AUCTUS ON FRIDAY - 29/11/2024

AUCTUS PUBLICATIONS
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ADX Energy (ADX AU)C; Target price of NOK51 per share: Water inflow from a small interval in Welchau deeper formation. Continuing well test up hole – Two intervals in the Steinalm formation (1452.5 m-1463.5 m and 1474.5 m-1480 m MD) were tested at a stable rate (natural flow) of 240-290 bbl/d of drilling mud, likely contaminated formation water and some oil traces. Gas was initially observed at surface. While the achieved flow rate highlights the high permeability of the natural fractures, the absence of hydrocarbons is disappointing and surprising given the results of the logs, the inflow of gas while drilling, the analysis of the retrieved cores (with indication of hydrocarbons) and the fact that down hole oil samples were recovered from this interval. Production logging results suggest that most (~80%) of the water inflow came from a single entry point at ~1478 m MD with hardly any contributions from the remaining perforations. The dominant flow is interpreted to be from a fracture system accessing an oil/water contact lower in the structure. This opens the possibility that some part of the Steinalm below that point could still be in the oil zone. In addition, there is at least 27 m of Steinalm reservoir above the main mud and water inflow entry point at ~1478 m depth. The shallower Reifling will now be tested, where influx of hydrocarbons was also witnessed while drilling. The Reifling formation is 128 m thick at the well location (Steinalm: 118 m). While the Reifling is less naturally fractured than the Steinhalm, the matrix and vugs permeability in the Reifling is higher. If the water encountered in the Steinalm came through the fractures from a deeper water zone, the fact that Reifling is less fractured could be a positive. However, the individual flow rate from a vertical well could also be lower, and the development of the formation could be based on horizontal drilling as is the case in Canada. Three intervals will now be perforated in the upper Reifling (starting from the top) including (1) 1324 m to 1340 m MD (16 m), (2) 1346 m to 1351 m (5 m) and (3) 1358 m to 1382 m (24 m). The Steinalm is the largest contributor to the prospective resources estimates. We are carrying a 70%/30% resources split between the Steinalm and the Reifling. Following the results of the flow test in the Steinalm formation, we have taken the cautious view to reduce our chance of development for this zone from 50% to 15%. This might be too conservative. We have left unchanged the Reifling. Our unrisked value for this formation is A$0.36/sh. We changed our target to A$0.40/sh.
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Arrow Exploration (AXL LN/CN)C; Target price of £0.75 per share: FY25 budget: Production growth and exploration upside – The 3Q24 financials were in line with our expectations with cash of US$16.5 mm at the end of September, which is consistent with previous indications. The sixth horizontal well at Carrizales Norte (CNB HZ-7) is producing 700 bbl/d of oil (350 bbl/d net to Arrow) with a water cut of 65%. While this flow rate is lower than at previous wells, we note that the horizontal well has been positioned lower in the structure and only 50 feet above the oil water contact. The other horizontal wells were positioned ~100 feet above the oil water contact. Arrow was expecting a higher initial water cut at HZ-7 well than at other horizontal wells. The HZ-7 well is the first well that went through the fault in this area of the field, resulting in additional drilling locations and potential reserves. Overall current net production is now 5.5 mboe/d (5,305 boe/d on 11 November). Arrow plans to spend ~US$50 mm in 2025 to drill up to ~23 wells with two rigs. The programme includes development wells at RCE and Carrizales Norte as well as exploration wells at Mateguafa Oeste and Capullo. Including the upcoming Alberta prospect, the programme is targeting ~11 mmboe prospective resources with an aggregate unrisked NAV of £0.42/sh. Arrow will also shoot 3D seismic to mature additional prospects. We forecast that the drilling programme will increase production from ~5.5 mbbl/d to >7 mbbl/d at YE25. By comparison, the US$37 mm FY24 drilling programme has increased production from 2.6 mboe/d in 4Q24 to 5.5 mbbl/d. As we incorporate the FY25 budget, partially offset by lower Brent price assumptions, we have increased our target price from £0.70/sh to £0.75/sh. We anticipate an increase in 2P reserves at YE24..
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Condor Energies (CDR CN)C: Equity financing upsized – Condor has upsized its equity financing priced at C$1.90 per share from C$10 mm to C$15 mm.

Criterium Energy (CEQ CN)C; Target price of C$0.35 per share: Work-overs outperform. Still waiting on well results. Near term focus on gas - 3Q24 production of 879 bbl/d was in line with expectations. The company’s cash position of C$6.1 mm at the end of September is high but reflects greater current payables. We note a further opex reduction from C$3.4 mm in 2Q24 to C$2.6 mm with flat production. The workover programme is outperforming expectations with production currently standing at ~1,000 bbl/d without any new wells. Production is expected to reach 1,100-1,150 bbl/d by ~YE24 with four additional workovers. The total cost of the FY24 workover programme to boost production from ~800 bbl/d to >1,100 bbl/d was only ~US$0.6 mm. Well testing activities continue at the MGH-43 well with multiple zones being evaluated. Adding 150 bbl/d in 1Q25 would boost production to ~1,250 bbl/d. A 10-13 workover programme in 2025 (total cost 5 mboe/d net), total production was already over 50 mboe/d on 2 October. Since then, the Gannet GE-05 well has been tied-in and the EC1 well (Guillemot NW field) has reached TD (first production in 1Q25). Overall, we forecast that Serica could produce ~48 mboe/d in 1Q25 assuming no further problems at Triton. The second compressor at Triton continues to be expected to be repaired in 1Q25. This will provide some redundancy and address the operational vulnerability at Triton. As a result of Triton coming back later than expected, the company has reduced its FY24 production guidance to 37 mboe/d (we forecasted 39.5 mboe/d). The FY24 opex and capex guidance is unchanged but with the lower FY24 production plus the proceeds of the Triton December lifting (0.4 mmbbl or ~US$24 mm) now expected to be received in January, we now forecast YE24 net debt of ~US$45 mm. While our YE24 net has increased, we note UK gas prices (NBP) now stand at ~£1.20 per therm. With Russia cutting gas supplies to Austria, the fundamentals for UK gas prices in the near term are very strong. Serica continues to be committed to significant dividend returns. All else being equal, we continue to forecast >16% dividend yield for 2024.
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Southern Energy (SOUC LN/SOU CN)C; Target price of £0.60 per share: Better balance sheet than expected. Emerging signs of recovery in gas fundamentals - 3Q24 production of 2,336 boe/d was in line with our expectations. Southern has monetized excess inventory for US$2 mm during 3Q24, resulting in net debt being reduced by US$1.4 mm. Southern estimates that further excess inventory could be sold for US$1-1.5 mm. The company is also involved in an ongoing dispute around transportation fees, which Southern believes are governed by a regulated rate. In case of success, Southern could recover overpaid historical fees. In addition, future transportation costs could be reduced by ~US$0.1 mm per quarter. Southern has obtained a further amendment to its credit facility with an extension to the pause of the monthly repayment of the principal to YE24. A US$1.7 mm repayment of the principal could be due at the end of January. We estimate that Southern has enough cash resources to fund this. The ~US$3.2 mm convertible debentures mature at the end of June 2025 but Southern has been able to extend its maturity in the past. We continue to assume that new wells will be drilled according to available cashflow. We have reduced our Henry Hub (HH) assumptions, and we are now forecasting a more muted production profile. We are also assuming lower drilling and service costs (~US$5 mm to drill/complete a well vs US$6 mm previously). Higher gas prices or more capital would allow Southern to grow production faster. We have changed our target price to £0.60/sh to reflect lower HH assumptions and our new production profile. Southern continues to be a play on the recovery of US gas prices; however, the company also holds acreage in the Williamsburg and Mechanicsburg that would provide diversification from natural gas.
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Tethys Oil (TETY SS)C; Target price of SEK80 per share: Field development approved in Oman. Flow test at Kunooz-1 has commenced – The field development for Bock 56 has been approved by the Ministry of Oman. Preliminary results from the testing of Kunooz-1 are expected in ten to 15 days.

Valeura Energy (VLE CN)C; Target price of C$10 per share: Higher flow rates than expected and potential reserves upside at Jasmine - Production at Jasmine has increased to 9,8mbbl/d over the last seven days following the drilling of five new infill wells. This is higher than we expected and represents an increase of >2 mbbl/d. Corporate production in September and October was already at ~26.4 mbbl/d. Even after allowing for production declines, the strong production at Jasmine gives us confidence in the 4Q24 26 mbbl/d production guidance. One of the new Jasmine wells evaluated several secondary appraisal targets, resulting in five further zones being completed as future producing reservoirs. The well encountered several additional oil-bearing intervals which may be the subject of further infill development drilling. This is expected to contribute to the YE24 reserves replacement ratio being greater than 100%. This figure does not include the expected reserves booking when FID is taken for the redevelopment of Wassana (1Q25).
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IN OTHER NEWS
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AMERICAS

Gran Tierra Energy (GTE LN/CN/US): Discovery in Ecuador/Selling asset in Canada – The Zabaleta-K-1 exploration well in Ecuador tested 1,105 bbl/d of 17 deg API oil with a 2% water cut. In Canada, Gran Tierra is selling 50% WI in the Simonette Montney (3.9 mmboe 2P reserves and ~0.8 mboe/d production) to Logan Energy for C$52 mm in cash. Logan will also carry the first development well in the Lower Montney region valued at C$3 mm net to Gran Tierra.

HeLix Exploration (HEX LN): First zone at helium exploration well uneconomic – Well test results of the Amsden formation at the Clink #1 well suggest sub-economic helium grade in gasses. The Amsden formation is a secondary target containing less than approximately 6% of the project resource of 2.3 bcf. The deeper Charles formation will now be tested. Testing at Darwin #1 is due to commence next week.

Parkmead Group (PMG LN): FY results for the year ending 30 June 2024 – Gross production in the Netherlands was 3.3 mboe/d. The company held £9.5 mm in cash at the end of June.

Rockhopper Exploration (RKH LN): Resources and costs increase in the Falklands – Peak production at Sea Lion using a refurbished FPSO is estimated at 55 mbbl/d. 319 mmbbl gross resources are expected to be recoverable from the Northern Development Area. In addition 312-532 mmbbl gross 2C resources have been estimated in the Central Development Area. Overall, the certified gross 2C recoverable oil resources have increased from 791 mmbbl to 917 mmbbl. In addition, 2.1 tcf of 2C recoverable gas resources have been certified. The gross capex required to first oil has increased to US$1.4 bn.

EUROPE

Beacon Energy (BCE LN): Becoming a shell – The reservoir performance from the SCHB-2 well in Germany continues to disappoint the company with current production of ~45 bbl/d, a decline of ~20% since the installation of a rod pump in early September. Production at these levels places doubt on the future financial viability of Rhein Petroleum (Beacon’s subsidiary). The assets of Rhein Petroleum are being sold to meet obligations to creditors, resulting in Beacon to become an AIM shell.

Galp Energia (GALP LS): Dropping helium project in Portugal - Galp has decided not to proceed with the construction of the Aurora helium project.

Harbour Energy (HBR LN): Exiting CCS project in the UK – Harbour is withdrawing from the Medway Hub Camelot CCS project.

Horizon Petroleum (HPL.V CN): Operating update in Poland – Horizon has received the final, signed concession agreements for a 100% working interest in the Bielsko-Biala and Cieszyn concessions located in southwest Poland. The company plans to re-enter the Lachowice-7 well in 3Q25. Horizon holds 36 bcfe of 2P reserves plus 249 bcfe of 2C contingent resources.

OMV (OMV AG): Farming out exploration assets in Hungary – OMV is selling 50% WI in the Han Asparuh offshore block in Bulgaria to NewMed Energy. In exchange, NewMed Energy will bear a significant part of the costs of the exploration and appraisal operations. Han Asparuh is an exploration block located in the western Black Sea in Bulgaria, south of the Neptun Deep block in Romania and has an area of 13,712 km² with water depths slightly below 2,000 m.

Serinus Energy (SENX LN): 3Q24 results – Production from January to September 2024 was 577 boe/d including 522 boe/d in Tunisia and the balance in Romania. The company had a working deficit of US$5.2 mm a the end of September.

FORMER SOVIET UNION

Enwell Energy (ENW LN): Lifting of suspension of Ukraine licences – Enwell has obtained interim rulings from the Poltava District Administrative Court to lift the suspensions of the company's MEX-GOL, SV and VAS production licences.

MIDDLE EAST AND NORTH AFRICA

Energean (ENOG LN): Trading update – Production from January to September was 156 mboe/d. The FY24 production guidance has been reduced from 155-165 mboe/d to 150-155 mboe/d with lower exploration capex (U$95-120 mm vs US$115-150 mm previously).

SUB-SAHARAN AFRICA

TotalEnergies (TTE FP): Selling interests in Namibia – Total is selling 5.25% in PEL56 and 4.695% in PEL 91 to QatarEnergies.

Tullow Oil (TLW LN): Operating update – Production YTD averaged ~62 mboe/d including 6.5 mboe/d of natural gas. Jubilee gross oil production averaged ~89 mbbl/d (~34.5 mbbl/d net) to end-October, below expectations primarily due to underperformance of the J69-P well, unplanned downtime at the onshore gas processing plant and periods of reduced water injection due to power outages. TEN gross oil production averaged 19 mbbl/d (10.5 mbbl/d net) above expectations, with Enyenra and Ntomme wells responding positively to both injection and production optimisation. Production in Cote d’Ivoire and Gabon averaged 10.5 mbbl/d. The FY24 production guidance of 62 mboe/d with US$300 mm capex is unchanged. The government of Ghana owes ~US$40 mm of overdue gas payments.