WTI (July) $77.72 +85c, Brent (July) $82.12 +76c, Diff -$4.40.

USNG (June) $2.52 -4c, UKNG (June) 84.55p +1.4p, TTF (June) €34.22 -€0.555.

Oil price

Oil drifted last week and while the Fed were ambivalent about interest rates, economic data looks mixed. But the data creeping out of the Memorial Day weekend and its start of the driving season where product demand was very high. 

Opec has moved the Ministerial meeting back a day to Sunday, the 2nd of June and perhaps more importantly online which points to a meeting where the decision is already made. 


Chariot has announced the results from the drilling of the OBA-1 well on the Dartois prospect, the second of a two well drilling campaign, in the Loukos Onshore licence onshore Morocco (Chariot, Operator 75%, ONHYM, 25%).

·      OBA-1 well was safely and efficiently drilled, on time and on budget, to a final measured depth of 901m through the target reservoirs.

·      Following comprehensive evaluation of the well data, including wireline logs, cuttings and gas data, preliminary interpretation:

 confirms the presence of reservoirs over an interval of approximately 200m gross thickness, corresponding to the pre-drill targets; and

 within which an approximate 70m gross interval of primary interest has been identified containing elevated resistivities coincident with elevated mud gas readings, indicating potential gas pays, with no water-bearing reservoirs identified.

·      Further post-drill analysis will be conducted in preparation for well flow testing which will determine the well productivity and the gas resource potential of the discovery.

·      The well will now be suspended to allow future rigless flow testing operations and potential use as a producer well and the rig will then be demobilised.

Duncan Wallace, Technical Director of Chariot commented:

“We are very pleased to report the successful drilling of the OBA-1 well at the Dartois prospect which now concludes Chariot’s first onshore drilling campaign in Morocco and brings with it positive results for the potential of the Dartois area.

We will now integrate the comprehensive data we have obtained from both the RZK-1 and OBA-1 wells with recently reprocessed 3D seismic data to understand the resource potential of the Dartois area, to confirm the optimal future work programme on the discovery and the impact on wider prospectivity across the Loukos licence. Our two first wells have both been successful in confirming our geological model for reservoir distribution and the presence of gas which bodes well for future exploration activity.

I would like to thank both our operational team, who once again have shown that that they can drill safe, efficient and successful wells, and ONHYM for their ongoing support and partnership. Our focus on the Loukos licence is to get any commercial discoveries to first gas as quickly as possible.

We now look forward to the offshore drilling campaign planned for Q3 2024, on the Anchois gas field, with our new partners Energean, where we are looking to increase the development to over 1 Tcf.”

Great news that Chariot has made a gas find with OBA-1 at the Loukos onshore licence, onshore Morocco. The well was drilled safely and on time and the company has already got under way with a comprehensive evaluation of the well data, including wireline logs, cuttings and gas data, preliminary interpretation and has confirmed the presence of reservoirs over an interval of approximately 200m gross thickness, corresponding to the pre-drill targets and showing that these wells can be drilled and analysed cheaply and quickly. 

The primary targets showed a 70m gross interval with elevated mud gas readings, indicating potential gas pays, with no water-bearing reservoirs identified. A well like this has a number of advantages in addition to those identified, in particular it can provide a return on investment very quickly indeed something that will be proved in the coming months at Chariot. With another campaign to come with Energean, the area could prove to be the profitable province envisaged by Chariot. 

Challenger Energy Group

Challenger has announced that the investment in the Company by Charlestown Energy Partners LLC  has completed on terms and conditions as previously announced, and that Mr Robert Bose, Managing Member of Charlestown, has joined the Board of the Company.


·    Charlestown has advanced a £1.5m loan to the Company;

·    On closing of the farm-out of the Uruguay AREA OFF-1 licence to Chevron, and subject to the prior completion of an agreed share consolidation, this loan (and interest) shall convert (“Conversion”) into new ordinary shares in the Company at a fixed price of 0.168 pence per share, being a c. 15% premium to the current share price;

·    On Conversion Charlestown’s shareholding will represent a c. 8.7% interest in the Company, thus making Charlestown one of the Company’s largest shareholders;

·    Charlestown’s investment will underpin accelerated commencement of technical activity on the Company’s AREA OFF-3 licence offshore Uruguay; and

·    Mr Robert Bose (a member of the Charlestown oversight committee and currently Chief Executive Officer of Sintana Energy Inc) has been appointed as a Non-Executive Director of the Company, with immediate effect.

Eytan Uliel, Chief Executive Officer of Challenger Energy, said:

“We are pleased to have finalised the investment from Charlestown, a specialist investor in energy and E&P, including being a very successful earlier-stage investor in the Namibian conjugate margin which has obvious parallels to Challenger Energy. We also extend our welcome to Charlestown’s Managing Member, Mr. Robert Bose, who has joined our Board. Challenger Energy is at an exciting point in its history, and we look forward to working together with Robert to ensure that we deliver on that promise over the coming period”.

Good news for Challenger here as the investment from Charlestown has arrived and will be useful for development and the costs of running the business.

Southern Energy

Southern Energy has  announced its first quarter financial and operating results for the three months ended March 31, 2024. 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, 2024, 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.


·    Average production of 18,055[1] Mcfe/d (3,009 boe/d) (96% natural gas) during Q1 2024, an increase of 15% from the same period in 2023

·    Petroleum and natural gas sales of $4.8 million in Q1 2024, a decrease of 8% from the same period in 2023, largely due to the decline in natural gas pricing

·    Generated $2.2 million of adjusted funds flow from operations[2] in Q1 2024 ($0.01 per share basic and diluted)

·    Net loss of $3.1 million in Q1 2024 ($0.02 net loss per share – basic and fully diluted), compared to a net loss of $1.1 million in Q1 2023

·    Average realized natural gas and oil prices for Q1 2024 of $2.53/Mcf and $74.86/bbl compared to $3.25/Mcf and $75.73/bbl in Q1 2023

·    Entered into the sixth amendment to the Company’s senior secured term loan, which among other amendments, included extending the term of the Credit Facility from August 31, 2025 to December 31, 2026 (see “Liquidity and Capital Resources – Credit Facility” in the March 31, 2024 MD&A for full details of the amendment)

·    Monetized the Company’s fixed price swap derivative contracts to take advantage of the positive unrealized gain position, realizing net proceeds of $1.1 million


·    Entered into a fixed price swap derivative contract of 5,000 MMBtu/d for the period of May 2024 – December 2026 at a price of $3.40/MMBtu

Ian Atkinson, President and Chief Executive Officer of Southern, commented:

“The Company’s Q1 2024 results show the resilience of our business in an environment which experienced one of the warmest winters in U.S. recorded history. Along with the warm weather came low heating demand for natural gas and suppressed pricing. Our focus has been on improving our already low-cost structure, which our operations team has done an excellent job of executing. As we look to the second quarter and second half of our financial year, we are already seeing a significant recovery in excess of 50% from the recent lows in natural gas pricing which we expect will allow us to re-initiate growth in completing one of the three remaining Gwinville drilled but uncompleted wells (“DUCs”).

“While low natural gas prices may have been a feature for the period, the recent correction in U.S. natural gas prices along with the structural dynamics of the market are extremely encouraging for a business with Southern’s exposure to natural gas. As the price weakness during the first quarter was met with a significant cut in production from several of the large U.S. gas producers, demand from seven of the largest LNG export plants, including Freeport LNG in Texas, continue to experience significant increases. This huge demand driver for U.S. natural gas is only set to increase further as new Gulf Coast LNG export facilities start accepting feed gas later this summer as well as growing domestic demand from artificial intelligence data centers and electrification of vehicles. Additionally, with the early heat in the U.S. Southeast, we are seeing basis premiums where we sell a portion of our natural gas of close to $1.00/MMBtu for the summer.

“We remain focussed on costs with a solid balance sheet and retain our position of being able to capitalise on gas prices by bringing on increased volumes in short order. As gas maintains its position as a crucial part of future energy security in the U.S., we see a significant re-rating opportunity in the current share price and we look forward to updating shareholders as we unlock the value in our portfolio.”

The first quarter, whilst showing a decent increase of some 15% in production to 3,009 bboe/d of which 96% was natural gas which meant with the weaker prices during the warmer than expected winter pushed sales down by around 8%. However as we have discovered with Southern they have a very low cost structure and with current prices some 50% above the lows are facing a much better quarter.

This means that with stronger prices now and through the current strip, expect Southern to re-initiate growth sometime in the second half of 2024 in completing one of the three remaining Gwinville drilled but uncompleted wells that I wrote about last time. Accordingly I agree with CEO Ian Atkinson as he expects a ‘significant rerating’  and to ‘unlock the value’ in what is a very fine portfolio. 

Financial Highlights


Three months ended March 31,

(000s, except $ per share)



Petroleum and natural gas sales

   $         4,794

 $         5,189

Net loss



Net loss per share





   Fully diluted



Adjusted funds flow from operations (1)



Adjusted funds flow from operations per share (1)





   Fully diluted



Capital expenditures and acquisitions



Weighted average shares outstanding





   Fully diluted



As at period end


Basic common shares outstanding



Total assets



Non-current liabilities



Net debt (1)

 $     (25,274)

$     (19,731)


(1)          See “Reader Advisories – Specified Financial Measures”.

Operations Update

Production in Q1 2024 was positively impacted by bringing online the first of its four drilled but uncompleted DUCs from the Q1 2023 drilling program, the GH 14-06 #3 wellbore. This lateral hole was drilled and completed in the Upper Selma Chalk reservoir and achieved an IP30 natural gas rate of 5.2 MMcf/d, with declines in the quarter in-line with pre-drill expectations. 

Southern is planning to delay the completion timing of the remaining three DUCs into at least the second half of 2024 when the Company expects natural gas pricing to be significantly elevated from current levels. The remaining three DUC wellbores have been drilled in the Lower Selma Chalk (2) and City Bank formations.     

In response to the low natural gas prices experienced in Q1 2024, Southern has been actively reducing and optimizing operating costs, general and administrative expenses and maintenance capital to maximize our netbacks. The Company expects to continue these initiatives throughout 2024. 

The strategic sales points that Southern sells its natural gas into realized a 13% premium to the average benchmark New York Mercantile Exchange (“NYMEX”) Henry Hub price in Q1 2024, helping to offset the challenging natural gas pricing environment. 


Southern currently has $10.0 million of unused capacity on its Credit Facility, which can be utilized to complete the DUCs at higher natural gas prices or can be used to be opportunistic with counter-cyclical inorganic growth opportunities.     

As part of its risk management and sustainability strategy, Southern continuously monitors both the price of NYMEX, as well as the basis differentials, in order to mitigate some of the volatility of natural gas prices. With the extended term provided by the Sixth Amendment of the Credit Facility, Southern has taken advantage of the contango in the natural gas future strip by entering into a fixed price swap contract of 5,000 MMBtu/d for the period of May 2024 – December 2026 at a price of $3.40/MMBtu. Southern’s current commodity hedge program includes:

Natural Gas



Fixed Price Swap

May 1, 2024 – December 31, 2026

5,000 MMBtu/d

NYMEX – HH $3.400/MMBtu

Costless Collar

November 1, 2024 – March 31, 2025

1,000 MMBtu/d

NYMEX – HH $3.50 – $5.20/MMBtu

Southern will continue to monitor NYMEX prices and the basis differential prices and is prepared to hedge additional volumes in a tactical manner going forward.

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.

Ithaca Energy

Ithaca Energy, a leading UK independent exploration and production company, today announced its unaudited financial results for the three months ended 31 March 2024.

Financial key performance indicators (KPIs)



Q1 2024

Q1 2023

Adjusted EBITDAX1 ($m)



Statutory net income ($m)



Net cash flow from operating activities ($m)



Available liquidity 1 ($m)



Unit operating expenditure1 ($/boe)



Adjusted net debt 1 ($m)



Adjusted net debt/adjusted EBITDAX 1




Other KPIs


Total production (boe/d)



Tier 1 process safety events



Serious injury and fatality frequency



1 Non-GAAP measure


Q1 2024 Strategic Highlights

Transformative Business Combination with Eni UK

·    Announced transformational Business Combination of Ithaca Energy and substantially all of Eni S.p.A’s (Eni) UK upstream oil and gas assets in April 2024, creating a UK powerhouse that provides the strategic platform for long-term growth in the UK North Sea and internationally through the combination of complementary portfolios.

–     UKCS powerhouse with estimated pro-forma 2024 production of 100,000 – 110,000 barrels of oil equivalent per day2

–     Agility of an Independent and capability of a Major, implementing Eni’s successful regional satellite model

–     Complementary portfolio unlocks potential for material long-term organic growth with the capability to increase the Combined Group’s production to over 150,000 barrels of oil equivalent per day by the early 2030s on an un-risked basis3

–     Platform for further inorganic growth in the UK and internationally

–     Highly cash-generative combination providing material dividend capacity with ambition for up to $500 million total dividends each year in 2024 and 20254

·    Following completion of the Business Combination, Eni will be a fully committed, long-term and supportive shareholder of the combined business

–     Based on the merger ratio, Ithaca Energy’s shareholders will own 61.5% and Eni will own 38.5% of the combined entity

–     Sell down provisions have been put in place, together with an Eni Call option, to maintain a free float of 10% on completion


·    Rosebank development project progressing as planned to multi-year development timeline:

–     Petrojarl Rosebank FPSO docked in Dubai with vessel upgrade work continuing

–     Q1 preparation work ahead of commencement of Subsea, Umbilicals, Risers and Flowlines (SURF) activity in Q2

·    Successfully awarded license extension from 31 March 2024 to 31 March 2026 for Cambo field on 19 March, supporting the ongoing farm-in process to enable the future progression of Cambo and Fotla towards FID, subject to fiscal and market conditions

·    Continued progression of Captain Electrification FEED study to support FID in due course, subject to fiscal and market conditions


·    Captain continues to deliver against a high-activity plan in support of the Enhanced Oil Recovery (EOR) Phase II project now substantially complete and in preparation for turnaround activity in May. During the quarter, rig recertification was successfully executed on plan and on budget in support of the topside drilling campaign scheduled for Q3

·    Final verification activities completed supporting milestone first EOR Phase II polymer injection into the subsea wells during H1 2024, with the following activities completed in the Q1:

–        Drilling: Completed drilling operations of remaining three Area D polymer injection wells and new production well B35 brought online

–        Subsea: Completed installation of all remaining subsea infrastructure including flowlines, umbilicals, subsea distribution units to enable EOR II start-up

–        Facilities: Successfully completed significant facilities maintenance scopes across power generation, gas compression and oil export pumps

·    Preparation for W1 well workover at Erskine during Q2, reinstating a fifth production well at the field

Q1 2024 Operational Update

·    Q1 production of 58.7 thousand barrels of oil equivalent per day (kboe/d), supporting full year pro-forma 2024 production guidance issued 23 April

·    Q1 production split 69% liquids, 31% gas

·    Q1 production reflects previously guided operational issues across our non-operated joint venture portfolio:

–     Non-operated Pierce field production impacted as the vessel remained off stream for the entirety of Q1. The issue has now been resolved and field production is ramping up

–     Non-operated Schiehallion field production impacted by weather related downtime and outages caused by the Ocean Great White rig being off station, which will also impact the timing of production wells later in 2024

–     Compressor issues at Erskine’s host facility (Lomond) impacting production in Q1

Q1 2024 Financial Highlights

·    Adjusted EBITDAX of $339.0 million (Q1 2023: $518.1 million)

·    Statutory net income of $42.7 million (Q1 2023: $158.4 million)

·    Robust net cash flow from operating activities of $313.8 million (Q1 2023: $351.4 million)

·    YTD realised oil prices of $88/bbl before hedging and $87/bbl after hedging (Q1 2023: $83/bbl before hedging and $81/bbl after hedging) and gas prices of 65p/therm before hedging and 119p/therm after hedging (Q1 2023: 137p/therm before hedging and 192p/therm after hedging)

·    Continued strong cost control, delivering Q1 operating costs of $122 million ($22.9/boe (Q1 2023: $20.3/boe)) with Q1 producing asset capex of $93 million and Q1 Rosebank capex of $43 million including the ongoing modifications to the FPSO

·    Balance sheet remains very strong with further deleveraging in the period

·    Adjusted net debt of $461.1 million at 31 March 2024 (31 December 2023: $571.8 million; 31 March 2023: $899.6 million)

·    Group leverage position of 0.30x adjusted net debt to adjusted EBITDAX (31 March 2023: 0.46x)

·    Further interim dividend for 2023 of $134 million paid in April 2024, taking the total 2023 dividend payment to $400 million

·    Significant build on hedging book during the quarter, with 7.4 million barrels of oil equivalent (69% oil) hedged from Q2 2024 into 2025 at an average price floor of $77/bbl for oil and 125p/therm for gas at 31 March 2024

FY 2024 Management Guidance

·    Management reaffirms all previously provided pro-forma guidance ranges for full year 2024 (issued 23 April)

Interim Chief Executive Officer, Iain Lewis, commented:

“Ithaca Energy continues to deliver against its BUY, BUILD and BOOST strategy, announcing the transformational Business Combination with Eni UK in April that positions the Company as the largest resource holder in the UKCS with the potential for further material organic and inorganic growth. The Company’s Q1 performance was in line with our expectations and factored into our full year guidance set towards the end of March, following a number of operational issues across our non-operated joint venture portfolio that have now been resolved.”

I don’t formally cover Ithaca, I have been waiting a long time for a meeting with the company and had it as an income buy on the back of the previous portfolio and old management. Following the Eni deal that has significantly changed the asset base and the as of today the whole suite of management.

Iain Lewis, who presented for the last time as interim CEO returns to CFO territory whilst the Chairman has disappeared w.i.e. Yanic Friedman is lined up as Executive Chairman with Luciano Vasques as CEO and a new COO making up the numbers from Eni.

The company are determined to pay out $500m in dividends this year after paying $400m in 2023 so if I was a shareholder I would give them the benefit of the doubt as the portfolio has got very strong growth built into in for many years. to come. Until I meet with them I’m usually circumspect but at the moment I would remain firmly in Ithaca’s camp.

And finally…

The English football season ended on Saturday at Wembley as the blue side of Manchester took on the red side in an attempt at numerous records but the Red Devils hadn’t read the script and won 1-2.

And joining them in the Prem next season will be the Saints who beat Leeds United in the alleged richest game in the world and return to the Prem.

And England beat Pakistan in the T20 opener at Edgbaston on Saturday,  tonight the 3rd match is scheduled for Sophia Gardens at Cardiff but if the weather is anything like it has been here today then it may go the way of the 1st match…