Quarterly Report for the Three Months Ended 30 September 2023

Source Press Release
Company Cooper Energy LimitedPertamina 
Tags Oil & Gas Trading, LNG & Gas Storage/Processing, Decommissioning, Production/Development, Upstream Activities, Capital Spending, Strategy - Corporate, Financial & Operating Data
Date October 24, 2023

Key features

  • Q1 FY24 production and revenue: production up 3% from previous quarter to 5.51 PJe, revenue up 4% to $50.8 million from previous quarter
  • BMG decommissioning: Helix has confirmed the Q7000 is expected to depart from NZ in early November before starting BMG decommissioning works in the third week of November
  • Orbost Improvement Project: workstreams progressing with a current focus on reducing absorber bed cleaning time
  • PEP 169 farm-in: binding agreement for 25.1% farm-in to onshore Otway Basin PEP 169 containing Enterprise North prospect
  • Cost out initiative: underway with focus on G&A component but also broader cost base

Comments from Managing Director and CEO, Jane Norman

“During the quarter, whilst total production increased 3%, Orbost production was down 1% compared to the previous quarter, due to variability arising from execution of the Orbost Improvement Project. Despite this, it was pleasing to see some of the OGPP performance improvement initiatives executed, giving us better information on the Thiopaq process as we continue to strive for production increases. Our newly appointed Chief Operating Officer, Chad Wilson, has now commenced with the company and will focus on steering the improvement project.

“The Q7000 vessel is due to mobilise to the BMG site shortly, following an extended campaign in New Zealand. The vessel will travel via the Port of Geelong where it will clear customs, take on supplies and bunker fuel. We remain focused on executing the BMG decommissioning programme safely, within the minimum time possible and within the mid-case cost estimate. We continue to actively manage the risks, however some, such as the recent delay in receiving the Q7000 vessel, are outside Cooper Energy’s control.

“As I highlighted during the FY23 full year results, a key business priority for us in FY24 is the cost-out initiative, including reducing G&A by at least 10%. The scope of the cost-out is all encompassing, and broader than G&A alone. During the quarter we realised savings related to personnel and corporate overheads, with further cost reduction initiatives identified, such as rationalising office space, and reducing the expenses associated with sulphur removal and waste disposal at Orbost.

“The cost-out initiative, as well as recent changes to the organisational structure, ensure the business is right sized for our current and future operations.”

Key performance metrics

$ million unless indicated  Sep Q1 FY23  Jun Q4 FY23  Sep Q1 FY24  Qtr on Qtr change  FY23 YTD  FY24 YTD  Change 
Production (PJe)  6.05  5.34  5.51  3%  6.05  5.51  (9%) 
Sales volume (PJe)  6.00  5.43  5.78  6%  6.00  5.78  (4%) 
Average gas price ($/GJ)  9.06  8.61  8.30  (4%)  9.06  8.30  (8%) 
Sales revenue  55.4  48.9  50.8  4%  55.4  50.8  (8%) 
Cash and cash equivalents  83.0  77.1  47.5  (38%)  83.0  47.5  (43%) 
Net debt/(cash)  75.0  80.9  110.5  37%  75.0  110.5  47% 


Production

Quarterly oil and gas production was 5.51 PJe or 59.9 TJe/day (0.90 MMboe), 3% higher than the prior quarter. This was mainly due to increased uptime at the Athena Gas Plant (AGP) and increased production from the Cooper Basin following connection of the Callawonga-23 well.

Production by product  Sep Q1 FY23  Jun Q4 FY23  Sep Q1 FY24  Qtr on Qtr change  FY23 YTD  FY24 YTD  Change 
Sales gas (PJ)  5.9  5.1  5.3  3%  5.9  5.3  (10%) 
Oil and condensate (kbbl)  28.6  32.1  38.7  21%  28.6  38.7  35% 
Total production (PJe)  6.05  5.34  5.51  3%  6.05  5.51  (9%) 
Total production (MMboe)  0.99  0.87  0.90  3%  0.99  0.90  (9%) 

Gippsland Basin (Sole)1

Sole gas production processed through Orbost Gas Processing Plant (OGPP) was 4.2 PJ for the quarter, or 46.2 TJ/day, 1% lower than the prior quarter of 46.3 TJ/d, impacted by plant variability arising from the Orbost Improvement Project.

Activities during Q1 FY24 focussed on improving OGPP functionality, following on from the successful reduction in absorber bed clean time in Q4 FY23.

Specific workstreams included optimising the ‘nutrimix’ solution with the goal of improving bacterial performance to reduce fouling. A US based Thiopaq expert was engaged for this work, and whilst there was no immediate uplift to processing rate, knowledge and management of the live bacteria system has evolved, with learnings applied to improve the stability of the system.

The Orbost Improvement Project has also included trialling in-situ water washing of the absorber beds. The first stage of this workstream established that sulphur deposition in the absorber beds can be removed with water, with next steps focussed on refining and enhancing this methodology. If this is successful, in-situ water washing will further reduce the absorber bed downtime and reduce the operational intensity associated with the current vessel entry cleaning process.

Other near term workstreams to be implemented in Q2 FY24 include trialling new absorber bed packing material, installation of a four-nozzle spray header within the absorber bed and re-instating the polisher unit.

Going forward the polisher unit will be used strategically to support the plant during absorber cleans, or to increase overall processing rates during periods of high demand, or trials of Improvement Project initiatives. This will test the potential for prolonged use between media changeouts.

1 Cooper Energy 100% and operator

Strategic polisher use, combined with enhanced biological stability, should allow for more predictable and stable processing rates as the remainder of the Orbost Improvement Project workstreams are rolled out.

As announced at the FY23 full year results, work is progressing on the option for a third absorber bed in the event that the Orbost Improvement Project workstreams do not deliver sufficient sustained higher rates.

Otway Basin (Casino, Henry and Netherby)2

Casino, Henry and Netherby (CHN) gas production processed through AGP was 1.0 PJ net share for the quarter, or 11.2 TJ/day, 11% higher than the prior quarter of 10.2 TJ/d. Increased production was due to reliable and uninterrupted processing of CHN gas at the AGP. Well cycling operations continue to be implemented to optimise production from the CHN fields.

Subsequent to quarter end, a low inlet pressure trial was successfully conducted at AGP. Results of the trial are still being analysed, however early indications show potential positive impacts to instantaneous gas rate and extending CHN field life.

Cooper Basin3

Oil production was 37.7 kbbls net share for the quarter, or 410 bbls/day, 20% higher than the prior quarter of 344 bbls/day, mainly due to the incremental production from the Callawonga-23 well that came online in early July.

Production by basin  Sep Q1 FY23  Jun Q4 FY23  Sep Q1 FY24  Qtr on Qtr change  FY23 YTD  FY24 YTD  Change 
Gippsland Basin (Sole)         
Sales gas (PJ)  4.7  4.2  4.2  1%  4.7  4.2  (10%) 
Otway Basin (CHN)         
Sales gas (PJ)  1.2  0.9  1.0  11%  1.2  1.0  (11%) 
Condensate (kbbl)  1.06  0.82  0.97  19%  1.1  1.0  (9%) 
Cooper Basin         
Oil (kbbl)4  27.5  31.3  37.7  20%  27.5  37.7  37% 
Total production (PJe)  6.05  5.34  5.51  3%  6.05  5.51  (9%) 
Total production (MMboe)  0.99  0.87  0.90  3%  0.99  0.90  (9%) 

Exploration and development

Gippsland Basin

BMG decommissioning

The Helix Q7000 intervention vessel is currently completing its work in New Zealand. Helix has confirmed an early November expected departure from New Zealand. The vessel will transit to Geelong for customs clearance and supplies before starting works with Cooper Energy in the third week of November. The offshore support vessel MMA Vigilant is currently working at BMG, completing a planned scope of work prior to the arrival of the Q7000.

Otway Basin (Offshore)

Cooper Energy has continued to progress the Otway Phase 3 Development (OP3D) project and secured the Transocean Equinox rig, as part of a consortium agreement with three other operators. The contract is expected to commence during FY25, with timing for Cooper Energy’s firm well to be confirmed closer to the time. The rig contract also includes options to drill additional subsea development and/or exploration/appraisal wells.

2 Cooper Energy 50% and operator

3 Cooper Energy 25%, Beach Energy 75% and operator

4 Cooper Basin production data is preliminary for the current quarter, awaiting September reconciled data

The OP3D project is positioned to proceed to sanction as soon as conditions permit, most particularly Otway joint venture partner support, substantial progress of the BMG decommissioning programme, and improved performance at OGPP as a result of the Orbost Improvement Project.

Otway growth will be funded from organic cash generation, supported by existing committed senior secured bank debt as well as the $120 million accordion debt facility.

Growth in the Otway provides the opportunity to tie back new resources to Cooper Energy’s existing gas processing infrastructure at the AGP, which has ~150 TJ/d of total capacity and current utilisation of ~25 TJ/d (both 100% gross).

Otway Basin (Onshore)

In the onshore Otway Basin in South Australia, processing of the PEL 494 Dombey 3D seismic survey progressed during the quarter. Processing and interpretation of the final 3D seismic data is expected by the end of 2024. Interpretation of the 3D seismic data will delineate the resource potential of the Dombey gas field and identify potential new exploration opportunities.

Reprocessing of the existing 3D seismic surveys within PEP 168 is also expected to be completed in Q2 FY24.

Cooper Basin

An exploration drilling campaign commenced in ex PEL 92. Cooper Energy is participating in three exploration wells. The first well Marion-1, was plugged and abandoned on 30 September 2023, having drilled to a total depth of 1,750 metres and failing to encounter hydrocarbons in the primary Namur Reservoir.

Subsequent to the quarter end, the Bangalee South 1 exploration well was drilled. It is located 630 metres southeast of Bangalee-1. It intersected 2.9 metres of net oil pay in the Namur reservoir and 4.3 metres net oil pay in the Birkhead reservoir. The well was cased and suspended as a future oil producer. It is expected to be brought online in 2024.

Financial

Sales volume and revenue

Total Q1 FY24 gas and oil volumes sold of 5.78PJe, or 62.8 TJe/day, was 6% higher than the previous quarter of 5.43 PJe (59.7 TJe/day). Periods of instability throughout the quarter associated with the impact from the Orbost Improvement Project resulted in gas purchases of 284 TJ, up from 135 TJ in Q4 FY23. Surplus Gippsland gas production, relative to the Sole term contracts, resulted in spot gas sales of 254 TJ (Q4 FY24: 309 TJ).

Total gas sales revenue was 2% higher at $46.1 million, due to a 5% increase in gas sales volumes (volumes impacted by gas purchases), partially offset by a 4% decrease in average realised gas prices across both basins of $8.30/GJ (Q4 FY23 $8.61/GJ).

The lower average realised gas price in Q1 FY24 was largely due to lower average spot prices of $8.85/GJ (Q4 FY23 $11.64/GJ). During the quarter 95% (Q4 FY23: 94%) of gas was sold into term contracts, at an average price of $8.28/GJ (Q4 FY23: $8.28/GJ).

PEL92 production for Q1 FY24 increased to 406 bbls/d (Q4 FY23: 343 bbls/d), with volumes sold of 35,722 bbls (Q4 FY23: 25,470 bbls) at an average oil price realisation of A$128.40/bbl (Q4 FY23: A$130.29/bbl).

Total liquids revenue, including condensate, was $4.7 million in the quarter (Q4 FY23 $3.5 million). Crude oil inventory at 30 September 2023 was 27,858 bbls (30 June 2023: 26,976 bbls).

    Sep Q1 FY23  Jun Q4 FY23  Sep Q1 FY24  Qtr on Qtr change  FY23 YTD  FY24 YTD  Change 
Sales volume         
Gas  PJ  5.9  5.3  5.6  5%  5.9  5.6  (6%) 
Oil  kbbl  15.5  25.5  35.7  40%  15.5  35.7  130% 
Condensate  kbbl  1.1  0.8  1.0  21%  1.1  1.0  (12%) 
Total sales volume  PJe  6.00  5.43  5.78  6%  6.00  5.75  (4%) 
Sales revenue ($ million)         
Gas5    53.1  45.4  46.1  2%  53.1  46.1  (13%) 
Oil and condensate    2.3  3.5  4.7  34%  2.3  4.7  104% 
Total sales revenue    55.4  48.9  50.8  4%  55.4  50.8  (8%) 
Average realised prices         
Gas  $/GJ  9.06  8.61  8.30  (4%)  9.06  8.30  (8%) 
Oil and condensate  $/boe  146.59  130.29  128.40  (1%)  146.59  128.40  (12%) 

The tables below summarise gas sales and sources.

Sole GSA sales and sources    Jun Q4 FY23  Sep Q1 FY24  Jun Q4 FY23  Sep Q1 FY24 
Sole GSA sales  PJ  4.0  4.2  TJ/d (average)  44  46 
Sole spot sales  PJ  0.3  0.36  TJ/d (average) 
Comprising:       
OGPP processing  PJ  4.2  4.2  TJ/d (average)  47  46 
Third-party gas purchases  PJ  0.1  0.37  TJ/d (average) 
CHN GSA sales and sources    Jun Q4 FY23  Sep Q1 FY24  Jun Q4 FY23  Sept Q1 FY24 
CHN GSA sales  PJ  1.0  1.0  TJ/d (average)  10  11 
             

Capital expenditure

Q1 FY24 incurred capital expenditure of $1.5 million was significantly lower than the prior quarter which included spend relating to Cooper Basin wells and OGPP integration costs.

$ million  Sep Q1 FY23  Jun Q4 FY23  Sep Q1 FY24  Qtr on Qtr change  FY23 YTD  FY24 YTD  Change 
Exploration and appraisal  8.1  4.5  1.2  (73%)  8.1  1.2  (85%) 
Development  1.5  5.6  0.3  (95%)  1.5  0.3  (80%) 
Total capital expenditure  9.6  10.1  1.5  (85%)  9.6  1.5  (84%) 
         

5 Includes sale of third-party gas purchases

6 Sole spot sales were 254 TJ in Q1 FY24 (Q4 FY23: 309 TJ)

7 Third-party gas purchases were 284 TJ in Q1 FY24 (Q4 FY23: 135 TJ)

    Q1 FY24      FY24   
By basin, $ million  Exploration  Development  Total  Exploration  Development  Total 
Otway Basin  0.4  0.4  0.4  0.4 
Gippsland Basin  0.8  0.8  0.8  0.8 
Cooper Basin  0.3  0.3  0.3  0.3 
Other 
Total capital expenditure  1.2  0.3  1.5  1.2  0.3  1.5 

Liquidity

As at 30 September 2023, Cooper Energy had cash reserves of $47.5 million (Q4 FY23: $77.1 million), with drawn debt unchanged at $158.0 million (Q4 FY23: $158.0 million), as summarised below.

$ million  Sep Q1 FY23  Jun Q4 FY23  Sep Q1 FY24  Qtr on Qtr change  FY23 YTD  FY24 YTD  Change 
Cash and cash equivalents  83.0  77.1  47.5  (38%)  83.0  47.5  (43%) 
Drawn debt  158.0  158.0  158.0  0%  158.0  158.0  0% 
Net debt/(cash)  75.0  80.9  110.5  37%  75.0  110.5  47% 

Whilst revenue generated for the quarter was $50.8 million, up 4% from Q4 FY23, the following items impacted quarterly cash generation versus Q4 FY23, among others:

  • Payment of $40.0 million to APA in July for deferred consideration in relation to the acquisition of the Orbost Gas Processing Plant, and;
  • Spend on decommissioning of $18.0 million, primarily associated with the pre-abandonment programme and ramp up of work on BMG.

Commercial, corporate and subsequent events

Chief Operating Officer

Chad Wilson commenced as Chief Operating Officer, effective 23 October 2023. Chad has functional responsibility for operations, maintenance, engineering, development projects, as well as the operations taskforce responsible for the Orbost Improvement Project. Chad has a strong track record in driving performance improvement, transformational cost reductions and efficiency improvements, with a career spanning 20+ years at Talisman and Santos.

PEP 169 farm-in

Subsequent to quarter end, Cooper Energy and Lakes Blue Energy agreed to binding terms for the Company to farm into 25.1% of PEP 169 with an upfront consideration of A$1.2 million, together with funding Lakes Blue Energy’s retained 23.9% working interest of the drilling costs of Enterprise North-1, capped at A$1.25 million. The transaction is conditional on the completion of due diligence, negotiation of transaction documents and obtaining necessary consents and regulatory approvals.

Lakes Blue Energy currently holds a 49% interest in PEP 169, along with Armour Energy who hold a participating interest of 51% and operatorship. PEP 169 contains the Enterprise North prospect8, located less than three kilometres south of the Cooper Energy operated Athena Gas Plant and immediately north of the 204 PJe9 Enterprise gas field.

8Source: Description of Enterprise North prospect included in Armour Energy Investor Presentation released on 23 March 2023 and the ASX release on 3 July 2023

9Source: Beach Energy ASX release 15 February 2021. Cooper Energy assumed conversion factors of gas: 163,417 boe per PJ, LPG:

8.458 boe per tonne, condensate: 1 boe per bbl.

Cost-out initiative

As outlined at the FY23 full year results, a key priority in FY24 is the cost-out initiative, an all-encompassing review including production costs and targeting at least 10% savings in G&A.

Progress to date has included headcount reductions, labour cost reductions and savings in corporate and entertainment expenses; these three elements are expected to deliver savings in excess of $3.0 million.

Further work will focus on reduction in operations contract services, including waste management costs at OGPP, reducing office space including consolidating the Adelaide office and rationalising the Perth office after the completion of BMG decommissioning.

There are more than 70 actions identified in the cost-out initiative and a fuller update will be provided as part of the half yearly reporting in February.

Pertamina

The Company continues to pursue its Victorian Supreme Court claim against PT Pertamina Hulu Energi (“Pertamina”) for  Pertamina’s 10% share of the BMG decommissioning costs. Pertamina, via an Australian subsidiary, participated in the BMG oil project during its production life and Cooper Energy’s claim against Pertamina arises with respect to obligations under the withdrawal and abandonment provisions of the BMG oil project joint operating and production agreement.

2023 Annual General Meeting

Cooper Energy will hold its 2023 annual general meeting (AGM) on Thursday, 9 November 2023 at 10.30 am (Australian central daylight time). The AGM will be held in person at Peppers Waymouth Hotel, 55 Waymouth Street, Adelaide. The AGM will be recorded and available to view via the Company website after the AGM.

Source: EvaluateEnergy® ©2024 EvaluateEnergy Ltd