Malcy’s Blog: Flash blog: IOG, Arrow, Longboat.

Another flash blog from over the pond, the same rules apply and if I chat to senior management on my return I will add over the next few days.

IOG

IOG has provided a summary of its FY2022 annual reserves and resources review. This review involves a technical reassessment by the Company’s subsurface team of all portfolio assets to generate updated reserves and resources estimates.

The update describes management’s current assessment of the portfolio and has been approved by the HSE and Technical Committee and the Board. It follows the Petroleum Resources Management System (PRMS) classification framework. In the case of production assets, it is based on static and dynamic models that have been updated and history matched over field life to date. In the case of pre-production assets, it is based on interpretations of reprocessed seismic and well data where applicable.

Reserves

Field

Gross billion cubic feet equivalent (BCFE)

YE 2021

2022 Production

YE2022

1P

2P

3P

1P

2P

3P

Blythe

25.9

43.3

56.9

4.1

24.6

42.3

46.8

Elgood

5.7

7.8

7.9

4.1

0.4

2.2

2.8

Southwark

46.3

71.3

104.8

0.0

0.0

10.0

15.0

Blythe

Blythe FY2022 1P and 2P reserve estimates represent a modest increase on FY2021 estimates, factoring in 2022 production of 4.1 billion cubic feet equivalent (BCFE, where condensate is converted into gas equivalent at 5.8 bbl/mcf)

–     1P case assumes production only from the H1 well, as H2 was not sanctioned at year end  

–     2P case assumes production from H1 and H2, which was sanctioned in February 2023   

Elgood

Elgood produced 4.1 BCFE in 2022. Production of the remaining reserves is expected to require pipeline dewatering and onshore compression.  

–     1P case assumes 0.4 BCFE production post-dewatering

–     2P case assumes 0.4 BCFE post dewatering and a further 1.8 BCFE post-compression

Southwark

As previously stated, Southwark is undergoing further detailed technical review following the A2 well result, involving external technical expertise. This will inform the A1 plan and may also result in a further revision of the estimated reserves range.   

Pending that review, the current estimated range reflects the uncertainty following A2 as to the recoverability of commercial gas volumes from the A1 and A2 wells.   

–     1P case assumes no production is possible from the field

–     2P case assumes production from the A1 well only, based on a limited stimulation scenario, with no production from the A2 well

Reclassified Contingent Resources: Nailsworth and Elland  

Field

Gross BCFE

YE 2021

YE2022

1P

2P

3P

1C

2C

3C

Nailsworth

63.9

105.2

155.9

48.5

84.9

140.2

Elland

39.9

55.0

72.9

39.9

55.0

72.9

The Nailsworth and Elland gas fields, which are envisaged to be part of a Central Hub development in the area north of Southwark, have been reclassified from the lowest ranked reserve category under PRMS, Justified for Development, to the highest ranked contingent resource category, Development Pending. This classification is considered currently more appropriate given the evolution in development plans from the earlier FDP version that informed the October 2017 Competent Persons Report. Both assets would then be expected to be reclassified to Reserves Justified for Development upon Final Investment Decision.

In addition, the estimated contingent resources range for Nailsworth has been updated to 1C / 2C / 3C 48.5 / 84.9 / 140.2 BCFE. This follows a full subsurface uncertainty analysis which included updates to the static and dynamic models. The post-A2 detailed technical review of Southwark could also have implications for the Nailsworth estimated resource range in future. The volumetric estimates on the Elland gas field have not changed.

Contingent Resources for other assets

Field

Gross BCFE

YE 2021

YE2022

1C

2C

3C

1C

2C

3C

Goddard

52.0

115.0

169.0

52.0

115.0

169.0

Abbeydale

19.0

23.0

25.0

19.0

23.0

25.0

Grafton

24.0

35.0

46.0

24.0

35.0

46.0

Panther

38.0

46.0

55.0

38.0

46.0

55.0

The volumetric estimated range of contingent resources have not changed for these four gas fields.

Prospective Resources 

Prospect

Gross BCFE

YE 2021

YE2022

Low

Mid

High

GCoS

Low

Mid

High

GCoS

Goddard Flank 1

16.0

27.0

42.0

71%

16.0

27.0

42.0

71%

Goddard Flank 2

30.0

50.0

73.0

71%

30.0

50.0

73.0

71%

Southsea

13.0

31.0

76.0

48%

13.0

31.0

76.0

48%

Kelham North

34.0

46.0

58.0

72%

34.0

46.0

58.0

72%

Kelham Central

11.0

16.0

22.0

72%

11.0

16.0

22.0

72%

Thornbridge

9.0

15.0

20.0

64%

9.0

15.0

20.0

64%

Thornbridge Deep

24.0

46.0

76.0

18%

24.0

46.0

76.0

18%

Orrell (on licence)

12.6

17.6

21.0

100%

11.0

16.0

22.0

100%

Of the prospects in the portfolio, only the Orrell structure, which lies partly within the P2442 licence area, has been slightly revised since the previous assessment. Subject to further technical assessment and successful appraisal of the Kelham North and Kelham Central structures, Orrell could potentially become part of a Southern Hub development. This would be most likely via a single well subsea tie-back to an unmanned host platform and is also envisaged to include the Abbeydale discovery which lies south-east of Kelham North and Kelham Central.

As previously noted, IOG also applied in the 33rd UK Offshore Licensing Round with its joint venture partner CalEnergy for nine blocks in five licences across the Saturn Banks catchment area that all contain existing gas discoveries.

Finally, the reserves and resources estimates contained herein are based on a current assumed date for the start-up of onshore compression of March 2027. The work on compression is currently at concept feasibility evaluation stage.

Rupert Newall, CEO of IOG, commented:

“This comprehensive and rigorous annual reassessment of all our reserves and resources is an essential pre-requisite for maximising the value of our portfolio. It provides the technical baseline for our operational and investment plans, based on a realistic and balanced subsurface view of each asset.

This work continues throughout the year and is now informed by nearly a full year of production data for Blythe and Elgood, recent drilling data for Southwark, as well as ongoing remapping, reinterpretation and remodelling of the pre-development discoveries and prospects in the portfolio.”

It is quite difficult for IOG to give an accurate and up to date technical view of the portfolio particularly at the moment when post-A2 the new management team is by its very nature being   prudent. This is because the detailed follow-on review of the field is underway and until then the outcome is not clear, the last thing to do is to come out as being overly optimistic.

Elsewhere as Rupert Newall comments, data is helped by nearly a full year of production from Blythe and Elgood, recent drilling data from Southwark and technical work right across the portfolio. Indeed, the Blythe numbers are holding up well and the H2 well (which wasn’t sanctioned at year end hence isn’t reflected in the 1P number) will help ensure recovery of the 2P reserves.

The aforementioned new team is flat to the boards and the portfolio has extensive opportunities in many areas and of course has made 33rd Round applications all of which show upside for IOG with submissions already in.

Arrow Exploration

Arrow has provided an update on the Rio Cravo Este-3 well (“RCE‑3”), an appraisal / development well on the Tapir Block in the Llanos Basin of Colombia.

RCE-3

The RCE-3 well was spud on February 8, 2023 and reached target depth on February 16, 2023.  RCE‑3 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 8,880 feet (8,087 feet true vertical depth) and encountered seven hydrocarbon bearing intervals totaling 58 net feet of oil pay.

The well was completed in the C7-A and C7 Stringer zones and the well is currently producing from those zones.  A submersible pump has been inserted but not turned on. The well flowed naturally at rates equivalent to 2,000 BOPD gross for four hours after unloading kill fluid. The well is currently being choked back with a 18/168 choke and, in the last 24 hours, it has produced at a rate of 968 BOPD gross (484 BOPD net) of oil at 28.5 API and with a 0% water cut.  The Company will provide a further update on production rates in due course.

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

Marshall Abbott, CEO of Arrow commented:

“We are very encouraged by the initial production of RCE-3, the fourth well on the Tapir block. The well was completed in the C7-A and C7 Stringer zones with additional zones currently behind pipe.”

“RCE-3 is currently flowing better than expected.  The Company is choking the well back in an effort to manage the reservoir and discourage premature water production.  Arrow plans to engage the pump and slowly increase production once the well has stabilized.”

“The continued strong production rates from existing tied-in wells combined with the encouraging results from new wells in Colombia continues to provide us with confidence that our objective of achieving a production rate of 3,000 boe/d within 18 months of the AIM listing can be achieved.  This is an exciting time for Arrow, and we look forward to providing further updates on our progress.”

Well, I’ve spent a while waiting for this and the first drill of a 10 well programme has not let me down. After a flying start the well is settling down nicely whichever stat you look at. It’s 28.5* API, working with a small choke, without a pump (fitted but not switched on yet) and has settled down to around 483 b/d with no water cut all of which beat pre-drill expectations. 

The well programme kicks on, RCE-4 is already under way and if as expected will be producing by the end of this month, if the last drill is anything to go by it may be another fastest well on the block. After that RCE-5 will spud.

My target price for Arrow remains at 50p per share but to be frank if this programme continues to deliver the goods as it has started then the world is your oyster…

 

The RCE-3 well costs came in under budget and was the quickest well drilled to date on the block.

RCE-4 and RCE-5 Wells

The RCE-4 well was spud on March 1, 2023 and is currently drilling.  Expectations are that the RCE-4 well will be complete and brought on production towards the end of March.  Plans are then to skid the rig to the RCE-5 location and begin drilling.

Capella Field

The Capella field continues to be shut in and discussions between the government, protesters and the operator are ongoing.  The Company hopes for a quick resolution of the protesters’ concerns.

Longboat Energy

Longboat Energy, the emerging full-cycle E&P company, provides an update on the status of the PL 939 licence which contains the Egyptian Vulture oil discovery.

In October 2021, Longboat announced the Egyptian Vulture light oil discovery (Longboat 15%) close to infrastructure on the Halten Terrace in the Norwegian Sea. The discovery is visible on seismic as a large amplitude anomaly and intensive technical studies have been undertaken to de-risk the discovery with particular focus on seismic interpretation and distribution of areas with good reservoir. As part of this work, ERCE provided an independent assessment of the discovery in a Competent Person Report commissioned by Longboat, which has confirmed the 1C-3C size of the discovery at gross 4-68 mmboe.

For an appraisal well on Egyptian Vulture to be successful, it would need to encounter better reservoir quality than that penetrated by the discovery well.  The Joint Venture participants, following extensive technical work, have been unable to form an aligned view regarding an appraisal well and will not be committing to a licence extension as required on 2 March 2023. Therefore the licence is being relinquished.  

However, Longboat is looking to form a new group to take the asset forward and rather than take over the existing licence, which would involve escalating license fees, will seek to re-apply for the acreage in the forthcoming licence round with awards due in January 2024.

Helge Hammer, Chief Executive of Longboat, commented: 

“The Egyptian Vulture discovery has significant upside and needs an aligned partnership to be efficiently appraised and progressed to a potential development project. We look forward to creating a new group to take this high-potential asset forward.” 

Well, this certainly came out of west field, for me anyway. Right now it seems like there needs to be a bit of marketing to new potential partners who will come in on a sort of guaranty of a discovery in an upcoming licence round. Interesting times huh?

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