formerly Empire Energy Group Ltd) continued drilling and flow-testing of wells in EP187 on the eastern margin of the Beetaloo Sub-basin, and have 2C Contingent Resources of 1.467 Tcf gas within EP187. In November 2024, the company drilled the Carpentaria-5H (C-5H) well on the same pad as the Carpentaria-2H (C-2H) and Carpentaria-3H (C-3H) wells. C-5H is designed to produce gas for the Carpentaria Pilot Project. The well was drilled to a total depth of 5310 m in 41 days, including a 3310 m horizontal section in the target Velkerri B Shale at an average depth of about 1575 m, Carpentaria-5H achieved a peak gas flow rate of 11.2 TJ/day, the second-highest 30-day average flow rate in the basin of 7.1 TJ/day and an exit flowrate of 6.3 TJ/day, confirming a low rate of decline over the 30-day clean-up test. Beetaloo Energy Australia announced a Final Investment Decision for the Carpentaria Pilot Project in December 2025. Civil construction works for the Carpentaria Gas Plant are well advanced, with gas sales expected to start in the second half of 2026.
McArthur Basin
In January 2024, Armour Energy Group sold its assets, including its exploration permits in the McArthur Basin in the Territory to ADZ Energy Pty Ltd.
In June 2024, Top End Energy Ltd was granted EP258 was granted, marking the first exploration permit granted in the Territory since 2015. In February 2024, Top End Energy Ltd announced plans to acquire granted EPs 144, 153 and 154 in the greater McArthur Basin and South Nicholson Basin from Minerals Australia Pty Ltd and Jacaranda Minerals Ltd, wholly owned subsidiaries of Hancock Prospecting.
In February 2023, signed an agreement with Lucapa Diamond Company Limited for supply of gas from the Glyde field in the McArthur Basin to the Merlin diamond project, located 20 km from the field. The agreement contemplates sales of gas from the conventionally reservoired Glyde field in mid-2025.
Elsewhere in the greater McArthur Basin, Armour Energy, Minerals Australia (a subsidiary of Hancock Prospecting) and Empire Energy have large tenement holdings with a number of stacked conventional and unconventional petroleum plays.
Amadeus Basin
The Territory’s current onshore gas production is entirely sourced from Mereenie, Palm Valley and Dingo fields in the Amadeus Basin operated by Central Petroleum Ltd. In 2024, 11.663 Billion Standard Cubic Feet (BSCF) of gas was produced in the onshore Northern Territory, a 15% decrease on 2023. This comprised 7.38 BSCF from Mereenie, 2.69 BSCF from Palm Valley, and 1.59 BSCF from Dingo. Onshore oil production in the NT in 2024 was sourced entirely from the Mereenie Field, with 0.11 Million barrels (MMbbl) of oil produced.
The Mereenie Oil and Gas field was discovered in 1963 and commenced production in 1984. The hydrocarbons occur in an elongated four-way dip anticline with a length of 40 km, and a width of five kilometres. Sandstones of the Pacoota Formation host the majority of the hydrocarbons, but the overlying Stairway Sandstone has also produced gas while drilling, and several wells have been completed as gas producers. As of June 30 2024, the field has produced 19 MMbbl of oil and condensate, and over 310 PJ of natural gas. The Mereenie gas stream also contains about 0.2% helium. Proved and Probable (2P) reserves at Mereenie at June 30, 2024 are 0.36 MMbbl, with Contingent Resources (2C) of 0.05 MMbbl. Gas reserves are 36.6 PJ (2P), and 2C Contingent Resources of 45.6 PJ (PJ = Petajoules, 1 PJ = 0.981 billion cubic feet, and 0.028 billion cubic metres of natural gas).
The Mereenie Joint Venture (Echelon Resources Ltd 42.5%; Central Petroleum 25%; Horizon Oil 25%; Cure Energy 7.5%) commenced a two-well development drilling program at Mereenie in December 2024. The first well, West Mereenie-29 was completed at a 1474 m in the Pacoota-3 Sandstones and was tied to the Mereenie gathering system, with a stabilised production rate of 5 TJ/ day. Production commenced on January 20 2025, with the additional gas being supplied to the NT Government. West Mereenie-30 was spudded in January and was completed in February, and was expected to produce at, or above pre-drill expectations of 3 TJ/d. As a result, the Mereenie field is expected to have a production capacity above 30 TJ/d available to meet the long-term Gas Sales Agreement with the Northern Territory Government that underwrote the activity. Following the success of WM29, the Joint Venture is looking to prioritise increasing reserves and gas production from both Mereenie and Palm Valley through new development wells, and appraisal of the Stairway Sandstone. A new flare gas recovery compressor was brought online at Mereenie in March, capturing lowpressure waste gas and converting it to sales gas; this will reduce total CO2 -equivalent emissions by approximately one-third. Work continued on the feasibility and planning for a helium recovery plant through the year, but was suspended following a softening of the global helium market.
The Palm Valley gas field was discovered in 1965, with gas primarily in an extensive fracture system in the Lower Stairway Sandstone, Horn Valley Siltstone and the Pacoota Sandstone, at depths in the range 1800–2200 m. The anticlinal structure is approximately 29 km long and 14 km wide. Currently, Palm Valley is operated by Central Petroleum (50%), with Echelon Resources having a 35% interest and Cue Energy a 15% interest. Gas reserves at Palm Valley are 11.7 PJ (2P) with 6.5 PJ (2C) Contingent Resources. In 2024, the Palm Valley JV progressed planning and permitting for the drilling of two new appraisal wells, to increase field production capacity.
The Amadeus Sub-Salt Exploration project is a joint venture between Central Petroleum and Santos, with the latter being the operator. The project is exploring for subsalt hydrogen, helium and hydrocarbons beneath the thick salt of the Gillen Formation of the Bitter Springs Group. Helium concentration in the historical Magee-1 well was 6% He, and gas flows at the Mt Kitty well contained 9% He. Central had its project ownership interests returned to pre-farmout interests, following the termination of farmout arrangements with Peak Helium in 2023. Central and Santos were continuing to hold discussions on farmout agreements to fund exploration for sub-salt hydrogen, helium and hydrocarbons through 2024.
In September 2023, Greenvale Energy Ltd announced it had executed a Farm-in agreement with Mosman Oil and Gas Ltd to earn up to 75% in EP145, located east southeast of Mereenie. EP145 has Best Estimate Prospective Resources of 440 BCF gas, 26.4 BCF helium and 26.4 BCF hydrogen in the permit area. In October 2024, Greenvale pulled out of EP145, as they had changed their focus to uranium. In January 2025, EP145 became subject to a sale agreement between Mosman Oil and Gas and Echelon Resources Ltd. EP145 is adjacent to the Mereenie oil and gas field and contains the West Walker Anticline, a west northwest plunging structure over 30 km in length, which hosts Neoproterozoic to Ordovician sedimentary rocks. Two holes were drilled into the anticline; West Walker-1, which flowed wet gas to surface at a rate of 3.5 MMSCF/d from the Pacoota Sandstone. The second hole was drilled to the southeast; oil was seen seeping from the core but the well was not tested. Later reprocessing of the seismic survey data, on which these holes were targeted, showed them to have been drilled off structure. No additional work was completed in EP145 in 2024.
