WTI (July) $72.67 +84c,  Brent (July) $77.07 +12c, Diff -$4.40 -3c
USNG (June) $2.18 +12c, UKNG (June) $54.8p -3.2p, TTF (July*) €24.575 -€1.02 *
*June contract TTF Expiry

Oil price

Oil has fallen sharply today as Washington panics about the debt ceiling talks, an extra few days until Monday 5th has been allowed.

PetroTal Corp

PetroTal is pleased to report the technical working table committee for the 2.5% Block 95 community social trust fund has approved bylaws governing and regulating the social trust. This was a required follow up step from the March 9, 2023 announced publication of the Supreme Decree, signed by Peru’s President authorising Petroperu to execute the amendment incorporating the 2.5% social trust to the Block 95 license contract.

The approval of the by-law regulations was a result of constant and coordinated efforts between members of the working table committee and the population of Puinahua with its regional governance members. Outlined in the regulation is the establishment of a formal Board of Directors led by representatives from the Government of Peru, PetroTal, and groups representing the local population near the Bretana oil field.

Canon(1) Redistribution
The Peruvian Economic Commission of Congress has approved the redistribution of the Canon for the Loreto region. If approved by the Executive, as expected, the share of the Canon going to the Loreto producing district should increase approximately six times starting in 2024. This would allow the Puinahua Municipality to increase its budget and, together with the 2.5% social trust fund, make a significant impact on the lives of the Puinahua district population.    

(1) Canon is the method used by the central government to allocate funds back to various producing regions and communities in Peru.

Kistos

Kistos has provided a summary of its audited full-year results for the year ended 31 December 2022. A copy of the Company’s full audited annual report and accounts will be made available shortly on the Company’s website at www.kistosplc.com.

2022 Highlights

• On a pro forma basis, the Group production averaged 10.6 kboe/d (2021: 4.3 kboe/d), reflecting a full-year contribution from the Q10-A gas field offshore the Netherlands, and almost six months production from the Greater Laggan Area (“GLA”) offshore the UK.
• Adjusted pro forma EBITDA, which includes a full 12-month contribution from the GLA, was €517.2 million (2021: €102.9 million).
• Completed the acquisition of a 20% interest from TotalEnergies E&P UK Limited in the GLA, more than doubling Kistos’ net daily production.
• Year-end 2P reserves of 12.7 MMboe increased to 36.3 MMboe on completion of the Mime Petroleum A.S. (“Mime”) transaction.

12 months ended 31 December 2022

1. Pro forma figures include the GLA as if it had been acquired on 1 January 2022. The acquisition completed on 10 July 2022. Pro forma figures for 2021 include the results of Kistos NL1 and Kistos NL2 as if they had been acquired on 1 January 2021.
2. Comparative information has been restated to align with current year allocation methodology.
3. Total production rate includes gas, oil and natural gas liquids and is rounded to the nearest 100 barrels of oil equivalent per day. Actual production rates include impact from acquired businesses only from date of acquisition completion.
4. Non-GAAP measure. Refer to Appendix B to the financial statements for definition and calculation.
5. Certain pro forma equivalents are not applicable or meaningful. The GLA acquisition comprised the purchase of interests in an unincorporated joint arrangement with no pre-existing IFRS income statement, balance sheet or cash flow statement from which to derive pro forma information.

Financial
Strong cash generation in both halves of the year, with movements in gas prices and production rates offsetting each other

• Profit after tax of €73 million, including €44 million of impairment charges relating to exploration assets in the Netherlands, €27 million of gains from changes and releases in acquisition contingent consideration balances, and a total tax charge of €228 million.
• The tax charge (resulting in an effective tax rate for 2022 of 89.8%) includes impact of the Energy Profits Levy in the UK and the EU Solidarity Contribution Tax in the Netherlands.
• Cash balances on 31 December 2022 of €212 million (31 December 2021: €77 million) and net cash of €130 million (31 December 2021: net debt of €73 million).
• Retired 46% of outstanding debt by repurchasing €68 million of Nordic Bonds, leaving €82 million outstanding.
• Capital expenditure on a cash basis, excluding business acquisitions, was €19.5 million.

Operational

Increasing the Group’s production base with organic and inorganic growth

• Year-end 2P reserves of 12.7 MMboe increased to 36.3 MMboe on completion of the Mime Petroleum A.S. (Mime) transaction.
• Drilling of the Benriach exploration well (Kistos 25%) approved and was spudded in March 2023.
• Estimated Scope 1 CO2 emissions from our operated activities offshore were less than 0.01 kg/boe in 2022 (excluding necessary flaring during drilling campaigns)

Outlook
Transforming Kistos into an influential independent North Sea E&P across three proven energy markets

• Mime acquisition completed in May 2023, adding 2P reserves of 23.6 mmboe and 2,000 boe/d of production in 2023, increasing to over 15,000 boe/d in 2025 once the Jotun FPSO is on-stream.
• The Mime acquisition provides a platform for growth on the Norwegian Continental Shelf
• Kistos is ready to sanction the Edradour West and Glendronach developments in the GLA (subject to JV partner approval), utilising investment allowance under the terms of the UK Energy Profits Levy. If approved, Edradour West development programme anticipated to commence by year-end 2023. 

Andrew Austin, Executive Chairman of Kistos, commented:
“Kistos’ accelerated evolution over the course of 2022 has been driven by targeted value-accretive acquisitions which have provided both immediate and longer-term upside for the Group. Our entry into the UKCS, followed this year by Norway, has created a diversified and flexible portfolio across multiple jurisdictions.

The Group benefited from strong commodity prices resulting in significant cash generation, which will allow us to continue to capitalise on the exploration, appraisal, and development opportunities within our portfolio. However, these strong commodity prices have resulted in authorities imposing so-called windfall taxes on our operations. This is difficult to comprehend, given that greenhouse gas emissions associated with imported hydrocarbons are typically much higher than those associated with those produced locally. This tax instability has already resulted in Kistos and companies with international asset portfolios cancelling or scaling back North Sea projects and diverting capital elsewhere, with significant implications for local energy security of supply.

In particular, the imposition of the retrospective and regressive Solidarity Contribution Tax on our Netherlands profits means that the Group, and other energy industry participants in the EU, will find it difficult to justify future material investments and developments due to the risk of confiscation of profits should oil or gas prices rise again. We believe our Dutch subsidiary is out of scope of the charge, but have nonetheless made a provision for it in these results, pending further clarification and the outcome of legal challenges from other parties.

From a standing start in 2020, we have built an excellent platform, and we will seek to deploy further capital in the right opportunities or make distributions to shareholders. The instability of the fiscal regimes in which we operate has prompted us to review our investment options and, as we have already demonstrated with our entry into Norway, our pipeline of business development opportunities includes assets in jurisdictions other than the UK and the Netherlands in which we can continue to generate substantial returns for investors.”

I find it appropriate that Andrew Austin comments so deliberately about the tax situation in both the UK and the Netherlands and why the company has elected to make their next strides in Norway.  But what is interesting is that the investments that the company has made up until now include some of the best and most valuable of modestly sized assets.

Comparable early life assets like the Greater Laggan Area and others in the same shape will prove to be worth their weight in gold and it is a shame that more acquisitions will be made but not in this country where ironically our own hydrocarbons will not be used but those with higher carbon footprints from overseas will…To be continued…

Arrow Exploration Corp

Arrow has provided an update on the Carrizales Norte-1 well (“CN‑1”), an exploration well on the Tapir Block in the Llanos Basin of Colombia.

CN-1
The CN-1 well was spud on May 1, 2023 and reached target depth on May 11, 2023.  CN-1 targeted a three-way fault bounded structure with multiple high-quality reservoir objectives on the Tapir Block in the Llanos Basin of Colombia. The well was drilled to a total measured depth of 9,190 feet (8,511 feet true vertical depth) and encountered 148 feet of cumulative net oil pay (128 feet TVD).

Arrow has completed the first test on the CN-1 well in the Ubaque formation which has approximately 58 feet of net oil pay. The pay zone is a clean sandstone exhibiting consistent 30% porosity and high resistivities. A submersible pump has been inserted in the well after perforating.

Specific data for the production test on the Ubaque formation were as follows:

• The production test was run over a 58-hour period.
• The well was tested at three different flow rates to evaluate productivity and to plan for water cut management.
• The first flow period was held for 23 hours and showed an average oil rate of 491 bopd gross.
• The second flow period was for 18 hours and showed an average oil rate of 861 bopd gross, and,
• The third flow period was held for 17 hours and showed an average oil rate of 1134 bopd.
• Oil production tested at a peak rate of 1,222 bopd, and a final stabilized rate of 1,134 bopd

In the final 24 hours of the test, CN-1 produced at a rate of 1,134 bopd gross (567 bopd net) of oil at 13.5 API and with a 28.3 % water cut (completion fluid). Water cut has been decreasing throughout completion testing. Additional tests of the Gacheta and C7 formations will proceed over the coming weeks, with production forecast to commence in the second half of June 2023. The Carrizales Norte-2 (CN-2) well will be drilled immediately upon the CN-1 well being brought on-stream.

Initial production results are not necessarily indicative of long-term performance or ultimate recovery.

Marshall Abbott, CEO of Arrow commented:
“The Carrizales Norte-1 discovery and the Ubaque test are extremely important and material events for Arrow. The Ubaque test – the first on the Carrizales Norte field – shows that oil from the formation can be produced at high rates using conventional means. The test is further evidence of the potential of the Tapir block in the prolific Llanos Basin.”

“After a brief flow and pressure build-up on the Ubaque, Arrow plans to completion test additional pay zones in the Gacheta and C7 reservoirs over the coming weeks and then make a decision on which zone to bring on production initially.”

“Our expectation is that the Carrizales Norte wells will be quick to payout in the current oil price environment with triple digit IRRs, providing positive cashflow for the Company. This is a very exciting time for Arrow, and we look forward to providing further updates on our progress.”

This was another success from Arrow as the Carrizales Norte comes good particularly with the success from the Ubaque which wasn’t already booked and also may mix with the lighter C7 and Gacheta and produce at higher rates than previously expected. After that testing the rig moves to CN-2 and we start all over again, Arrow are making this job of drilling in time and below budget looking quite easy and we will soon see ratings increases. 

The associated results were ahead of expectations and in particular the formidable cash generation runs ahead of whatever the company spends and therefore the programme is paid for with plenty to spare. It is very tempting to increase my target price but right now the 50p that I have been carrying for some time looks good if somewhat conservative…

Results below…

Arrow also announces announces the filing of its Interim Condensed Consolidated Financial Statements and Management’s Discussion and Analysis (“MD&A”) for the quarter ended March 31, 2023 which are available on SEDAR (www.sedar.com) and will also shortly be available on Arrow’s website at www.arrowexploration.ca.

Q1 2023 Highlights:

• Recorded $6.9 million of total oil and natural gas revenue, net of royalties, more than double compared to 2022 (Q1 2022: $3.4 million).
• Adjusted EBITDA of $4.3 million, more than seven times compared to 2022 (Q1 2022: $0.6 million).
• Average corporate production up 43% to 1,635 boe/d (Q1 2022: 1,144 boe/d).
• Realized corporate oil operating netbacks of $58.31/bbl due to increased production allowing operating cost to be spread over more barrels.
• Cash position of $12.3 million at the end of Q1 2023.
• Generated positive operating cashflows of $2.4 million (Q1 2022: negative $0.1 million).
• Drilled three successful wells at Rio Cravo Este (RCE) resulting in material production additions.

Post Period End Highlights:

• The Carrizales Norte-1 (CN-1) well has been drilled and reached its target depth, and is currently under production testing.

Outlook

• Arrow anticipates two additional wells to be drilled at Carrizales Norte by year-end.
• Arrow anticipates two additional wells at RCE by year-end to target the Gacheta formation which was successfully tested at commercial rates in RCE-2.
• Arrow plans to drill two development wells at the Oso Pardo Block in the Middle Magdalena Basin.

Marshall Abbott, CEO of Arrow Exploration Corp., commented:
“Arrow has had a strong start to 2023, including the drilling of three RCE wells and the CN-1 well, which is expected to have a significant impact on the Company’s production and reserves, as well as establishing a new core area. The 3D seismic West Tapir project has completed shooting, is currently being processed and is expected to further evaluate the 2D recognized fault prospects. The Arrow Team continues to strive towards excellence and increasing shareholder value.”

FINANCIAL AND OPERATING HIGHLIGHTS

1. Non-IFRS measures – see “Non-IFRS Measures” section of the  MD&A
2. Long term restricted cash not included in working capital 

DISCUSSION OF OPERATING RESULTS

The Company maintained its overall production and continued improving its operations. This has allowed the Company to continue to improve its balance sheet and its business profile.  In early 2023, the Company increased production on its Tapir block through drilling the RCE-3, RCE-4 and RCE-5 wells, offset by the current production shut in at its Ombu block. There has also been a decrease in the Company’s natural gas production in Canada due to natural declines.

 Average Production by Property

For the three months ended March 31, 2023, the Company’s average production was 1,635 boe/d, which consisted of crude oil production in Colombia of 1,222 bbl/d, natural gas production of 2,459 Mcf/d and minor amounts of natural gas liquids from the Company’s Canadian properties. The Company’s Q1 2023 total production was 43% higher than its total production for the same period in 2022.

DISCUSSION OF FINANCIAL RESULTS

During Q1 2023 the Company continued to realize strong oil prices, offset by decreased gas prices, as summarized below:

(1) Non-IFRS measure

OPERATING NETBACKS

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

 (1) Non-IFRS measure

The operating netbacks of the Company continued improving in 2023 due to increasing production from its Colombian assets, and consistent crude oil prices, which were offset by decreases in natural gas prices and increases in royalties and operating expenses for natural gas.

During Q1 2023, the Company incurred in $4.3 million of capital expenditures, primarily in connection with the drilling of the three RCE wells, civil works completed in Rio Cravo and shooting 100 km2 of 3D seismic in the Tapir block to highlight existing leads and prospects for drilling. This acceleration in operational tempo is expected throughout 2023, funded by cash on hand and cashflow.

ARROW PARTICIPATING INTEREST IN THE TAPIR BLOCK

By way of a private commercial contract with the recognized interest holder before Ecopetrol S.A., Arrow is entitled to receive 50% of the production from the Tapir block. The formal assignment to the Company is subject to Ecopetrol’s consent.

Southern Energy Corp

Southern Energy has announced its first quarter financial and operating results for the three months ended March 31, 2023. Selected financial and operational information is outlined below and should be read in conjunction with the Company’s unaudited consolidated financial statements and related management’s discussion and analysis for the three months ended March 31, 2023, which are available on the Company’s website at www.southernenergycorp.com and have been filed on SEDAR.

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

FIRST QUARTER 2023 HIGHLIGHTS

• Generated $1.7 million of adjusted funds flow from operations[1] in Q1 2023 ($0.01 per share basic and diluted)
• Net loss of $1.1 million in Q1 2023 ($0.01 loss per share basic and diluted), compared to a net loss of $1.9 million in Q1 2022
• Petroleum and natural gas sales were $5.2 million in Q1 2023
• Maintained balance sheet strength with net debt1 to adjusted funds flow from operations ratio of 1.2x on a trailing twelve month basis down from 2.6x in the first quarter of 2022
• Average production of 15,643 Mcfe/d[2] (2,607 boe/d) (95% natural gas) during Q1 2023, an increase of 36% from the same period in 2022
• Average realized natural gas and oil prices for Q1 2023 of $3.25/Mcf and $75.73/bbl, respectively, reflecting the benefit of strategic access to premium-priced U.S. sales hubs in a geographic region with strong industrial and power generation natural gas demand
• Drilled six net wells at Gwinville in Q1 2023 from three padsites, with each subsequent pad drilling operation resulting in fewer drilling days per well depth adjusted

2022 Year End Reserves Upgrade:
Highlights of the Company’s year end independent oil and gas reserves evaluation as at December 31, 2022 (the “NSAI Report”) prepared by independent qualified reserves evaluator Netherland, Sewell & Associates, Inc. (“NSAI”) include:

• an increase in proved developed producing (“PDP”) reserves of 25% to 6.2 MMboe
• an increase in total proved (“1P”) reserves of 44% to 14.1 MMboe
• an increase in total proved plus probable (“2P”) reserves by 31% to 25.5 MMboe in 2022
• before-tax net present value (“NPV”) of 2P reserves, discounted at 10% (“NPV10”), of $142.5 million (an increase of 61% on year end 2021) 
• Top performing energy stock in the 2023 TSX Venture 50™ based on equal weighting of performance during 2022 across three key indictors: market capitalisation growth, share price appreciation, and trading volume

SUBSEQUENT EVENTS

As announced on May 23, 2023, Southern entered into a strategic and highly synergistic purchase and sale agreement to acquire ~400 boe/d (99% natural gas) for cash consideration of $3.2 million in Gwinville with an expected close date of June 1, 2023 

Ian Atkinson, President and CEO of Southern, commented:
“Q1 2023 was a great operational quarter for Southern as we wrapped up our seven horizontal well drilling program at Gwinville, with improved drilling time and cost efficiencies, which will lead to future cost savings when we re-ignite our organic growth at more supportive commodity prices. We are encouraged by the outlook of supply and demand dynamics for U.S. natural gas and are well set to immediately capitalize on gas prices with production behind pipe which can be brought on stream in a very short time scale. Additionally, we are extremely excited to consolidate the Gwinville field with the recently announced asset Acquisition. This Acquisition, which will be seamlessly incorporated with our current operations and staff, provides significant cost synergies, stable, low-decline production and additional high quality drilling locations to compliment our current drilling inventory. These are precisely the type of accretive transactions that we are looking for to expedite reaching our goal to reach 25,000 boe/d. As a low-cost producer attracting premium pricing, we feel that we have the right assets in the right locations that will provide long term value to shareholders and continue to look for further comparable opportunities.”

I wrote in some detail last week about Southern after the PetroTx deal, so these results add little new but when offered a ride in such a comfortable, well managed and efficient vehicle you don’t want to get off. The synergies offered by that acquisition are literally breathtaking and when the HH price starts to rise as it surely will, Southern will prove that it is the most efficient in the trade with a portfolio to die for. 

While it might seem an odd time to increase my Target Price I am full of confidence in Ian Atkinson and his team and I am on a promise to have an interview with him when he next visits these shores, that will be a must watch bit of broadcasting I’m, sure…

Financial Highlights

Operational Update
On March 29, 2023, the Company concluded operations on the current drilling campaign which included seven new horizontal wells into three separate productive horizons from three distinct padsites in the Gwinville Field.  The program added three Upper Selma Chalk wells, two Lower Selma Chalk wells and two City Bank wells. The drilling campaign was initially planned for 13 horizontal wells, but the Company paused the capital program in response to the weaker natural gas pricing in the first quarter of the year to maintain balance sheet discipline.  

Southern is extremely happy with the field execution performance from this program, highlighted by drilling efficiencies which saw the average time from spud to total depth of the Selma Chalk wells reduced from approximately 20 days in Southern’s three well appraisal program in 2022 to below 10 days by the final padsite in Q1 2023. The majority of the wells in the program came in at or below the initial drilling and completion cost estimates, despite more than 80% of the cost structure being fixed due to long term contracts for materials and major services locked in during the highly inflationary second half of 2022. With the learnings and efficiencies achieved in this campaign, Southern is planning for all future horizontal drilling in Gwinville to utilize an optimized wellbore design change that will remove the intermediate casing string and all associated costs which the Company expects will reduce the per-well drilling costs by 20-25%. This will allow the Company to reinitiate its organic growth plans at lower future gas prices than what was previously contemplated.  

Comparing key performance indicators from the drilling and completion operations in this program to the appraisal program from 2022, Southern achieved a 6% reduction in drilling costs per lateral foot (down to $644/ft) and a greater than 22% reduction in completion costs per lateral foot (down to $615/ft). Further, compared to the early generation horizontal activity between 2005 and 2009 on the asset by the previous operator, one of the largest independent upstream oil and natural gas companies in the U.S., on an inflation adjusted basis, Southern achieved a greater than 30% reduction in both drilling and completion costs per lateral foot.

The Company continues to flow back its first City Bank Hz well at Gwinville 18-10 #1, with load fluid recovery of approximately 13%. Based on historical vertical and early generation horizontal well completions in the City Bank reservoir in Gwinville, peak gas rates are not expected until the load fluid recovery is closer to 20+%, which is expected to be towards the end of Q2 2023. Gas rates are encouraging and continue to improve and Southern is excited to provide further operational updates in Q2 2023 as the modern generation City Bank type curve results are established. 

Remediation plans for the 18-10 #3 Upper Selma Chalk well that experienced a mechanical integrity issue with the production casing during completion operations continue to be finalized, with field execution expected in late Q2 2023. The 18-10 #3 well was drilled to a total lateral length of 5,091 ft, achieved 80% of the lateral placed in the targeted porosity zone and was successfully completed in 44 stages prior to the mechanical issue.

The four wells that are awaiting completion include the first two Lower Selma Chalk laterals, along with the second City Bank lateral and one Upper Selma Chalk lateral. These four wells are some of Southern’s longest laterals to-date. They were drilled with an average lateral length of approximately 5,400 ft and were steered within the high-graded intervals for an average of 95% of the wellbore length. The two padsites can be brought on production within a matter of weeks once completion operations are resumed. At current strip pricing, Southern could commence completion operations in Q4 2023.         

Outlook

With a moderated capital program due to low commodity prices, Southern has left four drilled, uncompleted wells (“DUCs”) that can be quickly completed and brought online through Southern’s 100% owned equipment at higher natural gas prices. After closing the above-mentioned Acquisition anticipated on June 1, 2023, Southern expects to have approximately $14.5 million of unused capacity on its senior secured term loan (the “Credit Facility”), which can be utilized to complete the DUCs at supportive natural gas prices.

As part of its risk management and sustainability strategy, Southern has entered into both a fixed basis and a fixed price swap in order to mitigate some of the volatility of the natural gas prices going forward. In Q1 2023, Southern entered into a basis swap transaction to secure a premium to NYMEX of $0.32 per MMBtu on 1,000 MMBtu/d from April 1, 2023 to October 31, 2023. Subsequent to March 31, 2023, Southern entered into a fixed price hedge on 1,000 MMBtu/d of production at a price of $3.88/MMBtu from January 1, 2024 to December 31, 2025. To further protect against the volatility, the Company continues to monitor the basis differential prices and is prepared to hedge additional basis exposure at elevated basis premiums.

Southern thanks all of its stakeholders for their ongoing support and looks forward to providing future updates on operational activities and continuing to create shareholder value.

Hunting

Hunting has announced that its Asia Pacific operating segment has won a new, significant Oil Country Tubular Goods contract that management estimates to be worth up to $91 million with Cairn Oil and Gas, Vedanta Limited, for its operations in Rajasthan, India. The contract is for an estimated 100 wells and is to extend up to three years. The OCTG will be supplied with Hunting’s proprietary SEAL-LOCK XDTM premium connection.

This order, again, breaks Hunting’s record for the largest single order received for the Group’s OCTG and premium connections and supports management’s belief that international market sentiment remains extremely strong as governments and countries address the challenges of energy security, the development of domestic supply and post-COVID economic recovery.

2023 Full Year Guidance
Based on the timing of the first deliveries of this order, management now believes that 2023 full year EBITDA will be in the range of $92-$94 million, which represents a further increase to the guidance issued at its 2022 full year results in March 2023. Management also believes that the year-end guidance for cash and bank remains unchanged.

Commenting on trading, Jim Johnson, Chief Executive, said:
“Hunting’s successful run of significant OCTG and Subsea orders since H2 2022 demonstrates that our technology and global footprint is well positioned to deliver significant growth in the medium term. US market activity remains stable and with the orders received for China, Guyana, Brazil and now India, Hunting continues to see a strong growth profile given our standing and recognition with major energy companies, coupled with the strong international market sentiment being reported in many regions.”

Hunting has done it again and as I have pointed out at every opportunity in recent months the company is delivering the goods time and time again. Yet the market is still not convinced that these are earnings of significant quality and achieved in a number of markets.

With this order, Hunting’s sales order book now is c.$575 million, which represents a material increase since the year-end and given what they have said about product pricing recently I would wager that next time we hear about margins we will be pleasantly surprised.

Given that the management conclude that the ‘international market is extremely strong’ I would expect the shares to rally at least to the 350p level if not more, after all the rating is hardly demanding. 

Angus Energy

Further to the announcement of 15 May 2023, Angus Energy (AIM: ANGS) is pleased to announce that production at the Saltfleetby Field has reached a steady operating state from the 3 producing wells in the field, B2, A4 and the new B7T.

After a short duration plant outage, we are now exporting gas to the National Grid at a combined average daily rate of 9.5 mmscfd, reaching peak flows of over 10 mmscf. The new B7T well continues to clean-up and the Company anticipates exceeding a combined average daily rate of 10 mmscfd, on a sustainable basis.

We have seen gas prices falling back to lower summer levels over recent weeks, but winter 2023-2024 pricing is strong, with forecasted prices at £1.24 per therm on Heren NBP published trading data. On the basis of continued production at this level, known hedge prices and published market forward prices we should be generating approximately £2.5 million of revenues on average each month for winter 2023 from Saltfleetby.

Potential Future Drilling and Gas Storage
Angus continues to evaluate storage opportunities at Saltfleetby variously for natural gas, hydrogen and CO2.  To advance this, the Company has also engaged planning consultants to submit a further planning permission for an expanded site at Saltfleetby to encompass a number of new wells and process plant.

The drilling will initially address the Namurian reservoir, below the presently exploited Westphalian, as a commercial source of natural gas but wells will also be designed to be repurposed as potential injection wells for gas storage, whether in the Namurian or Westphalian, and for which further planning permissions at national level would be sought if deemed appropriate.

Furthermore, following on from the pioneering use of hydrogen tight Soluforce pipe in the first commercial transmission grid connection at Theddlethorpe Entry Point, Angus will be exploring the design parameters around the management of hydrogen or CO2 at high pressures, alongside traditional storage of natural gas.

The Namurian reservoir, which sits below the Westphalian from which the Company currently extracts natural gas, has produced 1.5 bcf to date but a very wide variation of gas in place exists between our own recent CPRs and internal estimates by previous Operators, Gazprom-Wintershall and Roc Oil.  To date no detailed interpretation of the Namurian, independent from the Westphalian, has been undertaken and accordingly a full third party re-interpretation of both reservoirs is presently underway, expected to complete in October.

In 2006 Gazprom-Wintershall estimated the storage capacity of the overall field to be between 700 and 800 million cubic metres, making it easily the largest onshore storage facility in the UK.  Estimates by Angus of storage capacity are somewhat higher and do not include the Namurian.

Richard Herbert, CEO, writes: 
“The Company is pleased to have reached this production milestone and to be able to turn attention to both organic and inorganic growth opportunities.  Gas storage is an obvious and topical one.  Properly engineered to manage H2 or CO2 as well as natural gas, storage at Saltfleetby has the potential to meet the twin demands of present and future administrations for clean energy and energy security and we are pleased to be able to align shareholder interests with those longer term goals whilst offering the possibility of enhanced gas recoveries in the medium term.”

The fact that Angus are exceeding a combined average daily rate of 10 mmscfd, on a sustainable basis is an important milestone and the longer term strip for the winter reads pretty well.

Add to this the potential for further drilling has led management to also engage planning consultants to submit a further planning permission for an expanded site at Saltfleetby to encompass a number of new wells and process plant. You never know, it could be the next gas storage site which would add further value. 

Longboat Energy

Longboat Energy, the emerging full-cycle E&P company, is pleased to announce that a rig has been assigned for the drilling of the Lotus (Kjøttkake) exploration well (Company 30%) in Norway.

The Lotus prospect will be drilled using the semi-submersible Deepsea Yantai and is expected to be drilled during Q3 2024. The license partnership includes DNO Norge AS (40%, op) and Aker BP ASA (30%).

Licence PL1182S lies in the prolific Northern North Sea, 4kms southeast of the Company’s recent significant Kveikje discovery where Longboat is a 10% equity partner. 

Longboat’s Lotus prospect has been named Kjøttkake by the license operator. It comprises Paleocene injectite sandstones, characterised by excellent reservoir properties, and is supported by seismic amplitudes. Longboat exploited its significant knowledge of injectite reservoirs, which are also the main reservoir in the Kveikje discovery, to secure the Lotus prospect through a firm well commitment in last year’s APA 2022 licencing round.

Based on the Company’s estimates, Lotus contains gross mean prospective resources of 27 mmboe* with further potential upside estimated at 44 mmboe*. The chance of success is 56%* with the key risk being hydrocarbon retention.

If successful, Lotus is likely to form part of an area cluster development together with Kveikje and several other recent discoveries in the area, through infrastructure associated with the nearby giant Troll field. 

Helge Hammer, Chief Executive of Longboat Energy, commented:
“I am pleased that we have secured a rig for drilling Lotus, which could add substantial reserves to our Kveikje development if successful.   

The next well on the programme will be Velocette, which is expected to spud late this summer, and which will be followed by Lotus next year.”

Even Longboat will know that the market is hardly likely to be over excited by the prospect of hiring a rig for a well to be drilled in Q3 2024 but it gives a chance to remind us about Velocette which is scheduled for this autumn. 

Empyrean Energy

Empyrean has announced a successful capital raise and debt restructuring as well as an update on future activities at the Mako Gas Field at the Duyung PSC (Empyrean 8.5%)  and the Topaz prospect at its Block 29/11 permit (Empyrean 100%), offshore China.

HIGHLIGHTS

• £1.52 million raised at a price of 0.8p
• Placement oversubscribed
• Mako Gas Sales Agreement binding terms expected late Q2 and sell down news expected early Q3
• Joint regional oil migration study with CNOOC team to be completed
• 3D seismic inversion project to discriminate light oil from water to commence at Topaz with a specialist seismic consultancy with expertise in seismic inversion
• Convertible Note debt restructure to reduce face value of the Convertible Note and secure extended moratorium on interest
• Management participation in the capital raising and agreement to sacrifice one-third of salary for new equity to minimise cash burn ahead of key developments

Empyrean is the operator of Block 29/11 in China and has 100% working interest during the exploration phase. In the event of a commercial discovery, its partner, China National Offshore Oil Company (“CNOOC”), may assume a 51% participating interest in the development and production phase.

Capital Raising
Empyrean is pleased to advise that it has entered into binding subscription agreements to issue 189,753,783 new Ordinary Shares of 0.2p each in the Company at a price of 0.8p per New Ordinary Share, raising £1,518,030 (before costs).

 The Issue Price represents a 22.3% discount to the price of the Company’s ordinary shares of 0.2p each (the “Shares”) as at close of business on 26 May 2023 (1.03p) and a 33.5% discount to the volume weighted average price of the Shares for the ten days prior to close of business 26 May 2023 (1.12p) (“10 Day VWAP”).

Empyrean advises that the Board has resolved to issue 2,887,500 Shares to advisors of the Company in lieu of part of the fees incurred for the capital raising (the “Advisor shares”).

The Subscription is being completed under the Company’s existing authorities and is not subject to the approval of shareholders. Following the Subscription and issue of the Advisor shares, the Company’s enlarged issued share capital will comprise 981,073,175 Shares. This figure may be used by shareholders as the denominator for the calculations by which they will determine if they are required to notify their interest in, or a change to their interest in, securities of the Company under the Financial Conduct Authority’s Disclosure and Transparency Rules.

Of the total raised under the Subscription, CEO and Managing Director of Empyrean, Tom Kelly, has subscribed for 6,250,000 New Ordinary Shares for a total consideration of £50,000. Following his participation in the Subscription, Mr Kelly has an interest in 95,138,888 Shares, representing 9.69% of the enlarged issued share capital of the Company. In addition, Technical Director of Empyrean, Gaz Bisht, has subscribed for 1,850,000 New Ordinary Shares for a total consideration of £14,800. Following his participation in the Subscription, Mr Bisht has an interest in 33,671,429 Shares, representing 3.43% of the enlarged issued share capital of the Company. Further, Company Secretary of Empyrean, Jonathan Whyte, has subscribed for 500,000 New Ordinary Shares for a total consideration of £4,000. Following his participation in the Subscription, Mr Whyte has an interest in 673,572 Shares, representing 0.07% of the enlarged issued share capital of the Company.

The funds raised from the Subscription will be used as follows:

• for the completion of joint regional oil migration studies with CNOOC at Topaz ;
• for the completion of a 3D seismic inversion study aimed to discriminate between oil and water in the reservoir at Topaz;
• for ongoing prospect, licensing fees and permit costs;
• for post Jade well consultancy, analysis and residual exploration costs;
• for front-end engineering design (“FEED”), studies and surveys at Mako – including gas processing and export gas tie in at the Kakap KF Platform; and
• for general working capital requirements

Application will be made for the New Ordinary Shares and the Adviser Shares to be admitted to trading on AIM. Admission is expected to take place on 12 June 2023. The New Ordinary Shares and the Adviser Shares will rank pari passu with existing Shares in issue.

Future Activities

Mako Gas Field
As previously announced, Conrad Asia Energy, the operator and 76.5% partner in Mako has commenced a sell down process with a global investment bank in order to fund the development of Mako. Mako is the largest undeveloped gas accumulation in the immediate region and Conrad have said that industry interest in the project and sell down process is encouraging. Mako has received government approval for a Plan of Development. A Gas Sales Agreement is currently in advanced stages of negotiation and a binding terms sheet is expected between the partners, a Singaporean buyer and SKKMIGAS (the Indonesian regulator) in the near term. 

Topaz Prospect
Empyrean intends to conduct two further key projects that capitalise on the excellent quality 3D seismic acquired by the Company over the permit, shared regional 3D seismic that CNOOC has and additional physical well data of both Empyrean and CNOOC. These projects are designed to help address and mitigate the remaining primary geological risk at Topaz  – oil migration into the Topaz trap.

Firstly, jointly with CNOOC, Empyrean intends to complete a regional oil migration study. CNOOC bring excellence in local basin modelling expertise along with crucial regional data that augments the data Empyrean has on Block 29/11. The regional data includes temperature, pressure, timing of oil maturation, and successful oil migration pathway mapping. The project will map oil migration from the proven source rock south west of Block 29/11 that charges the four CNOOC oil discoveries (immediately west of Block 29/11 and Topaz) and extend this into Block 29/11 and map these migration pathways to Topaz. In addition, similar work will be conducted from a new kitchen located entirely within Block 29/11 and oil migration pathways will be mapped to Topaz. This project is expected to take approximately 4 months to complete.

Secondly, Empyrean will conduct a 3D seismic inversion project focussing on Topaz. The 3D seismic inversion project will utilise the oil properties, reservoir temperature, reservoir pressure and water salinity data from CNOOC oil discovery wells combined with reservoir porosity and physical data from Empyrean well logs and core to maximise the effectiveness of the inversion project outcomes. The aim of the 3D seismic inversion project is to assess whether Topaz has different elastic properties to that of three water bearing wells in Block 29/11 and whether these properties can discriminate between water and light oil in the high porosity carbonate reservoir rocks on the high quality Topaz 3D seismic. The 3D seismic inversion project is expected to take approximately 3 months to complete.

Debt Restructuring
In December 2021, the Company announced that it had entered into a Convertible Loan Note Agreement with a Melbourne-based investment fund (the “Lender”), pursuant to which the Company issued a convertible loan note to the Lender and received gross proceeds of £4.0 million (the “Convertible Note”).

As announced in May 2022, the Company and the Lender then amended the key repayment terms of the Convertible Note, which at that time included the right by the Lender to redeem the Convertible Note within 5 business days of the announcement of the results of the Jade well at Block 29/11. The face value of the loan notes was reset to £3.3m with interest to commence and accrue at £330,000 per calendar month from 1 December 2022.

The Company and the Lender have, in conjunction with and conditional upon the completion of the Subscription, now reached agreement on amended key terms to the Convertible Note to allow the sales process for Mako to complete. The key terms of the amendment are as follows:

1. The face value of the Convertible Note has been reduced from £5.28m (accrued to the end of May 2023) to £4.6 million;
2. No interest shall accrue on the Convertible Note until 31 December 2023, with interest accruing thereafter at a rate of 20% p.a.;
3. The conversion price on the Convertible Note has been reduced from 8p to 2.5p per Share;
4. Unless otherwise required by the joint operating agreement entered into with Empyrean’s licence partners (the “JOA”) or with the prior written consent of the Lender (such consent not to be unreasonably withheld or delayed), Empyrean may only execute agreements for the sale of its interest in Mako (in whole or in part) if the terms of the sale provide for a payment to Empyrean at completion of immediately available funds and for a sale price of an amount that is at least the amounts owed to the Lender (as described in 5 and 6 below):
5. On a successful sale of the Company’s interest in Mako, Empyrean must redeem the face value of the Convertible Note and pay the Lender the greater of (a) US$1.5 million or (b) 15% of the proceeds such sale;
6. In the event that the Company repays the Convertible Note from sources other than a sale of its interest in Mako, Empyrean must also pay the Lender US$1.5 million on redemption of the Convertible Note together with a further payment based on either (a) the actual valuation achieved on any sale within 2 years or (b) an updated valuation of the Company’s interest in Mako if not sold within that 2 year period, in each case so that the total proceeds paid to the Lender are 15% of the valuation of the Company’s interest in Mako;
7. In the event that the sale process being run on behalf of the operator, Conrad, does not result in an offer being made to acquire all or part of the Company’s interest in Mako, then Empyrean must work with the Lender in good faith to sell the Mako Interest as soon as reasonably possible and, subject to applicable laws and the terms of the JOA, may grant rights to the Lender to market this interest on its behalf. 

Salary Sacrifice
While the Company awaits the anticipated signing of the GSA and the completion of the sell down process noted above, two of its Directors, Tom Kelly and Gaz Bisht, together with its Company Secretary, Jonathan Whyte, have agreed to take one third of their salaries in new Shares (“Salary Sacrifice Shares”) in lieu of cash remuneration in order to preserve capital and ensure more funds are directed towards project activities. The Salary Sacrifice Shares will be issued at the same price as the Subscription Price (0.8p per New Ordinary Share) and will be issued to the relevant participants at the end of each month starting June 2023. This arrangement will conclude on the earlier of 31 December 2023 or the signing of a binding agreement for the sale (in part or whole) of Empyrean’s interest in Mako.

Issue of Warrants
Empyrean advises that the Board has resolved to issue warrants in respect of 2,833,333 Shares to advisors of the Company, for consultancy and advisory services provided over the last 12 months (the “Advisor Warrants”).

The exercise price of the Advisor Warrants is 1.5p each and they will expire on 30 May 2024.

Empyrean also advises that the Board has resolved to issue incentive warrants in respect of 10,000,000 ordinary shares of 0.2 pence in the Company to the Company Secretary, Jonathan Whyte, or his nominee.

The Incentive Warrants have been granted as part of the Company’s strategy to retain and incentivise directors and management of the Company. The Incentive Warrants will expire on 30 May 2026.

The Incentive Warrants are to be issued in two equal tranches of 5,000,000. The exercise price of the first tranche of Incentive Warrants is 1.5p each, which represents an approximate 25% premium to the volume weighted average price of the Shares for the ten days prior to the date of grant. The exercise price of the second tranche of Incentive Warrants is 2.0p each, which represents an approximate 66% premium to the volume weighted average price of the Ordinary Shares for the ten days prior to the date of grant.

The technical information contained in this announcement has been reviewed by Empyrean’s Executive Technical director, Gaz Bisht, who has over 32 years’ experience as a hydrocarbon geologist and geoscientist.

Empyrean CEO, Tom Kelly, stated:
“Empyrean is very pleased with the outcome of this capital raising and is grateful for the continued support from its shareholders. We now look forward with great interest to the conclusion of Gas Sales Agreement negotiations and to developments on the sell down process of the Mako Gas Field. The macro environment for gas in South East Asia, and Singapore in particular, is expected to continue trending favourably with the region transitioning from coal to gas as the preferred energy source. Energy demand and gas demand are both forecast to continue to grow.

In China, we will use the very latest technology to further de-risk the very large 890 million barrel (P10) target at Topaz. Following success on the regional oil migration study and 3 seismic inversion project, we will continue our preparations for drilling within the November – May 2024 drilling weather window.”

Until I get a chance to speak to Tom Kelly I can’t really add anything to what is in the statement, readers will know that historically I have given Empyrean every chance but this really sounds like the company are heading towards the last of their 9 lives but more after Ive spoken to TK. 

Prospex Energy

Prospex has announced that on behalf of the Joint Venture, Po Valley Energy Limited has recovered the €757,000 performance bond funds deposited with SNAM, the Italian national Transmission System Operator.

Po Valley Operations Pty Limited, a wholly owned subsidiary of Po Valley Energy Limited (ASX: PVE) is the Operator of the Selva Malvezzi production concession with 63% ownership interest and Prospex has the remaining 37% working interest in the Joint Venture.

Highlights

• PVO has successfully recovered the €757,000 performance bond (€280,090 net to PXEN) previously deposited with the Italian national Transmission System Operator SNAM
• The return of the bond follows the completion of the SNAM pipeline tie in connection, Gas Sales Agreement and transportation arrangements
• First gas supply from the Podere Maiar – 1 well in the Selva field is contingent upon final Ministry approval after final operation and safety inspection of the completed gas treatment plant

On Monday 29 May 2023, Po Valley Energy Limited  announced that the process to recover the performance bond funds deposited with SNAM had been finalised.  The amount reimbursed from SNAM is €757,000 with €280,090 net to PXEN.  This follows the completion of the pipeline tie in connection to the newly built Podere Maiar – 1 (PM-1) gas treatment facility in the Selva Malvezzi Production Concession, located in the Emilia Romagna region (Po River Valley area in the north of Italy).

The return of the bond deposited with SNAM was conditional on completion of the SNAM grid connection and the Gas Sales Agreement, announced on 13 February 2023.

Initial production of PM-1 gas is contingent on Ministry final approval after the sign-off of the final operation and safety inspection.  The final inspection has been delayed due to severe flooding throughout the Emilia Romagna region.  Po Valley Energy has been informed that the inspection will take place as soon as the Fire Department has attended to urgent priorities.  The gas treatment facility and preparatory activities for first gas have not been affected by the flooding.

Mark Routh, Prospex’s CEO, commented:
“The team at Po Valley continues to deliver on behalf of the Joint Venture and the new gas plant facility and grid connection has been approved by the Italian national Transmission System Operator.  The return of the SNAM Bond is an expected but welcome boost.

“The anticipated flow of gas from Selva by the end of May has been delayed on account of the emergency situation in the Emilia Romagna region of the Po Valley, where the emergency services are fully focussed on dealing with the catastrophic flooding in the area.  Fortunately, the new plant and the well site has not been affected by the flooding.

“The delay of the final operation and safety inspection due to the flooding is entirely beyond the control of the team in Italy.  The Operator has been assured that the necessary inspections by the fire department will take place as soon as resources become available.”

This should be good news from Prospex but they have fallen, on a temporary basis, behind in Italy…..

Rockhopper Exploration

Rockhopper has announced its audited results for the year ended 31 December 2022.

2022 HIGHLIGHTS

SEA LION AND NORTH FALKLAND BASIN

• Completion of transaction to bring Navitas Petroleum LP into the North Falkland Basin licences (the “Transaction”)
• Licence interests fully aligned
• Navitas 65% and Operator
• Rockhopper 35%
• Rockhopper benefits from two loans from Navitas
• Pre-Final Investment Decision (“FID”) loan: covers all Rockhopper’s Phase 1 Sea Lion project costs pre-FID via 8% loan
• Post FID loan: covers two-thirds of Rockhopper’s Phase 1 Sea Lion project costs from FID to the earlier of 12 months post-first oil or project completion (for any costs not met by third party debt financing) via 0% loan
• Loans repaid from 85% of Rockhopper’s working interest share of Sea Lion Phase 1 project cash flows
• Sea Lion project re-defined
• Total barrels developed: 269mmbbls

Phased drilling

• First campaign: 18 wells (11 pre first oil)
• Further campaign: 5 wells
• Production plateau: 80,000 bbls/d
• Redeployed FPSO
• Gross JV NPV10 US$4.3 billion
• Pre first oil capex US$1.3billion

OMBRINA MARE

• Successful arbitration outcome announced in August 2022
• Awarded compensation c.€190 million plus interest (the “Award”)
• Rockhopper sent letter to Italy in September 2022 requesting payment of €247 million
• Italy seeking to annul; Rockhopper contesting annulment; confident in merits of legal case
• Interest accruing at c.€1.25 million per month
• Rockhopper and Italy directed to find an outcome that allows Rockhopper to enforce whilst protecting Italy from risk of non-recoupment should it succeed in annulment 

CORPORATE AND FINANCIAL

• Capital raise of US$10.4 million pre-expenses in placing and open offer which completed in July 2022
• Warrants outstanding at 9p per share
• Administrative expenses remain low

Keith Lough, Chairman of Rockhopper, commented:
“As John Summers and I approach our final AGM, we are pleased for shareholders that the Company is in such a strong position. The combination of a new, committed and capable partner in Navitas, a reworked hugely attractive Sea Lion development and the outcome of the Ombrina Mare arbitration sets our company up for what we believe is an exciting moment in our development. We are delighted with the hugely significant progress achieved in the last year and are convinced that we are closer than ever to unlocking the value of Sea Lion for all stakeholders.“

Nothing to add to these historic number for RKH who are in the arms of Navitas and of course the Arbitration process…

IGas Energy

IGas is pleased to announce that, as part of the five tenders submitted through the Carbon and Energy Fund (CEF) Framework in late 2022, GT Energy, IGas’ geothermal business, has been selected by Manchester University NHS Foundation Trust (the Trust) as preferred bidder to deliver a geothermal heat solution for the Wythenshawe Hospital.

An Innovation Partnership between GT Energy, the Trust and the CEF will be created to provide a framework for the parties to work together through the project development phases.

Further announcements will be made about the details and timeline of the project once the partnership has been formalised.

About the Carbon and Energy Fund
The Carbon and Energy Fund (CEF) has been specifically created to fund, facilitate and project manage complex energy infrastructure upgrades for the NHS and wider Public Sector.

With a proven track record of more than 60 projects and in-depth experience of procurement, engineering, legal and finance, the CEF is the organisation to successfully guides Public Sector clients through the complex processes involved.

No need for any further comment as there are few pieces of information in this statement. 

Reabold Resources

Reabold, today announces its audited financial results for the year ended 31 December 2022 and the Annual Report is publicly available at www.reabold.com/investors/reports-presentations/

Reporting period highlights

Portfolio developments

• Sale of Corallian and its Victory licence in which Reabold held a 49.99% interest to Shell U.K. Limited in November 2022 for gross cash consideration of £32 million; Reabold’s share of net proceeds c. £12.7 million after fees and other costs
• Acquisition of Corallian’s six North Sea licences by Reabold for £250,000 in May 2022
• West Newton developments: planning granted and Competent Person’s Report (“CPR”) confirmed gross 2C unrisked technically recoverable resources of 197.6 bcf of sales gas, with an estimated 86% geological chance of success.  Technical analysis confirmed future exploratory drilling at the West Newton B site
• Reabold’s California assets exchanged for a 42% stake in Daybreak Oil & Gas Inc

Board and balance sheet

• Appointment of Chief Financial Officer Chris Connolly in March 2022; former Finance Director Anthony Samaha appointed as Non-Executive Director
• Cash of £5.5 million at year end, no debt
• Net assets of £46.5 million

Post period end highlights

• Acquisition of Simwell Resources Limited for £1 million which includes interests in four Southern North Sea licences east of onshore West Newton, providing interesting exploration opportunities and valuable geological insight for our understanding of West Newton
• CPR released on four of Reabold’s North Sea licences including P2478, which includes the West Dunrobin prospect confirming significant resource potential
• Rathlin to potentially bring in an industry partner to support licence activity, with West Newton B-2 drilling targeted for Q4 2023, subject to final regulatory approvals and rig availability
• Potentially highly significant discovery in Crawberry Hill, part of the PEDL 183 licence
• Share buyback programme commenced during April 2023
• Acquired a 3.1% interest in LNEnergy for cash consideration of £250,000, receiving options to acquire further shares in LNEnergy which, if exercised, would result in Reabold holding a 25.0% shareholding in LNEnergy for aggregate cash and equity consideration of £3.8 million.

These figures are historic and certainly not what the shareholders are waiting for.

For Reabold it is all about West Newton and  when it will be developed, for many in the industry that is by no means obvious but it must be where the potential upside is to be found at the company. Something needs to happen but there isn’t an obvious route, at least not one that is being found. 

KeyFacts Energy Industry Directory: Malcy's Blog