WTI (June) $77.07 -$1.69, Brent (June) $80.77 -$1.98, Diff -$3.70 -27c
USNG (May) $2.30 +13c, UKNG (May) 94.0p -1.68p, TTF (May) €38.975 -€0.75

Oil price

Oil rolled over yesterday after the banking crisis reared its particularly ugly head as First Republic Bank lost 50% of its value after a run on the bank. The API stats showed a decent draw of 6.083m barrels which if mirrored in the EIA stats later would be good news, at the moment despite gasoline also drawing, by 1.919m the market is cautious.

I should mention that the Halliburton figures were good, earnings of 72 cents beat the whisper of 67c but perhaps more importantly the company said that the ‘current year and the long term outlook is strong with service capacity tight’. Worth noting significant growth and I expect that Hunting, who were beaming last week should be noted.

Kistos

Yesterday I managed to spend some time in the Core London studio with Kistos Executive Chairman Andrew Austin. We talked about the recent MIME deal and his move into Norway for the first time as well as covering the rest of the portfolio. Even if I say so myself it is well worth a view…

Core Finance Chairman interview: Andrew Austin, Kistos

Challenger Energy Group

Challenger has provided the following highlights from its technical assessment of the AREA OFF-1 block, offshore Uruguay.

HIGHLIGHTS

• An initial prospect inventory of 1 to 2 billion barrels has been defined from CEG’s 2D seismic reprocessing work
• Three sizeable prospects have thus far been identified, derived from a range of play types consistent with those de-risked by recent successful conjugate margin drilling in Namibia by TotalEnergies and Shell
• Prospects are seismically-derived, and supported / further de-risked by Amplitude Variation with Offset (“AVO”) analysis
• Play robustness is corroborated by geochemical sampling and satellite seep analysis
• Conjugate margin success, competitive recent licensing rounds in Uruguay, and technical uplift from CEG’s 2023 work will drive farm-out process, soon to be initiated

SUMMARY

• The geotechnical assessment programme of the Company’s AREA OFF-1 licence is on-track to be completed by Q3 2023. This accelerated work will satisfy the entire minimum work obligations for the block’s initial four-year exploration period (i.e., to August 2026).
• Reprocessing of 2,100 kms of legacy 2D seismic (completed) and interpretation and mapping (ongoing) has confirmed considerable value uplift for the AREA OFF-1 licence, with at least three high potential prospects identified from two material play types to date.
• Technical de-risking has resulted from a range of workstreams, including AVO analysis, geochemistry seabed sampling, and satellite seep and slick imagery.

Prospect details are:

“Teru Teru” prospect – a Cretaceous turbidite play; analogous petroleum system and reservoir age to Namibian ultra-deepwater discoveries; 460 km2 in areal extent; Class II AVO supported; an estimated ultimate recoverable resource in excess of 700 MMboe; located in approximately 750 metres water depth; and with a reservoir depth of approximately 4,300 metres.

“Anapero” prospect – a Cretaceous turbidite play; analogous petroleum system and reservoir age to Namibian ultra-deepwater discoveries; 500 km2 in areal extent; Class III AVO supported; an estimated ultimate recoverable resource in excess of 500MMboe; located in approximately 750 metres water depth; and with reservoir depth of approximately 3,800 metres.

“Lenteja” prospect – an Early Cretaceous alluvial fan representing a large stratigraphic trap; analogous to proven legacy shelf discoveries in Namibia and South Africa; 425 km2 in areal extent; an estimated ultimate recoverable resource c. 500MMboe; located in approximately 85 meters water depth; and with a reservoir depth of approximately 5,000 metres.

• Continuing discretionary technical work will seek to define additional leads and prospects, further refine previous mapping of identified prospects, generate volumetrics of identified prospects, and seek to further constrain key technical risks.
• The Company has compiled a comprehensive data-room, which includes all new work completed, and following unsolicited interest from a number of industry counterparties a farm-out process is to be formally launched. Further announcements will be made as appropriate.
• The objective is for the Company to accelerate value realisation from the AREA OFF-1 licence in Uruguay by introducing a strategic partner(s) during 2023, to fast-track 3D seismic acquisition, potentially via a multi-client acquisition in early 2024, as a precursor to further value-creating field activity.

An update Uruguay AREA OFF-1 presentation is now also available on the Company’s website at www.cegplc.com. Additional details are also set out in the Appendix to this RNS.

Eytan Uliel, Chief Executive Officer of Challenger Energy, said:
“In 2020, when no other parties were ready to commit, Challenger Energy was first-mover into offshore Uruguay, securing the AREA OFF-1 block on an uncontested basis and on highly advantageous work terms. Since then, margin-opening discoveries offshore Namibia by TotalEnergies and Shell have made it possible to correlate what are now proven, oil producing source rocks directly across into the conjugate margin basins of Uruguay’s waters.

As a result, Uruguay has become a new global exploration hotspot, evidenced by the fact that in the last 12 months all but one of the available offshore blocks have been licenced by oil majors and NOCs, bidding sizeable work programs.

In direct response to the exploration success in adjacent analogue basins and the emerging industry interest it generated, we committed to remaining ahead of the game, and in late 2022 opted to accelerated our AREA OFF-1 work program. The goal was to generate a newly derived, modern dataset supporting prospect definition. The resulting prospect inventory is now informed by reprocessed legacy 2D seismic, supported by AVO attribute analysis (hugely significant as this technique is widely used in the industry as a key indicator of potential hydrocarbons), and corroborated by additional geochemical and seep analysis studies.

The results from this work have been extremely promising, in that we are now able to announce a technically supported prospect inventory of between 1 to 2 billion barrels in this globally attractive exploration hotspot.

Our next-step objective is to farm-out to an industry partner(s), so we can fast-track a 3D seismic acquisition. The high-quality data set we have now compiled, and the intellectual property created, positions us well, and we will shortly be initiating a formal farm-out process.

The world for Challenger Energy is changing rapidly. I look forward to updating shareholders as the year progresses.”

Quick thinking by Challenger management at the height of the pandemic has left them with acreage in Uruguay that is beginning to look highly prospective. The reprocessed legacy 2D seismic with the important AVO analysis searching as it does for anomalies, has led to three exciting prospects at Anapero, Lenteja and Teru Teru. 

With a farm-out process likely to see a host of the biggest and best of companies in the world fighting over acreage that looks eerily like margin-opening discoveries offshore Namibia drilled recently by TotalEnergies and Shell everyone wants to be friends with Challenger, let battle commence…

Harbour Energy

Harbour Energy is pleased to note operator Wintershall Dea’s announcement that the Kan-1 exploration well has made an oil discovery in Block 30 (Harbour 30 per cent interest), offshore Mexico.  

As announced by the operator the Kan-1 exploration well, which is located in 50 metres of water, was drilled to a total measured depth of 3,317 metres and encountered more than 170 metres of net pay. The well was subsequently side tracked up-dip and c. 250 metres of core was recovered.

The Block 30 partners will now evaluate the well data collected and put together a proposed plan to appraise the discovery.

A minimalist announcement from Harbour but this is a nice discovery and if previous finds locally are anything to go by then maybe a 250m barrel resource which falls outside the UK taxman must be worth the while…

Jadestone Energy

Jadestone yesterday reported its preliminary unaudited consolidated financial statements, as at and for the financial year ended 31 December 2022.  

Paul Blakeley, President and CEO commented:
“2022 was an extremely frustrating year operationally, one which largely overshadowed the underlying progress made in a number of key strategic areas. The first half of the year validated our strategy at work, as we generated significant operating cash flow, building our cash balance to a record high of US$162 million by mid-year.  The second half however highlighted the over-reliance on Montara for operational and financial performance, highlighting that we are vulnerable to single events on this asset.

Since we became operator of Montara in 2019, we have been undertaking an ongoing programme to revitalise the asset through a systematic process of inspection, remediation and repair. Progress has been impacted by COVID-related manning restrictions over the past 18 months, that caused delays to this programme, and which frustratingly contributed to the unplanned event in July when a small hole in storage tank 2C was detected, a tank that was scheduled to be next in the inspection programme.

We have since undertaken an extensive 8-month shutdown, which has allowed us to address required regulatory actions, and carried out a detailed inspection of critical areas of the FPSO and the necessary repairs and maintenance to restart production.  This was the right thing to do notwithstanding the major short-term impact on the business, and our clear focus from now on is to ensure to the best of our ability that there will be no further unplanned events of this nature at Montara. Since restarting production in March 2023,  Montara has performed in line with expectations, producing from three wells at c.4,700 bbls/d, with additional wells becoming available for production in the coming weeks and more cargo tanks being returned to service in due course.

Over the past eight months, Montara has stress tested our resilience, and I am very proud of the way in which the whole team has responded in these difficult circumstances to work through the issues and bring the asset back on stream. 

However, the past 8 months, although challenging, has also demonstrated that we have the right strategy, highly cash generative with quick pay-back, adding to our production portfolio in a disciplined way. In doing this, we are repositioning the portfolio to ensure this won’t be repeated, so while Montara was 80% of our production in mid-2021, it is expected to be 20% of our production by mid-2024.  Over the same period, we will have expanded the business from just two producing assets to seven in multiple countries and jurisdictions, providing the portfolio diversity that will insulate the company from the impact of such events in the future, a benefit usually exclusive to the majors and one that will differentiate us from our peers.

Despite the hiatus at Montara, our robust business model allowed us to end 2022 with an increased cash balance over the 12-month period and a US$9 million profit for the year.  This was delivered against a backdrop of an extensive capital programme, a share buy-back of approximately US$18 million, completion of two acquisitions including BP’s interest in the highly attractive CWLH assets on the North West shelf, and commencement of the Akatara gas field development, our largest ever organic project, onshore Indonesia. 

Due to a combination of first quarter 2023 liftings being back-end loaded and high activity levels throughout our portfolio, cash available by end March 2023 had reduced to US$64 million, with US$29m of debt drawn from the Interim Facility to fund the Sinphuhorm acquisition.

With respect to the RBL, we have one international bank credit approved and three others in the credit approval process, and expect the facility to close in May 2023 once customary conditions precedent are satisfied.  We also anticipate approval from NOPTA on the CWLH title transfer to Jadestone in May, which is required to draw down the RBL.  The RBL would restore our capital flexibility and even though we maintain a high level of reinvestment in the business, the highly cash generative nature of our portfolio, particularly after Akatara comes onstream, should see us approaching a net cash position around the end of 2024 based on expected operating performance and current oil prices.  Importantly, the RBL will also facilitate the funding of further acquisitions of producing assets.  Our intention as previously, will be to utilise some hedging to help secure the RBL repayment schedule, while still retaining a significant exposure to oil price upside.  In line with our approach to the final 2021 dividend, a recommendation on the final dividend for 2022 will be made when our audited accounts are released in late-May 2023.

In addition to the recently acquired gas production at Sinphuhorm, we will add the fixed price gas that is expected onstream at Akatara in the first half of next year, both of which give increased reliability to future cash flows. 

Strong growth in the business is emphasised by the 45% increase in 2P reserves at year-end, circa six times production replacement, and it is worth recognising, that we have maintained asset reserves at Montara, reinforcing the principle that despite the shut-down, reserves and cash flows have been deferred and not lost.  This provides a lot of encouragement for the future; our company has been proven to be resilient through the challenges we have faced and we have strengthened the business through both product and portfolio diversification, a strategy we will continue to pursue.

2023 should be a promising year for Jadestone with the Akatara project in the Lemang PSC on schedule and within budget, an exciting four well programme at East Belumut, closing of Sinphuhorm and the potential to add to the portfolio through further acquisitions.  

I’m extremely grateful to the people within Jadestone who have worked tirelessly across the business to get us back on track, and despite a period of significant challenge imposed by the events of the past several months, have never wavered from doing the right thing.  It has been a challenging year, lessons have been learned and implemented, but we look forward with renewed confidence to the future”

Paul Blakeley
EXECUTIVE DIRECTOR, PRESIDENT AND CHIEF EXECUTIVE OFFICER

It is important for followers of Jadestone to realise that by reading the statement above that the whole of the current picture for the company is accurately and fairly portrayed and that furthermore the company is in very good hands. 

Yes, history will record the Montara accident as putting the brakes on JSE and almost writing 2022 off, too many eggs in one basket, certainly, lesson learned definitely, but in no way is it game over for Jadestone. The very fact that going into 2022 all looked good and the trophy asset of Montara was going to carry all in front of it meaning that the year end would have seen cash of some $300m and shareholder distributions at a record level. 

That whilst Montara can get back to peak production and yet only be 20% of production by mid 2024 from 80% shows just how much ammunition there is in the portfolio. Read for yourself the individual assets that can generate the difference at CWLH, Akatara, Stag, Penmal and Sinphuhorm whilst the RBL will join the huge $110-140m capex budget for work in the M&A market which I am confident they will deliver more from.

At the AGM we will hear more about the distribution policy but I am convinced it will please shareholders as the company returns to substantial payouts. Paul leads a high quality team of best in class operators in all areas of the company, I am convinced that my faith in the company, predicated by not taking them from the Bucket List throughout this year will be justified and they stay in there with 100% confidence.

 The audited financial results will be released on 25 May 2023 together with the release of the Group’s FY2022 Annual Report.

Operational and financial summary

• Proven and probable reserves at year-end 2022 totalled 64.8 mmboe, a 45% increase compared to the reserves at year-end 2021 of 44.7 mmbbls, representing a reserves replacement of 579%, reflecting the conversion of Akatara gas field contingent resources to reserves and addition of the non-operating working interest in the Cossack, Wanaea, Lambert and Hermes (“CWLH”) Assets, offset by production and modest technical revisions during the year;
• Full year production decreased by 8% to 11,487 boe/d (2021: 12,545 bbls/d), due to Montara being shut-in for tank repairs from August 2022 and the FPSO class suspension at the non-operated Peninsular Malaysia (“PenMal”) Assets.  This was offset by higher annualised production at the operated PenMal Assets due to a full year of operations in 2022 and two months’ contribution from the CWLH Assets;
• Total lifted volumes in 2022 decreased 7% to 4.3 mmboe (included lifted volumes of 0.7 mmbbls from the CWLH Assets), compared to 4.7 mmboe in 2021, reflecting lower production at Montara and the non-operated PenMal Assets;
• Total revenue increased 24% to US$421.6 million (2021: US$340.2 million) due to a 40% increase in realised prices, partly offset by a 7% reduction in lifted volumes;
• The average realised price for the year was US$103.85/bbl in 2022 (2021: US$74.34/bbl), a 40% increase year-on-year.  The average realised price premium was US$7.81/bbl for 2022 (2021: US$3.39/bbl);

Total production costs of US$250.7 million, compared to US$211.9 million in 2021, due to:

• The inclusion of US$37.8 million in 2022 associated with the CWLH Assets acquired in November 2022, consisting of US$3.7 million cash operating costs and an additional US$34.1 million of non-cash inventory movements, relating to moving from a significant underlift position to an overlift position following the lifting which occurred in mid-November 2022;
• A full year of operations and supplementary payments at the PenMal Assets following their acquisition in August 2021, whereby the supplementary payment also increased due to higher realised oil prices;
• Reduced production costs at Montara reflecting the shut-in from August 2022 through the end of 2022; and
• Lower Stag production costs due to reduced workover activities in 2022 compared to the previous year.

In line with previous disclosures, adjusted annualised unit operating costs(2) for 2022 were US$37.49/boe, compared to US$26.22/bbl in 2021, primarily due to the lower production from Montara and the non-operated PenMal Assets;

• Adjusted EBITDAX increased by 14% to US$161.9 million compared to US$142.2 million in 2021, predominately due to higher oil prices driving higher revenues party offset by lower adjustments for one-off expenditures;
• Net profit after tax of US$8.5 million (2021: US$17.1 million loss after tax);
• Operating cash flow generation in 2022 of US$158.1 million, before movements in working capital, up 73% compared to 2021 of US$91.2 million;
• Capital expenditure of US$82.9 million (2021: US$56.0 million), a 48% increase from 2021, primarily due to the Stag infill drilling programme completed in 2022 and the Akatara gas development at the Lemang PSC. The administration expenses related to the Lemang PSC are accounted for as operating expenditures (as Administrative Staff Costs and Other Expenses) of approximately US$2.0 million in 2022;
• Cash balances of US$123.3 million at 2022-year end, 5% higher compared to 2021 at US$117.9 million.
• The share buyback programme acquired 18.2 million shares in 2022, at an average cost of US$0.88 (0.76 GBp) per share for a total cost of US$16.2 million; and
• On 20 September 2022, the Directors declared a 2022 interim dividend of 0.65 US cents/share, equivalent to a total distribution of US$3.0 million. In line with the approach taken in respect of the final 2021 dividend in June 2022, a recommendation on the final dividend for 2022 will be made when the Group’s audited accounts are released in late-May 2023.

Business development

• On 6 June 2022, the Group took the final investment decision to develop the Akatara gas field, onshore Indonesia, with project completion and first gas scheduled in the first half of 2024;
• On 27 October 2022, the Group announced the termination of the Maari acquisition due to a lack of progress on regulatory approvals and resultant uncertainty over the timing for the transfer of interest and operatorship;
• On 28 July 2022, the Group executed a sale and purchase agreement with BP Developments Australia Pty Ltd (“BP”) to acquire BP’s non-operated 16.67% working interest in the CWLH oil field development, offshore Western Australia; and
• On 24 November 2021, the Group executed a settlement and transfer agreement with PT Hexindo Gemilang Jaya (“Hexindo”) to acquire the remaining 10% interest in the Lemang PSC.

Significant and subsequent events 

• On 7 February 2022, the Bunga Kertas FPSO, deployed at the non-operated PenMal Assets, had its class suspended, resulting in operations being shut-in and production suspended. Jadestone has assumed operatorship of the non-operated licences following the decision of the previous operator to withdraw. Jadestone looks forward to evaluating redevelopment options for the fields;
• On 17 June 2022, the Montara FPSO released between three to five cubic metres of crude oil to sea during a routine oil transfer between storage tanks.  As a precaution, production was shut in and the relevant authorities were notified.  Following a temporary repair and isolation of the tank where the leak originated, production restarted while a permanent repair was developed. On 12 August 2022, an additional defect was identified in a ballast water tank, after which the Group took the decision to shut in production and prioritise permanent repairs. In response to the new defect, the regulator issued a General Direction requiring an independent assessment of the storage tanks before restarting production. Following the submission of the independent review of the Group’s remediation plans and operational readiness for the Montara Venture FPSO on 8 February 2023, the local regulator lifted the General Direction on 27 February 2023 and Montara production resumed on 21 March 2023;
• On 19 January 2023, the Group executed a sale and purchase agreement with Salamander Energy (S.E. Asia) Limited (the “Seller”), an affiliate of PT Medco Energi Internasional Tbk to acquire the Seller’s interest in three legal entities, which collectively own a 9.52% non-operated interest in the producing Sinphuhorm gas field and a 27.2% interest in the Dong Mun gas discovery onshore northeast Thailand; and
• On 17 February 2023, the Group closed a US$50.0 million debt facility (“Interim Facility”) with two international banks. The closing of the Interim Facility forms part of the previously announced plan to arrange a reserves-based lending facility (“RBL”), which is a key element of the Group’s medium-term financing strategy to fund development capital at the Indonesian Akatara Gas Project and enable further inorganic growth of the Group. US$28.5 million of the Interim Facility was drawn to fund the acquisition of a 9.52% interest in the Sinphuhorm gas field, with Group cash balances of US$63.9 million as at 31 March 2023. The Group continues to make good progress on the RBL workstreams, with one international bank credit approved and three others in the credit approval process, with signing of the RBL facility agreement targeted for May 2023.  Once signed, the RBL is expected to close shortly thereafter once all customary conditions precedent are satisfied. It is expected that approval from the National Offshore Petroleum Titles Administrator (“NOPTA”) of the transfer of titles relating to the acquisition for the CWLH fields interest will be required prior to drawing down the RBL.

2023 Guidance

• Production for the first three months of 2023 averaged just over 10,000 boe/d, reflecting tank repair and scheduled maintenance activities at Montara.  Production for the nine months ending 31 December 2023 is expected to average 13,500-17,000 boe/d;
• Underlying operating costs in 2023 are expected to total US$180.0-210.0 million.  When adjusted for a full-year of operating costs associated with the CWLH Assets acquisition, higher tanker costs at Stag and higher logistics costs at Montara in 2023, underlying operating costs are expected to be c.6% higher year-on-year, demonstrating cost control in an inflationary environment; and
• Capital expenditure guidance for 2023 is expected to total US$110.0-140.0 million, the largest investment programme in the Group’s history. This is allocated primarily to the Akatara gas development project (c.70%), which is progressing well and remains on budget and schedule for first gas in H1 2024.  A further 15% will be spent on the PM323 PSC infill drilling campaign offshore Malaysia.

1. 1 Realised oil price represents the actual selling price inclusive of premiums.
2. 2 Operating costs per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail on the Non-IFRS Measures section in this document.

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