WTI (June) $62.05 -97c, Brent (June) $65.86 -$1.01, Diff -$3.81 -4c
USNG (June)* $3.33 u/c, UKNG (May) 76.0p -2.41p, TTF (May) €31.38 -€0.82

Oil price

Oil is a dollar off today, primarily as the spectre of Opec+ haunts the market, how much will the seniors at the cartel want to give Kazakhstan a proper kicking for misbehaviour. 

Arrow Exploration Corp

Arrow has announced the filing of its Annual Audited Financial Statements and Management’s Discussion and Analysis (“MD&A”) for the quarter and year ended December 31, 2024 and the filing of its 2024 year-end reserves report, which are available on SEDAR (www.sedar.com) and will also shortly be available on Arrow’s website at www.arrowexploration.ca. 

Full Year 2024 Highlights:

• Significant 65% growth in total oil and gas revenue to $73.7 million, net of royalties (FY 2023: $44.7 million).
• Net income of $13.2 million inclusive of an impairment reversal of $0.7 million (FY: 2023: net loss of $1.1 million).
• Adjusted EBITDA of $48 million, which is 78% greater than last year (FY 2023: $27.1 million), with Q4 2024 EBITDA of $13.3 million compared to $7.1 million in Q4 2023.
• Cash position of $18 million at the end of 2024.
• Annual average corporate production up 63% to 3,542 boe/d (FY 2023: 2,167 boe/d) with Q4 2024 average corporate production more than doubling to 4,738 boe/d compared with Q4 2023 2,335 boe/d.
• Funds flow from operations of $35.6 million (FY 2023: $19.9 million) with Q4 2024 funds flow from operations of $12.5 million (FY 2023: $3.8 million).
• Increase in Proved Developed Producing reserves at year-end 2024 of 92% to 2.4 MMboe.
• Successfully drilled seven  horizontal wells and five  vertical wells at Carrizales Norte (CN), which added significant production to the Company.
• Drilled a successful exploratory well on the Alberta Llanos (AB Llanos) field in the Tapir block.
• All operations delivered safely, with no accidents or environmental incidents.

Post Period End Highlights:

• So far in 2025, the Company has drilled three development wells on the CN field and two additional wells in the AB Llanos field in the Tapir Block, The AB-2 well is being recompleted as a water disposal well, the other new drills are all currently producing at restricted rates. Ramping production up slowly prevents early water breakthrough in each well.
• Currently mobilizing the drilling rig to the Alberta Llanos (AB) pad to start drilling horizontal development wells.  A second rig will be mobilized shortly to begin development drilling at the Rio Cravo Este (RCE) pad.
• Completed seismic data acquisition of 90 km² in the south east section of the Tapir block.  Seismic is currently being processed and will later be analysed. 

Outlook

• Arrow has a fully funded 2025 work program totaling $51 million targeting up to 23 wells mainly in the Tapir block.
• The work program includes the Company’s first horizontal wells in Alberta Llanos and recently identified prospects in Mateguafa Attic.

Marshall Abbott, CEO of Arrow Exploration Corp., commented:
“2024 was the best year for the Company so far on all fronts.  We saw substantial growth in production, revenue and EBITDA and our healthy balance sheet supports the aggressive capital program planned for 2025. Our strategy remains to maintain a disciplined approach to capital allocation which allows Arrow to grow production while maintaining positive cash flow and a growing cash position, which today’s results show clear success in doing. With a significant portfolio of reserves at year end, Arrow is confident in being able to replicate its strategy and continue to grow its production and cash flow.

So far in 2025, Arrow has completed drilling of AB Llanos 2 and 3, and horizontal wells CN HZ 9, CN HZ 10 and a directional well CN 11. Arrow is now moving the drilling rig to the AB Llanos pad where two horizontal wells are expected to be drilled in Q2 2025.   Arrow then plans to add an additional rig to drill at wells at the RCE pad and additional development wells in CN.  Additional operational updates will be forthcoming.

The Arrow team continues to strive towards growth, operational excellence and increasing shareholder value.”

It is difficult to know just what Arrow have to do to impress the market although they are not the only company in the sector who feel that they are delivering the goods to no avail. The good thing, or things about this company are that they are continuing to have exploration success and that they are fully funded for that and the development of existing finds. 

All the metrics tick the boxes, production last year was 3,542 boepd up 63% and 4Q was better still, funds flow was very impressive as was replacement of reserves which made revenue well worth reading and adjusted EBITDA was up 78%, again with a better final quarter. 

With $18m of cash that makes the balance sheet robust and ‘supports the aggressive capital program planned for 2025′ and as the company identifies makes for a ‘disciplined approach to capital allocation which allows Arrow to grow production while maintaining positive cash flow and a growing cash position’.

So, no surprise that CEO Marshall Abbott says that the company had the best year so far on all fronts, going forward there is yet more to get excited about. The drilling rig is now moving to the AB Llanos pad where two horizontal wells are imminent and then confidence remains high as they plan to ‘add an additional rig to drill wells at the RCE pad and additional wells in CN. 

Arrow is undoubtedly storing up a huge amount of value, whilst it must be irritating to management and shareholders that the share price doesn’t reflect this value it will surely at some stage be recognised. It may be that with a big and growing cash pile some sort of inorganic acquisition would be wise but might be difficult to find something accretive at these valuations, my TP remains at 75p. 

FINANCIAL AND OPERATING HIGHLIGHTS

(1) Non-IFRS measures – see “Non-IFRS Measures” section within this MD&A
(2) Long term restricted cash not included in working capital

2024 Year-End Reserves

Arrow has also filed on SEDAR, the Company’s Statement of Reserves Data and Other Oil and Gas Information, Report on Reserves Data by Independent Qualified Reserves Evaluator, and Report of Management and Directors on Oil and Gas Disclosure for the year ended December 31, 2024, as required by section 2.1 of National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (together, the “Reserve Report”).

To recap, the Company’s Year-End 2024 Company Working Interest Gross Reserves Highlights include:

• 2,384 Mboe of Proved Developed Producing Reserves (“PDP Reserves”)
• 5,805 Mboe of Proved Reserves (“1P Reserves”);
• 13,618 Mboe of Proved plus Probable Reserves (“2P Reserves”);
• 22,288 Mboe of Proved plus Probable plus Possible Reserves (“3P Reserves”)1;
• 1P Reserves estimated net present value before income taxes of US$115 million calculated at a 10% discount rate;
• 2P Reserves estimated net present value before income taxes of US$285 million calculated at a 10% discount rate; and
• 3P Reserves estimated net present value before income taxes of US$524 million calculated at a 10% discount rate.

Arrow refers readers to the Company’s press release of March 13, 2025 for additional details, as well as to the Reserve Report filed on SEDAR.

Discussion of Operating Results

The Company increased its production during 2024 mostly from new horizontal wells at the Carrizales Norte fields in the Tapir block. These have allowed the Company to continue to improve its operating results and EBITDA.  There has also been a decrease in the Company’s natural gas production in Canada due to natural declines.

Average Production by Property

The Company’s average production for the three months and year ended December 31, 2024 was 4,738 and 3,542 boe/d, respectively, which consisted of crude oil production in Colombia of 4,511 and 3,351 bbl/d, respectively, natural gas production of 1,332 and 1,119 Mcf/d, respectively, and minor amounts of natural gas liquids. The Company’s Q4 2024 production was 15% higher than its Q3 2024 production and 103% higher than Q4 2023.

Discussion of Financial Results

During Q4 2024 the Company continued to realize strong oil and gas prices, as summarized below.

(1) Non-IFRS measure

As at December 31, 2024, the Company reviewed its cash-generating units (“CGU”) for property and equipment and determined that there were indicators of impairment reversal in its Canada CGU and recognized an income of $662,753.

Operating Netbacks

The Company also continued to realize positive operating netbacks, as summarized below.

 (1) Non-IFRS measure

The operating netbacks of the Company maintained healthy levels during 2024 due to increased production from its Colombian assets, notwithstanding lower crude oil prices, which was offset by decreases in natural gas prices and higher operating expenses for natural gas.

During 2024, the Company invested $31 million of capital expenditures, primarily in connection with the drilling of 13 wells in the Tapir Block. This acceleration in operational tempo is expected to continue in 2025, funded by cash on hand and cashflow.

Touchstone Exploration

Touchstone has provided an update regarding the previously announced transaction to acquire the entire share capital of Shell Trinidad Central Block Limited (“STCBL”). 

As previously announced, on December 12, 2024, the Company’s wholly owned Trinidadian subsidiary signed a Share Purchase Agreement (the “Agreement”) to acquire 100 percent of STCBL from a third party (the “Acquisition”). STCBL holds a 65 percent operating working interest in the onshore Central block exploration and production licence, as well as four producing gas wells and a gas processing plant in Trinidad, with state owned Heritage Petroleum Company Limited holding the remaining 35 percent working interest. Under the terms of the Agreement, Touchstone will pay $23 million in cash plus closing cash and abandonment fund balances, and the Acquisition will be deemed effective as of January 1, 2025.

The parties have amended the Agreement to extend the long-stop date to May 12, 2025. Under the Agreement, the parties have until this date to satisfy or waive the conditions precedent, as applicable. Completion will occur on a mutually agreed date following the satisfaction of all conditions, which the Company expects to take place in the second quarter of 2025. All customary regulatory approvals have been received, and Touchstone has made significant progress with its current lender regarding the financing of the Acquisition.

For further information regarding the Acquisition and related advisories thereto, refer to the Company’s announcement dated December 13, 2024 entitled “Touchstone Exploration Announces the Acquisition of Central Block ” which is available under our profile on SEDAR+ (www.sedarplus.ca) and on our website (www.touchstoneexploration.com).

No assurances can be given that the Acquisition will ultimately be completed. Due to confidentiality terms in the agreement, Touchstone is not able to provide further information to the market on this Acquisition until the transaction is effectively closed, or terminated, as the case may be.

No surprise here that the long-stop date has been moved to 12th May 2025 as often these deals get bogged down in legals and it looks as if there isn’t a major problem. 

Southern Energy Corp

Southern has announced its fourth quarter and year end December 31, 2024 financial and operating results. Selected financial and operational information is outlined below and should be read in conjunction with the Company’s audited consolidated financial statements and related management’s discussion and analysis (the “MD&A”) for the three and twelve months ended December 31, 2024, as well as the Company’s annual information form for the year ended December 31, 2024, (the “AIF”), all of which are available on the Company’s website at www.southernenergycorp.com and have been filed under the Company’s profile on SEDAR+ at www.sedarplus.ca. 

All figures referred to in this news release are denominated in U.S. dollars, unless otherwise noted.

FOUTH QUARTER AND YEAR END 2024 HIGHLIGHTS

• Average production of 13,556[1] Mcfe/d (2,259 boe/d) (96% natural gas) during Q4 2024 and 15,264[2] Mcfe/d (2,544 boe/d) (96% natural gas) for the year ended December 31, 2024, a decrease of 19% and 6% from the same periods in 2023, respectively
• Petroleum and natural gas sales of $3.9 million during Q4 2024 and $16.1 million for the year ended December 31, 2024, a decrease of 23% and 17% from the same periods in 2023, respectively, largely due to a significant depreciation in commodity prices and initial decline from the new wells drilled
• Average realized natural gas and oil prices for Q4 2024 of $2.78/Mcf and $68.59/bbl, compared to $2.95/Mcf and $76.97/bbl in Q4 2023. Southern achieved an average premium of $0.22/Mcf (approximately 10% above the NYMEX HH benchmark) throughout 2024
• Generated $0.4 million of Adjusted Funds Flow from Operations[3] in Q4 2024 ($0.00 per share basic and diluted), excluding $1.1 million of one-time transaction costs, and generated $4.1 million for the year ended December 31, 2024 ($0.02 per share basic and diluted), excluding $1.3 million of one-time transaction costs
• Net loss of $3.7 million ($0.02 per share basic and diluted) and $11.5 million ($0.07 per share basic and diluted) for the three and twelve months ended December 31, 2024, respectively
• Reduced Net Debt3 for the year ended December 31, 2024 by $2.7 million from December 31, 2023
• On October 30, 2024, entered into the eighth amendment to the Company’s senior secured term loan (the “Credit Facility“), which included an extension to the pause of monthly repayment of principal to December 31, 2024 and a condition that Southern would repay a portion of the outstanding principal at January 31, 2025
• Monetized excess inventory equipment in 2024 for net proceeds of $3.4 millio

SUBSEQUENT EVENTS

• Effective January 31, 2025, Southern entered into the ninth amendment to the Credit Facility which included an extension to the pause of monthly repayment of principal to January 31, 2025 and reduced the repayment required from the eighth amendment to $1.45 million at January 31, 2025, which the Company paid (see “Liquidity and Capital Resources – Credit Facility” in the December 31, 2024 MD&A for full details of the amendment)
• Effective February 28, 2025, Southern entered into the tenth amendment to the Credit Facility, which amended the monthly repayment of the principal amount outstanding calculation beginning on February 28, 2025, to the aggregate principal amount then outstanding on all loans multiplied by 60% multiplied by the fraction 1 / A, where A equals the sum of the number of whole or partial calendar months remaining to the maturity date plus 24 months (see “Liquidity and Capital Resources – Credit Facility” in the December 31, 2024 MD&A for full details of the amendment)
• Effective March 31, 2025, Southern entered into the eleventh amendment to the Credit Facility. This amendment amended the asset coverage ratio down to 1.5x from 1.75x in 2025 and reduced Tranche B capacity to $5.0 million (see “Liquidity and Capital Resources – Credit Facility” in the December 31, 2024 MD&A for full details of the amendment)
• On April 8, 2025, Southern closed an equity financing raising aggregate gross proceeds of $5.0 million through the issuance of a total of 102,482,673 new units (see “Shareholders’ Equity – Share Capital” in the December 31, 2024 MD&A for full details)
• On April 8, 2025, Southern converted the remaining convertible debentures in the amount of $3.1 million into 62,759,286 new units and issued 1,627,170 new units for all accrued and unpaid interest (see “Liquidity and Capital Resources – Debenture Financing” in the December 31, 2024 MD&A for full details of the conversion)

Ian Atkinson, President and Chief Executive Officer of Southern, commented:
“Southern had a quiet year in the field in 2024 due to low natural gas pricing, which ended the year as the second-lowest in the past 24 years. The focus for Southern was balance sheet preservation, led by the monetization of excess inventory equipment for $3.4 million, reducing our abandonment liabilities by divesting non-core, non-producing wellbores during Q3 2024 and working with our credit lender to amend the Credit Facility to support the Company. We ended the year having reduced net debt and substantially decreased the burden of short term liabilities on our balance sheet, which in light of the operating environment was a positive achievement.

“Despite the market challenges, Southern has leveraged the strategic locations of its assets and sales points, achieving a $0.22/Mcf premium (~10% basis premium) over Henry Hub benchmark pricing in 2024. This premium has increased in Q1 2025 to $0.50/Mcf (~14%). Additionally, our financial hedge of 5,000 MMBtu/d at $3.40/MMBtu, which was initiated in Q2 2024, provided stable cash flows, enabling us to navigate ongoing volatility. Importantly, we have remained steadfast in sensible capital allocation in the field and have been disciplined to allow us future flexibility as commodity prices improve.

“As we enter 2025, market fundamentals continue to strengthen. Feed gas demand from LNG export facilities at Plaquemines and Corpus Christi are growing quickly with feed gas flows to Golden Pass LNG facility expected later this year. Domestic consumption is rising-driven by gas-fired electricity generation supporting data centers and transportation electrification as well as renewed growth in pipeline exports to Mexico. These dynamics are expected to tighten the U.S. natural gas balance in the coming quarters.

“Longer-term, the structural case for U.S. natural gas pricing remains intact as the U.S. has become the world’s largest exporter of LNG in the past few years at the same time as production growth in the U.S has slowed with upstream producers focusing on fiscal conservatism ahead of growth.

“We remain focused on leveraging our strategic position and disciplined operations to deliver sustainable growth and enhance long-term shareholder value by using the net proceeds from the recently closed equity financing to re-ignite our growth plan. As we navigate the year with a strengthened financial position and several exciting operational growth catalysts coming up, we look forward to keeping the market updated and thank our shareholders for the support in the year.”

CEO Ian Atkinson has it dead on, these historic figures report on a low price scenario and one in which Southern hunkered down and as they emerged recently to raise money and prepare to take advantage of what looks like ‘better market fundamentals’. 

For this scenario Southern is well poised to do very well, its portfolio perfectly constructed to take advantage of these fundamentals and also the huge potential growth in LNG exports from the US. My TP of 150p might give you vertigo but not when you consider the huge upside possible to the company, a cracking company with a fine management and great prospects. 

Prospex Energy

Prospex wishes to inform shareholders that it has been advised by the Operator of the Viura field, HEYCO Energia Iberia S.L, of the temporary cessation of production of the new Viura-1B well due to a leak in the completion tubing.  The Operator is sourcing the necessary equipment including mobilising a suitable drill rig to perform the workover with the aim of reinstating production from the field by mid-June 2025.  Although this is a temporary halt to production, it will have an impact on the stated schedule for drilling the development wells, which is now anticipated to take place next year.

Prospex owns 7.24% of the Viura field through its ownership of 7.5% of HEYCO Energy Iberia S.L. (“HEI” or the “Operator”).  Prospex is accruing 14.47% of the production income from the Viura gas field until payback of its capital investment (expected to be ≈£8 million) plus the accrued 10% p.a. interest thereon.

Mark Routh, Prospex’s CEO, commented:
“This is an unfortunate temporary cessation of production at Viura while the operator mobilises the necessary equipment to carry out the required interventions and workovers to re-establish stable gas production from the Viura gas field.

“It is important to re-establish stable gas rates from Viura before the drilling of the new development wells commences in order to optimise the financing options for phase 2 of the development drilling campaign.  We have every confidence in the Operator, who can access state-of-the-art technologies and expertise both in country and from the USA, to deliver the optimum outcome of the workover interventions and more importantly the future development well drilling.  One benefit arising from the disruption to production at the field and the resultant delay to the development drilling it is that it provides Prospex with more time to generate cash from its other producing assets and fund our share of expenditure at Viura reducing the need to source additional funding from the market.

“I will keep shareholders updated with regular progress reports as the well interventions proceed.”

This is indeed a real disappointment for Prospex as the leak in the completion tubing not only ceases production at Viura but also delays the ongoing development drilling scheduled for later this year and will now likely happen next year. 

Today’s price fall has taken Prospex back to the low for the year, probably a bit harsh especially as Mark Routh has said that it gives him more time to generate cash elsewhere and therefore won’t need a raise anytime soon. I have been getting more positive about Prospex lately and whilst this is undoubtedly a modest setback I’m not going to change my mind now. 

Background

The Viura-1B well is currently not in production and was shut in during April-2025 owing to a leak in the completion tubing which requires a rig intervention to reinstate production.  The Operator is now sourcing the necessary equipment including mobilising a suitable drilling rig in order to perform the workover by mid-June 2025.

Total natural gas produced from the Viura-1B well from start-up in December 2024 to the end of Q1-2025 was 0.528 Bcm = 18.6 Bcf which is 77 Bcm = 2.7 Bcf net to Prospex.

Whilst the rig is on site in June-2025 the Operator also plans a workover on the original producing well, Viura‑1ST3 which is not currently in production.  The Viura‑1ST3 workover is in order to shut off a water zone to prevent produced water ingress from deeper in the reservoir flowing to the top producing zones in the new well Viura-1B.  Decreasing water production into the processing plant will reduce operational costs.  Following this workover the Viura‑1ST3 well will not produce gas without further intervention.  As advised in the RNS of 8 April 2025, the Viura-3 water injection well is capped and suspended as it has been deemed unsuitable for water injection.

As a result of these necessary workovers, the schedule of drilling the Phase 2 wells Viura-3A and Viura‑3B has been pushed back to 2026.  This will allow further time for the Operator to procure the necessary equipment and to optimise the 3D seismic reprocessing and reinterpretation to fine-tune the subsurface well locations of these development wells.

The Operator will recommence negotiations with the syndicate of banks to provide debt-finance towards the cost of drilling the development wells upon the resumption of production from well Viura‑1B.

The Operator is also planning to test in Q1-2026 the hitherto untested Utrillas-B reservoir, which sits below the main Utrillas-A reservoir horizon and which was identified as containing the presence of gas bearing reservoir quality sandstones in December 2024.

Star Energy

Star has announced Full year results for the year ended 31 December 2024

Commenting today, Ross Glover, Chief Executive Officer, said:
“I am very pleased to be presenting my first annual results as Chief Executive Officer of Star Energy. Our strategic aim is to be a profitable energy business generating strong cashflows from our oil and gas assets whilst progressing growth opportunities in the geothermal sector. By focusing on maximising profitability from our oil and gas activities, we ensure long-term sustainability and can successfully navigate a volatile oil price environment, which is increasingly important in today’s uncertain geopolitical climate. We have maintained strong production across our fields and made good progress in reducing costs, with substantial general and administrative savings projected for 2025.

Investing in our producing assets provides a robust financial foundation for future growth, and I am confident that geothermal energy presents a significant growth opportunity in both the UK and Europe. Successful project development will create material incremental asset value and can deliver strong returns for shareholders. We recognise that it will take time to bring our geothermal projects to production and are committed to rigorously assessing project commerciality in order to allocate capital based on strict criteria for achievement of milestones and creation of value. This approach will enable us to build a portfolio of profitable projects over time.”

Ross Glover was dealt a tricky old hand on arrival as CEO as previous management had left the company in the relegation zone and he has done well just to get here. Production down, revenue down, losses up and net debt higher reads badly and the geothermal portfolio hardly makes exciting reading. But he has his chances and will give it everything he has, he will at least be able to say that he gave it all he had….

Financial Performance

* Adjusted EBITDA, Net Debt (borrowings less cash and cash equivalents excluding capitalised fees) and Underlying Operating Profit are used by the Group, alongside IFRS measures for both internal performance analysis and to help shareholders, lenders and other users of the Annual Report to better understand the Group’s performance in the period in comparison to previous periods and to industry peers 

Corporate & Financial Highlights

• Successfully secured a €25 million financing facility provided by Kommunalkredit Austria AG which, while primarily supporting the development of our geothermal energy sector, also enables continued investment in the oil and gas business utilising existing cash flows
• Cash at 31 December 2024 was £4.7 million, excluding restricted cash, and Star Energy had drawn £12.2 million under its loan facility. Restricted cash was £4.3 million and relates to the cash backing of performance bonds for licence commitments of the Company’s Croatian subsidiary relating to the Sječe and Pčelić exploration licences
• Increased our stake in our Croatian subsidiary post year end, from 51% to 71%, allowing us to control the development of this initiative until appropriate value inflection points are achieved
• Exchanged contracts for the sale of non-core land for £6.3 million in November 2024 with proceeds received in April 2025
• Hedging in place for 400bbl/d for H1 2025 and H2 2025 with swaps at an average price of $79.8/bbl and $73.0/bbl, respectively
• Energy Profits Levy of £1.0 million paid in February 2025 based on the taxable profits for the year ended 31 December 2023. The Company estimates a charge of £2.1 million for 2024

 Operational Highlights

• Net production, in line with guidance averaging 1,989 boepd in 2024 (2023: 2,100), with uptime across the portfolio remaining strong over the year
• Continued to optimise oil production from our existing wells through selective investment in short cycle developments which deliver quick payback
• DeGolyer & MacNaughton updated CPR  values 2P NPV10 at $188 million (2023: $235 million). The decrease in reserves value is due to a development project moving out of the reserves category due to project prioritisation
• Work has begun on the Singleton gas-to-wire project which will deliver c.74 boe/d, utilising gas which is currently being flared. The project, which satisfies the regulatory requirements for the facility, now has planning consent and a secured grid connection. Procurement for long lead items is underway, with a first export of electricity from the site expected late 2025
• Ernestinovo licence commitments have been fulfilled and the acquisition of magnetotelluric data across the Sjece and Pcelic geothermal licence blocks in Croatia is complete, with the incorporation of this data into the geological models underway.  Work is ongoing on the technical analysis to rank the optimal sequencing of their commercial development
• Seismic data was acquired and analysed for the Salisbury NHS Foundation Trust project, and pre-applications have been submitted for planning and permitting for both Salisbury and the Wythenshawe Hospital projects

Outlook

• We anticipate net production of c.2,000 boepd and operating costs of c.$40/boe (assuming an average exchange rate of £1:$1.27) in 2025
• 2025 forecast capital expenditure is c.£10.0 million. This includes £5.8 million on the Singleton gas-to-wire project which is forecast to come online in late 2025 with production of 74 boe/d. Star Energy also plans to invest £1.7 million on quick returning incremental projects and the balance on regulatory improvements, site resilience and projects to reduce operating costs going forward
• Holybourne sale proceeds of £6.3 million will be used to repay Facility A of our Kommunalkredit loan which is due on 30 June 2025
• Good progress on G&A costs reduction expected to generate savings of c.£1.5 million in 2025
• Data analysis continuing to further derisk our Croatian portfolio
• Seeking strategic partnerships in the UK to advance our pipeline

 Original article   l   KeyFacts Energy Industry Directory: Malcy's Blog