Malcy’s Blog – Oil price, IOG, Chariot, Zephyr, Arrow, SDX, Longboat, Hurricane, PTAL, EME, Angus & finally

WTI (June) $75.66 -$1.12, Brent (July)* $79.31 -$1.02, Diff -$3.65 u/c. *Brent June expiry

Author @mgrahamwood

USNG (May) $2.31 -9.2c, UKNG (May) 88.5p -1.94p, TTF (May) €38.15 -€0.68.

Oil price

Oil is under pressure today ahead of the Fed meeting tomorrow where comment on what is becoming a weaker US economy will be great. Many still are uncertain about the R word or indeed if the rate rises will have finished by then but China and indeed India will be literally oiling the wheels of the world’s economy…..

Retail gasoline in the USA is falling, at $3.60 a gallon this week it is down by 5.6c, on the month by 10c and y/y it’s down 58.2c but with the EIA suggesting that oil demand in the USA last month was some 20m b/d, a recent peak, the numbers are only going one way…


IOG has provided a corporate and operational update ahead of its Annual General Meeting which is being held at 10.00am this morning. An accompanying presentation is available at the IOG website and can be accessed via this link:


·      Blythe H1 producing steadily at 17 mmscf/d gross rate, averaging 14.9 mmscf/d year to date

 95.4% Operating Efficiency and 86.4% Production Efficiency

·      Steady progress towards resolution of Blythe H2 drilling issues highlighted on 18 April

 Targeted onstream by end of Q2, then expected to build up to 30-40 mmscf/d

 Additional cost impact net to IOG estimated to be £2-3 million

·      Central Cluster: additional conventional gas resources and several new prospects identified on P2589 licence (32nd Round) following interpretation of reprocessed 3D seismic

·      Southern Cluster: advanced planning for Kelham North/Central appraisal well

·      Northern Cluster: farm-out process launched for up to 50% of Goddard with joint venture partner

·      Interviews with regulator on nine 33rd Round SNS licence applications due later this month

 If successful, these would add valuable discovered resources to each cluster

·      Cash balance of £31.9m at end of April, of which £6.8m was restricted

·      Carefully assessing forward capital allocation and evaluating balance sheet options

Rupert Newall, CEO, commented:

“While Blythe H1 continues to produce steadily through our co-owned infrastructure, our team have worked closely with Petrofac and Shelf to handle the complex well control challenge on H2 safely and professionally. After coming onstream, H2 production is expected to reach an initial peak 30-40 mmscf/d, enhancing our cash flow. Meanwhile, we continue to carefully manage costs, optimise the portfolio and evaluate future investment options alongside our joint venture partner.

In that context, we continue to enhance the portfolio via our low-cost strategy of licensing rounds and 3D seismic reinterpretation. For example, we have identified valuable further undeveloped discovered conventional gas resources and exploration upside on our 32nd Round P2589 licence, part of the Central Cluster and within short tie-back distance to the Southwark platform. Additionally, our nine 33rd Round licence applications are also progressing, potentially adding discovered resources to all four of our production clusters.”

Dougie Scott, COO, commented:

“The gas/oil kick encountered from the Hauptdolomit has now been controlled without needing to sidetrack, despite three challenging complications: significant associated drilling fluid losses, a stuck drill string and a plugged drill pipe. The 8½” hole section has now been drilled to a revised depth above the reservoir, where the 7″ liner will be run and cemented to isolate the overpressure. This will enable the well to continue to the reservoir in the planned 6″ hole size.”

With the Blythe well back and with no need for a sidetrack H2 production should be around 30-40 mmscf/d thus ‘enhancing’ cash flow but with continued monitoring. It should be noted though that the COO’s comments above indicate that it was quite a battle. 

In the meantime, work continues on the 32nd round acreage and of course the 33rd round applications are progressing. IOG are demonstrating there is value and upside in the broader portfolio while they are not averse to bringing in a partner in at Goddard.

Production: Blythe H1 well

·      The current gross unconstrained H1 production rate is approximately 17 mmscf/d

·      Over 2023 year to date, average gross production has been 14.9 mmscf/d, factoring in liquid letdowns alongside other Bacton gas streams and planned H2-related shutdowns

·      Operating Efficiency year to date has been 95.4% and Production Efficiency 86.4%¹

·      Safe hook-up and commissioning of the H2 well is expected to require 3-5 days of planned downtime in both May and June respectively

Drilling: Blythe H2 well

·      Substantial progress made in resolving the well control challenge in the Hauptdolomit formation above the reservoir highlighted on 18 April, limiting the likelihood of needing a sidetrack

·      The situation has been uniquely challenging given the confluence of abnormal formation pressure with an influx of hydrocarbons, drilling fluid losses, the bottom-hole assembly becoming stuck and drill string being plugged

·      However, close collaboration between key IOG personnel and the Petrofac and Shelf Drilling teams has enabled the latter two issues to be resolved, materially improving the situation

·      Two cement plugs as well as specialist Lost Circulation Materials have been deployed, significantly mitigating the drilling losses

·      The 8½” hole section has been drilled to a revised depth and 7″ liner will be run and cemented to isolate this section, enabling continuation of drilling into the reservoir as planned

·      On that basis, the well is targeted onstream by the end of Q2, at an estimated additional cost impact of £2-3 million net to IOG

 The initial well cost estimate was £13 million net to IOG, including associated platform modifications, before any potential tax shelter or investment allowances

·      In a success case, H2 would deliver several key benefits:

 Gas production rates initially expected at 30-40 mmscf/d after a ramp-up a period of displacing liquids in the Saturn Banks Pipeline System

 Lower aqueous liquid arrivals into Bacton, reducing associated operating costs

 Increase in ultimate recovery of Blythe gas reserves

Central Cluster (P1915, P2342, P130, P039, P2589)  

·      The Central Cluster entails potential development of at least five contiguous licences in the broader Vulcan and Jupiter areas of the SNS

·      This includes the Southwark, Nailsworth, Elland and Grafton fields plus several clearly identified potential additions containing both conventional and tight gas resources  

·      The P2589 Grafton licence, acquired in the 32nd UK Offshore Licensing Round, has undergone 3D seismic reprocessing to Pre-Stack Depth Migration (PSDM)

·      Interpretation of this data has identified two structures containing undeveloped conventional gas within the Europa field, which IOG has renamed Kinnegar  

 Produced by ConocoPhillips over 2000-16, Kinnegar lies approximately 13km north-east of Southwark and directly south of Grafton

 These structures initially appear to be of commercial size; further analysis is underway to establish an estimated contingent resource range   

 Several further exploration targets also identified between Southwark and Kinnegar     

·      The Southwark platform would be the key gathering infrastructure for the Central Cluster, providing the conduit to the 24″ Saturn Banks Pipeline System into Bacton

·      A technical working group including third-party experts is progressing a deep-dive assessment of the potential deliverability of the Southwark A1 and A2 wells, as well as the future Nailsworth and Elland wells

·      If successful, the JV’s 33rd Round licence applications would add highly synergistic further discovered gas resources to the Central Cluster

Southern Cluster (P2442)

·      Planning is well advanced for drilling of the Kelham North/Central appraisal well in continuation from Blythe H2, subject to final JV approval

·      The appraisal well is intended to prove up a high-return, fast-payback Southern Cluster potentially including Kelham North, Kelham Central, Abbeydale, Orrell (which lies partly on block), Thornbridge and Thornbridge Deep, plus potential 33rd Round additions

·      The gross success case appraisal well cost is estimated at £14-18 million (£7-9 million net to IOG) before any tax shelter or investment allowance

 Benefits from attractively priced extension option on the Shelf Drilling Perseverance rig

·      The current licence term expires on 31 March 2024, following a six-month extension

Northern Cluster (P2438)

·      The joint venture (JV) of IOG and CalEnergy Resources (UK) Limited (CER) has initiated a farm-out process to bring in an additional partner for, in aggregate, an up to 50% working interest of the P2438 Licence (up to 25% each)

·      Goddard is one of the largest undeveloped SNS gas discoveries (gross 2C: 115 billion cubic feet), with several potential export routes including the Saturn Banks infrastructure

·      Advanced planning is underway to drill the Goddard appraisal well in continuation from Kelham North/Central, at an estimated gross cost of £14-18 million, before any tax shelter 

·      The well would enhance the commerciality of Goddard by confirming reservoir quality and deliverability, defining the gas-water contact and obtaining pressure data

·      Goddard is intended to be the core field in a Northern Cluster potentially including two adjacent Goddard Flank structures and the Southsea prospect, plus potential 33rd Round additions

·      The current licence term expires on 31 March 2024, following a six-month extension


·      The Company held £31.9m in cash at the end of April, of which £6.8m was restricted

·      Given the current lack of Southwark production, management continues to carefully control costs, assess all future capital allocation and evaluate options to optimise the balance sheet 

¹ Operating Efficiency factors in unplanned downtime and Production Efficiency factors in both planned and unplanned downtime.


Chariot has announced it has entered into a partnership agreement with Vivo Energy with the objective of creating a midstream joint venture that will oversee the distribution of natural gas to industrial customers in Morocco. Vivo Energy, the market-leading, pan-African retailer and distributor of high-quality fuels and lubricants has a long-standing presence in Morocco’s petroleum products’ sector, operating a network of over 400 service stations and supplying commercial and industrial customers across a number of sectors in the Kingdom.

The objectives of the partnership will be to:

·      implement a gas-to-industry business in Morocco through the development of marketing and commercialisation of natural gas to industrial customers;

·      establish a jointly owned special purpose vehicle for the purchase, transportation and distribution of natural gas to end-users; and

·      put in place a long-term gas sales agreement for a portion of the future gas production from the Anchois development project (“Anchois”).

Adonis Pouroulis, Chariot CEO, commented:

“We are delighted to be partnering with Vivo Energy, a company which has an extensive footprint in Morocco and the African continent, to develop and deliver a long-term supply of natural gas across the rapidly growing industrial sector in country.

“Morocco’s significant industrial gas demand, which this partnership will supply into, further supports the commercial viability of the Anchois project. This agreement confirms the priority given by Chariot to the Moroccan energy market, expands upon our other existing sales negotiations around future offtakes for the gas from the Anchois gas field and sets out a collaborative partnership with one of the continent’s leading energy distributors, as we continue to develop this high margin low risk asset.”

Stan Mittelman, Vivo Energy CEO, commented:

“We are very pleased to be entering into this partnership. We will work closely with Chariot to jointly leverage our position in Morocco, giving us the opportunity to offer a cleaner and more competitive source of energy for our industrial customers.

Further development of the country’s mid and downstream infrastructure will also facilitate the distribution and increased use of this important domestic resource over the longer term as the industrial gas markets continue to mature. We are confident that the development of the Anchois field, combined with the advancement of Morocco’s gas market, will further accelerate the country’s industrial roadmap towards becoming a less carbon intensive economy, and supporting its export strategy.”

Pierre Raillard, Chariot Morocco Managing Director, commented:

“Partnering with Vivo Energy to deliver this gas to industry creates additional scope for the future production from Anchois. A key part of our strategy in Morocco is to promote energy self-sufficiency and be a catalyst for growth and we are very pleased to be working together to deliver this important domestic resource directly into the country’s gas-hungry industrial sector.”

Peyami Oven, Vivo Energy Maroc MD, commented:

“This partnership is central to support industrials’ transition to a lower carbon source of energy. Development of a gas-to-industry market will enable our existing and potential customers to have access to an abundant and cost competitive source of domestic gas. Together with Chariot, our partnership is built on strong expertise and a deep knowledge of the Moroccan market and the latest gas technologies.  This makes us well positioned to offer best in class and fit for purpose energy solutions to a large spectrum of industries in Morocco.”

This is an exceptional agreement from Chariot, unfortunately almost all the good lines have been used above! But, I see it as a formidable midstream JV with a powerful partner who brings positive pricing and significant brand awareness. 

Anchois gas will get into all parts of the Moroccan gas market, aided by Vivo and in this case a strong presence in the substantial industrial market to add to what should be a large export market as well in due course. I am not changing my 100p target price and think that a  five bagger from here is the very least shareholders can contemplate…

Zephyr Energy

Zephyr has announced an update on its hedging programme related to oil production from its non-operated asset portfolio in the Williston Basin, U.S.    

With the majority of hedged volumes from last year’s Programme now produced, Zephyr’s Board of Directors has elected to enter into additional oil hedge agreements.  Volumes hedged for the nine months ending 31 December 2023 have increased from 94,000 barrels to 137,000 bbls, with BP Energy Company, one of the world’s leading energy trading houses, continuing to serve as the counterparty.

Under the terms of the Programme, Zephyr holds crude oil commodity swap agreements, which settle on a monthly basis, at the following prices:

·Q2 2023: 52,000 bbls at an average US$86.84/bbl

·Q3 2023: 45,000 bbls at an average US$83.57/bbl

·Q4 2023: 40,000 bbls at an average US$83.42/bbl

·Q1 2024: 27,000 bbls at an average US$82.20/bbl

The Programme has been structured to provide cashflow surety related to the Company’s debt obligations, as well as to derisk funding requirements for the Company’s activity at its flagship project in the Paradox Basin, Utah, U.S while allowing for additional exposure to future fluctuations in prices.

The Board will continue to monitor prices and may add additional hedges if appropriate. 

Another smart move from Zephyr who have secured significantly more oil hedged than before and at prices that are at a premium to the market. This is extremely beneficial to the company and is of course crucial to the funding of the development at the Paradox Basin currently under way. 

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, 2022 and the filing of its 2022 year-end reserves report, which are available on SEDAR ( and will also shortly be available on Arrow’s website at

Full Year Highlights:

·    Recorded $25 million of total oil and natural gas revenue, net of royalties (FY 2021: $6.5 million).

·    Generated record results from operations and an increase in production since its listing on AIM in October 2021:  

 FY 2022 EBITDA of $12.5 million (FY 2021: $0.8 million), with Q4 2022 EBITDA of $4.5 million compared to $0.5 million in Q4 2021.

 FY 2022 average corporate production up 223% to 1,345 boe/d (FY 2021: 461 boe/d) with Q4 average corporate production of 1,736 boe/d compared to Q4 2021 140 boe/d and Q3 2022 1,503 boe/d.

·    Realized FY 2022 corporate operating netbacks of $42.40/boe, and $41.95/boe in Q4 2022, due in each case to increased production and better prices of crude oil.

·    Cash position of $13 million at the end of 2022.

·    Generated positive operating cashflows in Q4 2022 of $7.5 million.

·    Proven and probable reserves at year-end 2022 increased 4% to 7.69 MMboe; representing a reserve replacement ratio of 164%.

·    Drilled two successful wells at Rio Cravo Este (RCE) resulting in material production addittions. Successfully completed two workovers in the RCE-1 and RCS-1 wells at Rio Cravo. These operations targeted additional hydrocarbon bearing zones which resulted in material production additions.

·    The East Pepper Montney gas well was tied in adding to Canadian production. This resulted in reserve reclassification and displays the commercial viability of drilling and completing Montney gas wells in the Hinton Area, all of which were part of the 2022 capital program.

·    All operations delivered safely, with no accidents or environmental incidents.

Post Period End Highlights:

·    So far in 2023, the Company has drilled three development wells on the Tapir Block, including RCE-5, RCE-4 and RCE-3, which are all currently producing at restricted rates. Ramping production up slowly prevents early water breakthrough in each Rio Cravo well.

·    The 130 square kilometer 3D seismic at West Tapir has completed and is in the hands of processors. It will take three to four weeks to refine the data and likely another two to three weeks to complete data interpretation. This is one of the larger 3-D surveys done in the last few years in the Llanos Basin. Our 2-D data set has identified a number of prospective structures. The 3-D shoot will refine these to prospect status and provide drilling running room for the next one to two years.


·    Arrow has a fully funded 2023 work program totaling US$32 million targeting 10 wells. The three final Carbonera-7 (C7)wells at RCE have been completed and are being ramped up slowly to manage the reservoir.

·    The first Carrizales Norte well will spud shortly. Arrow then anticipates an additional two wells to be drilled at Carrizales Norte by year-end.

·    Arrow will then mobilize back to the RCE pad to drill at least 2 wells targeting the Gacheta formation which was successfully tested at commercial rates in RCE 2.

·    Arrow also plans to drill 2 development wells at the Oso Pardo Block in the Middle Magdalena Basin.

Marshall Abbott, CEO of Arrow Exploration Corp., commented:

2022 was a fantastic year all around for the Company.  We saw growth in production, revenue and income and our balance sheet is in a very healthy position to support the large capital program planned for 2023. Looking ahead, Arrow has multiple near-term catalysts capable of delivering material value.  Currently, Arrow is ready to spud the first well at Carrizales Norte which could have a significant impact on the Company in both production and reserves as well as establishing a new core area. The 3D seismic West Tapir project has now completed shooting and is currently being processed and is expected to further evaluate 2D recognized fault prospects. Looking further ahead, in 2024 the Company is planning a second 3D project on the east side of the Tapir block to evaluate other 2D recognized prospects. The Arrow team continues to strive towards excellence and increasing shareholder value.”

With the 2022 results and reserves all now in and historic in nature we look towards this year to achieve new records and set new targets. And I see no reason at all why Arrow can’t hit the most optimistic of expectations with its exciting drilling programme. 

The ten wells to drill this year have already seen substantial success in the three drilled so far and with the RCE results beating expectations and being brought on in a most conservative manner I expect a real bonus from the start. From here we go to the Carrizales Norte field with the first well of three here imminent and as the CEO says, ‘could be significant’ and a new core area. 

After CN the plan is to drill ‘at least’ two wells into the Gacheta formation at the RCE pad, these were tested as commercial in RCE-2 so should add production for the company. Following that Arrow also plans to drill 2 development wells at the Oso Pardo Block in the Middle Magdalena Basin.

With the 3D seismic now complete and being processed West Tapir could easily be a candidate for another success story and again the East of the block is going to be assessed next year. I continue to expect previous targets to be achieved and new ones to be set, the drilling programme is fully funded and I am as confident as ever about my 50p target price. 




(in United States dollars, except as otherwise noted)

Three months ended December 31, 2022

Year ended December 31, 2022

Three months ended December 31, 2021

Year ended December 31, 2021

Total natural gas and crude oil revenues, net of royalties







Funds flow from (used in) operations (1)





Funds flow from (used in) operations (1) per share –








    Diluted ($)





Net income





Net income per share –



   Basic ($)





   Diluted ($)





Adjusted EBITDA (1)





Weighted average shares outstanding:













Common shares end of period





Capital expenditures





Cash and cash equivalents





Current assets





Current liabilities





Adjusted working capital(1)





Long-term portion of restricted cash and deposits(2)





Total assets






Natural gas and crude oil production, before royalties

Natural gas (Mcf/d)





Natural gas liquids (bbl/d)





Crude oil (bbl/d)





Total (boe/d)








Operating netbacks ($/boe) (1)



Natural gas ($/Mcf)





Crude oil ($/bbl)





Total ($/boe)





(1)Non-IFRS measures – see “Non-IFRS Measures” section within the Q4 2022 MD&A

(2)Long term restricted cash not included in working capital


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, 2022, 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 2022 Company Working Interest Gross Reserves Highlights include:

·    3,376 Mboe of Proved Reserves (“1P Reserves”);

·    7,691 Mboe of Proved plus Probable Reserves (“2P Reserves”);

·    11,679 Mboe of Proved plus Probable plus Possible Reserves (“3P Reserves”)1;

·    1P Reserves estimated net present value before income taxes of US$57.9 million calculated at a 10% discount rate;

·    2P Reserves estimated net present value before income taxes of US$127.3 million calculated at a 10% discount rate; and

·    3P Reserves estimated net present value before income taxes of US$205.8 million calculated at a 10% discount rate.

Arrow refers readers to the Company’s press release of March 29, 2023 for additional details, as well as to the Reserve Report filed on SEDAR.


During 2022, the Company increased production on the Tapir block, from the drilling of the RCE-2 and RCS-1 wells, and the Oso Pardo field, with its Ombu block maintaining steady production. The West Pepper well was consistently producing throughout 2022 and the East Pepper Well was brought on stream, increasing the Company’s natural gas production in Canada.

Average Production by Property

Average Production Boe/d

YTD 2022

Q4 2022

Q3 2022

Q2 2022

Q1 2022

Q4 2021

Oso Pardo







Ombu (Capella)







Rio Cravo Este (Tapir)







Total Colombia







Fir, Alberta







Pepper, Alberta







TOTAL (Boe/d)







For the three months and year ended December 31, 2022, the Company’s average production was 1,736 boe/d and 1,345 boe/d, respectively, which consisted of crude oil production in Colombia at 1,185 boe/d and 847 bbl/d, natural gas production of 3,270 Mcf/d and 2,958 Mcf/d, respectively, and minor amounts of natural gas liquids from the Company’s Canadian properties. The Company’s Q4 2022 total production was 142% higher than its total production for the same period in 2021.


During Q4 2022 the Company continued to realize strong oil and gas prices, as summarized below.

Three months ended December 31




Benchmark Prices


AECO ($/Mcf)




Brent ($/bbl)




West Texas Intermediate ($/bbl)




Realized Prices


Natural gas, net of transportation ($/Mcf)




Natural gas liquids ($/bbl)




Crude oil, net of transportation ($/bbl)




Corporate average, net of transport ($/boe)(1)




   (1)Non-IFRS measure


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


Three months ended December 31

Years ended

December 31






Natural Gas ($/Mcf)

Revenue, net of transportation expense










Operating expenses





Natural Gas Operating netback(1)





Crude oil ($/bbl)

Revenue, net of transportation expense










Operating expenses





Crude Oil Operating netback(1)





Corporate ($/boe)

Revenue, net of transportation expense










Operating expenses





Corporate Operating netback(1)





(1)Non-IFRS measure

The operating netbacks of the Company continued to improve during 2022 due to several factors, such as increased production from both its Colombian and Canadian assets, and improved crude oil and natural gas prices, which were offset by increases in royalties and operating expenses for natural gas.

During 2022, the Company incurred $7.7 million of capital expenditures, primarily in connection with the drilling of the RCE-2 and RCS-1 wells, workovers in its RCE-1 and RCS-1 wells, and its East Pepper Montney well tie in in Canada. Civil works were completed to start drilling three more wells in Rio Cravo and in early 2023 the Company started 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. At the end of the year, Arrow had a cash position of $13 million, which is expected to fund the Company’s 2023 capital program.

SDX Energy

SDX  is pleased to announce that it is partnering with Aleph New Energies (“ANE”), via a Memorandum of Understanding, to explore and to develop projects in the alternative energy sector. The parties will consider any projects deemed to be alternative energy, including, but not limited to, alternative/noble gases, energy infrastructure, solar, geothermal technologies, energy storage, gas and carbon storage and waste to power. As part of the partnership SDX and ANE will work together to provide technical and commercial support to identify and develop projects; additionally, ANE will provide the financing for such projects.

Jay Bhattacherjee, Executive Chairman commented:

“We are delighted to announce this joint venture between SDX and Aleph New Energies.  This is the first step in SDX’s move to become a true energy transition company, focused on delivering shareholder returns. SDX will utilise its in-country expertise, market position and infrastructure to increase its revenue stream by offering additional products to its existing customers and attracting new ones. Aleph New Energies brings considerable industrial, market and financial knowledge and capability, and the combination of our respective skills positions us well to address attractive market opportunities.”

This is a pretty good start by the new management and shareholder team now installed at SDX and whilst it is a pretty big remit I think it is the way that things will be going and Jay has committed to the sector. 

Following on from my last note on SDX last Friday I want to add something that I picked up from Jay after the blog went to post. It is that, as he pointed out in his quote that SDX would be expanding their Moroccan operations where they are currently the only gas producers and are actively leveraging this to be a leading player in the Moroccan energy sector. 

Longboat Energy

Longboat has announced that it has reached agreement with Japan Petroleum Exploration Co., Ltd (“JAPEX”) to make a significant investment into its Norwegian subsidiary, Longboat Energy Norge AS (“Longboat Norge”), to form a joint venture. 

The joint venture will be renamed Longboat JAPEX Norge AS, with a goal of building a leading Norwegian-focussed independent.

Transaction highlights

Cash investment of up to US$50 million for 49.9% of Longboat JAPEX comprised of:


cash investment on completion of US$16 million;


a contingent consideration of US$4 million, payable on successful completion of a production acquisition currently under review; and


a further tranche of up to US$30 million, payable on a sliding scale following a successful discovery on the Velocette exploration well due to spud in Q3 2023.

JAPEX to provide the Joint Venture with a US$100 million Acquisition Financing Facility:


five-year facility to finance acquisitions and associated development costs in pursuit of the Joint Venture’s strategy; and


interest rate based on a sliding scale with an all-in cost over the term of <10%.

JAPEX, founded in 1955, is a public company listed on the Tokyo Stock Exchange (m/cap ~US$1.8 billion) with proved reserves of 159 mmboe (2022/3) and production of 58,500 boepd (FY22). JAPEX’s largest shareholder is the Japanese government (35%) via the Minister of Economy, Trade and Industry of Japan.

Longboat JAPEX will pursue a growth-led strategy to create value predominantly through the acquisition of development projects, growing 2P reserves and reaching a significant production level within three to five years. The Joint Venture will continue to target the drilling of one to three exploration and appraisal wells per year.  

Helge Hammer, Chief Executive of Longboat, commented: 

“Longboat is delighted to have found a strong and complementary strategic partner in JAPEX. JAPEX has been looking for the best way to enter Norway and identified Longboat as an excellent match to reach its strategic objective.

“The Longboat team has significant experience and expertise in the Norwegian E&P sector and has strong local industry relationships. JAPEX is a long-established E&P company with a strong balance sheet and significant worldwide technical competence including in the North Sea. By joining forces, we will have greater opportunities and strong financial backing to pursue them. We believe that this agreement has laid the foundations for exciting growth in the coming years.

“We are also pleased to be in a strong position to continue to pursue our interests in the Kveikje area as this development project is being matured and additional value created.      

“The team looks forward to delivering production and reserves growth to create value for shareholders both in Norway with JAPEX, but also in Malaysia following our recent entry into the region.” 

Masahiro Fujita, President and CEO of JAPEX, commented: 

“JAPEX is very pleased that we have formed the partnership with Longboat for a Norwegian E&P business. We see a very strong alignment in the business expansion strategy in Norway and believe the combination of the Longboat team’s significant experience and expertise in Norway and JAPEX’s technical and financial competence will be very beneficial in pursuing such a strategy.

“I look forward to working closely with the Longboat team in pursuit of our common growth strategy in Norway.”

This is a very interesting deal indeed and removes Longboats’ biggest current problem that of a perceived shortage of equity. It also provides a huge financing at pretty reasonable rates and also ensures that Velocette is paid for if it comes in. 

Longboats’ call is tomorrow morning so I will add more after their performance after that…

Hurricane Energy

Hurricane has provided an operational update. This information is unaudited, and subject to further review and adjustments.  Also provided is an update on the recommended acquisition by Prax Exploration & Production PLC of the entire issued, and to be issued, share capital of Hurricane (the “Acquisition”) to be effected by means of a Court-sanctioned scheme of arrangement under Part 26 of the Companies Act 2006 (the “Scheme”), which was announced by Hurricane and Prax on 16 March 2023.

The 34th cargo of Lancaster oil, totalling approximately 541 Mbbls, was lifted on 27 April 2023. This cargo was priced by reference to the average of the last five days of April’s Dated Brent quotes, being c. $82/bbl, resulting in net revenue of c. $43 million.

The two liftings in 2023, totalling 1,041 Mbbls, have realised an average price of c. $79 per barrel. The next cargo is anticipated to be lifted in July 2023.

As a result of the April lifting, the Board of Hurricane is highly confident that, under the terms of the offer from Prax, the full value of the Supplementary Dividend will be paid (either as a dividend or as part of the Deferred Consideration Units (DCUs)) at the same time as the Transaction Dividend and the Cash Consideration, being within 14 days of the Effective Date. Therefore, it is expected that a total of 6.02 pence per share will be paid at this time.

You never had to be a genius to predict that another $43m was headed into the Hurricane coffers and the shareholders will now get the 6.02p per share that was always on the cards. 

Prax have done very well here and should be congratulated for putting the moulah down at a time when a fossil fuel acquisition wasn’t a given. But the fact that Hurricane was lying legs akimbo waiting to be hoovered up is a travesty of business justice that should never have been allowed to happen. 

The FPSO will last longer than most of us will be on the planet and those of us who said fossil fuels will be powering most things for longer than the Judge who saved the equity holders will also be on this mortal coil. As a result, somewhere a company that could have been really something has ended up on the scrap heap of the wonderful North Sea, that shouldn’t have happened, honestly…

Empyrean Energy

Empyrean has provide an update on the Mako gas field development within the Duyung PSC, following information provided on 1 May in the quarterly report of Conrad Asia Energy Ltd, Operator of the Mako gas field.


·    Negotiation of key terms of the Mako gas sales agreement between a Singaporean buyer and the Indonesian regulator (SKKMigas) are expected to be finalised during the second quarter, with Mako  being a key strategic gas asset for both countries.

·    The Mako gas field is the largest undeveloped and fully appraised gas field in the West Natuna Basin. Gas is exported from the basin by pipeline to Singapore. The competent person’s report commissioned as part of Conrad’s IPO late last year estimated that Mako would generate gas sales of US$2.4 billion net to Conrad’s 76.5% interest (~equivalent to US$266m net to Empyrean).

·    Conrad has engaged a global investment bank with a proven track record in similar transactions to lead a farm-down process for the divestment of a portion of its interest in the Duyung Production Sharing Contract (“PSC”). Bids are expected to be received during the second quarter and the industry response to date has been encouraging.

·    Empyrean, which holds an 8.5% interest in the Duyung PSC, and through certain drag along/ tag along clauses that exist in the Duyung Joint Operating Agreement will participate pro rata in the farm-down process. Empyrean has communicated to Conrad and the global investment bank that it will also entertain bids for its entire 8.5% interest.

Gas Sales Agreement

The operator of Mako, Conrad has confirmed that negotiation of the key terms of the Mako gas sales agreement between a Singapore buyer and the Indonesian regulator (SKK Migas) are expected to be finalised during the second quarter, with the Mako gas field being an important strategic gas asset for both countries. The continued GSA negotiations have allowed Conrad to take advantage of an improved and favourable pricing environment, given strong worldwide gas demand and low supply.

Conrad hold a 76.5% interest in the Duyung PSC, with the remaining 15% interest in the Duyung PSC held by Coro Energy plc.

The 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 pleased to note that GSA negotiations look to be entering a crucial final stage with tripartite meetings being held with Conrad, the Singaporean buyer and SKKMigas. We welcome the divestment process which we view as the most appropriate way to monetise our interest in Mako and look forward to providing an update as these important negotiations unfold.”

Mako will go, like we thought the way of all things and it is in the Empyrean interest to divest it. But then most people are not in EME for Mako….

PetroTal Corp

-PetroTal has announced the appointment of José L Contreras as Senior Vice President, Operations effective May 1, 2023. 

Mr. Contreras is an executive in the international oil and gas industry with over 25 years of experience and a successful track record managing large and complex field and technical upstream operations for various sized energy companies.

No need for further comment save that it looks like a good move for PTAL. 

Angus Energy

Angus Energy is pleased to announce the commissioning of the recently drilled B7T sidetrack well at the Saltfleetby Field took place this morning. The well has been connected by a temporary flowline to the production facilities on the Saltfleetby site and processed gas is being delivered to the National Grid. At present the well is flowing at approximately 4 mmscfd with the B2 well at 2 mmscfd –  each well’s flow rate being intentionally restricted in order to allow for co-production within the capacity of a single compressor.  The A4 well has been temporarily retired in order to facilitate the balancing of pressure and flow rates of the two other wells.

The field will be operated in this mode while the new well is monitored and production stabilises and it is planned to then move to dual compressor operations and reintroduce the A4 well into production on or shortly after the 10th May. The A4 well had been producing over 2 mmscfd and the B2 well over 3 mmscfd during April to give average monthly production of 5.3 mmscfd and we look forward to reporting combined flow rates with all three wells and both compressors later in this month.

The use of a temporary flowline with additional separation permits the continued clean up of the well but avoiding wasteful gas flaring. The performance of the B7T well is expected to continue to improve with production. Construction of a permanent flowline will commence this month, with anticipated completion in late-summer.

With production now approaching a stable plateau, Angus management is now able to deploy time and resources to monetising its other oil assets, developing a long-term transition storage capability at Saltfleetby, progressing its geothermal programme and exploring other strategic opportunities.

Another piece in the jigsaw for Angus and the shares should be a lot higher, after all the upside for production and in due course distributions should be on the cards…

And finally…

Over the weekend most results were predictable, the Saints, Forest, Wolves and Leeds all lost while the Noisy Neighbours, the Bar Coders and the Red Devils all one. Game of the weekend was probably Liverpool beating Spurs 4-3 after 3-3 looked nailed on. But tonight Chelsea go to the Gooners trying not to lose 6 in a row…

And Big Sam is on his way back to the Prem apparently going to Leeds…

And Perez won the Baku GP with Max right behind him….

Author @mgrahamwood

Disclaimer & Declaration of Interest
The information, investment views and recommendations in this article are provided for general information purposes only. Nothing in this article should be construed as a solicitation to buy or sell any financial product relating to any companies under discussion or to engage in or refrain from doing so or engaging in any other transaction. Any opinions or comments are made to the best of the knowledge and belief of the writer but no responsibility is accepted for actions based on such opinions or comments. The writer may or may not hold investments in the companies under discussion

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