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Challenger Energy Group – Bahamas Petroleum reboot?

spasmodicus
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Challenger Energy Group – Bahamas Petroleum reboot?

#418619

Postby spasmodicus » June 10th, 2021, 1:57 pm

Challenger Energy Group – Bahamas Petroleum reboot

Bahamas Petroleum Company BPC has changed its name to Challenger Energy group, with ticker CEG.

See the original BPC thread:
https://www.lemonfool.co.uk/viewtopic.php?f=16&t=27792

BPC has a chequered history, to say the least and I retained a small (in value) shareholding having mostly sold out at a modest profit before the price crashed, following the disappointing result of their Bahamas Shelf wildcat well Perseverence-1. Now what? In my last post on the old BPC thread I said that I would not be subscribing to the rights isue/open offer for more shares at 0.35p. The share price subsequently fell, after allowing for the 10:1 consolidation, to less than 3p.

Estimates vary, but over its lifetime BPC burned through at least $100 million, with very little to show for it and, as a result of various placings, convertible loan notes and other devices to extract funding, from a no doubt diminishing and increasingly sceptical band of investors, had several billion shares in issue, priced at fractions of a penny.

The markets have turned their back on CEG and my holding in it was worth practically nothing as of the recent 10:1 consolidation, but I wondered whether there might be a contrarian case for a successful reboot of this essentially bombed out company.

Warning: This post rambles on a bit

FINANCIALS

As a result of its recent merger with CERP (Columbus Energy Resources PLC) in 2019/20, the most recent financial accounts published by the company are difficult to interpret /non existent, for the purposes of illuminating production figures, opex, capex, cash and liabilities required to value the company. What is the financial situation as of today? This is a controversial subject, as the chat threads at ADVFN and LSE reveal in vociferous, if generally inaccurate detail.

On their website CEG's most recent financial report was "Interim financial statements to June 2020", where it was stated
As the merger with CERP did not complete until after the reporting date, these interim financial statements do not reflect the expanded operations and asset base of the now enlarged Group,and therefore are not reflective of our broader vision going forward.A fully consolidated financial report for the enlarged Group will be provided in the next Annual Report, which will be prepared to 31 December 2020 and released in the first half of 2021


The report reveals
cash position of over $12m, almost $1m more that it started with in January (2020) -ongoing expenditure against well preparations and corporate costs weremore than offset by additional capital securedthrough the unconditional convertible loan note facility entered into with a Bahamian family office in February 2020, coupled with a strict approach to cash management implemented in the face of the unfolding Covid-19 pandemic

a later report RNS Number : 2483T 24/03/21 said
Final Perseverance #1 drilling cost expected to be approx. $45 million compared to pre-drill estimate of approx. $35 million; additional costs of approx. $10 million incurred as a result of heightened Covid-19 procedures (approx. $3 million) and side-tracking operations related to mechanical debris in the well (approx. $7 million)

Cash on hand of approx. $13 million (as at 1 March 2021, including unconditionally committed convertible notes); anticipated additional capital requirement in 2021/22 across the business of $25 - $40 million, the Company expects to more than cover the difference from various potential funding sources

Fund Raising Rights Issue
Before the name change, BPC recently carried out a fund raising open offer / rights issue at 0.35 pence, As mentioned before at the end of the Bahamas Petroleum thread, I declined this offer, as the SP at that point was (and remains) lower than the offer price. I retained a few shares, worth less than £300 at the current SP, as my interest was attracted by the complete change in BPC/CEG's direction.

We learn from RNS Number : 3077Z 20/ May 2021
Open Offer closed with c.38.15% take-up from existing shareholders raising gross proceeds of £2.63 million (US$3.72 million) through the issue of 750,289,637 ordinary shares at a price of 0.35p each ("Open Offer Shares").

· Successful Placing to raise additional gross proceeds of £4.26 million (US$6 million) through the further issue of 1,216,599,935 ordinary shares at a price of 0.35p each ("Placing Shares").

· Aggregate gross proceeds of £6.9 million (US$9.75 million) from Open Offer and Placing.


Share Consolidation
CEG also went from being a sub-penny stock to a penny stock by doing a 10:1 share consolidation, resulting in around 800,000,000 shares in issue and a market cap of about $24million at a share price of 3p.

Cash flow
In a success case, total potential capex requirement through balance of 2021 is in the range of $20m – $25m, with cash flows generated from early wells reinvested into / funding drilling of subsequent wells.
RNS 0737H 1 Dec 2020
https://www.investegate.co.uk/article.aspx?id=202012010700070737H

CEG obtained producing assets in Trinidad as a result of its merger with CERP. Current production is stated to be around 400-500bbl/day, which cash flow potential of $3m+ pa. It is not stated anywhere that I could find what the Saffron-1 results amounted to in terms of flow rates, pressure decline etc. The Saffron-2 well is expected to flow 200-300bbl/day, i.e. cash flow of about $1.8m pa or so.

Everything else is somewhat speculative. The company states on its website that Saffron field development in H2 2021 might result in a further 1000 bbl/day of production. This would imply maybe a 5 well program, all successfully completed in the next 7 months, which seems like a tall order, given that we will not know the results from Saffron-2 for another month or so.

The company itself estimated that it would have cash in hand of $10m to $15m in March 2021, depending on outcome of Perseverence-1 remaining costs, see the above link to RNS 0737H 1 Dec 2020

Until end 2021, let's say cash in hand $12.5m
the recent placing raised $6.9m
$3m from current production
$1.8m from Saffron 2 and subsequent drilling
That's $24.2m, which would just about cover the 2021 year $20-25m capex estimate (to geological accuracy anyway)

Financial Conclusion
The company seems to have enough cash to carry out its operations in 2021
What we really need is a decent set of accounts, which have been promised for H1 2021. One month to go, but
Stop press! RNS 0167B announcement June 7th 2021
......AIM Regulation has granted the Company an additional period of up to three months to publish its annual audited accounts for the year ended 31 December 2020.
excuses, excuses?


THE E&P PROSPECTS

Post merger with CERP, CEG has licences on the Bahamas shelf (offshore), Trinidad(onshore), in Suriname(onshore) and in July last year it acquired a block in Uruguay(offshore).

CEG's main hope for pulling itself up by its own bootstraps seems to hinge on its activities inTrinidad and possibly in Suriname. After drilling the unsuccessful Perseverence-1 wildcat well on the Bahamas shelf, a pretty much make or break event which drained about $40m of cash from BPC's balance sheet, CEG's attention is now focussed on field extension and rejuvenation in SWP (South West Peninsular) Trinidad, in the licence acreage that it acquired as a result of BPC's merger with CERP a year or two ago. Information on these licences can be found here
https://www.londonstockexchange.com/news-article/BPC/operational-update-trinidad-tobago-and-suriname/14741377?lang=en

and the most recent update here as of a March 2021 presentation
https://d1ssu070pg2v9i.cloudfront.net/pex/bahamas/2021/03/25213812/bpc-update-presentation-march-21.pdf

URUGUAY
see
https://www.offshore-energy.biz/bahamas-petroleum-awarded-block-offshore-uruguay/
a pure exploration play - analogous to offshore Guyana and Suriname.
Existing wells and data., US$800,000 commitment over 4 years initial term. No drilling obligation
The problem is, it's offshore and thereby expensive to drill and will have little or no effect on CEG's immediate fortunes, except for the current $200k/year negative cash flow.

BAHAMAS
CEG hopes to farm out the Bahamas acreage, on the basis that BPC's Perseverence-1 proved up a working petroleum system, even though it was not commercial. They say:
Bahamas shelf – Monetise licence investment through securing farm in partner. I think that the chances of this happening in the present oil industry investment climate are slim to zero, but who knows?

SURINAME
The Suriname acreage is interesting. They have an agreement with Staatsolie on their Weg Naar Zee field, which (in 2019) contained an initial commitment of $250k for 3 years G&G studies, plus further optional commitments to shoot seismic and drill wells. The expected upside from this was 24mmbbl STOIIP. As of November 2020 it was said

As a result of these studies, BPC has prepared and submitted the drilling program for approval to Staatsolie (the state-owned oil company in Suriname and the Weg Naar Zee Production Sharing Contract partner). At the same time, necessary environmental studies have been submitted to NIMOS, the Suriname National Institute of Environment and Development.

Once approved, BPC is planning for drilling of WNZ09.02 to occur in Q1 2021, with a locally sourced rig, to a total depth of approximately 1,100 ft, and producing the well immediately thereafter. Any production from the WNZ09.02 well can be immediately transported and sold to the local refinery, located approximately 30 kilometres from the proposed well site.
It didn't happen in Q1 2021, due to covid probably.


They said recently: Suriname – field development - CPR assessed resources 2C 1.1 mmbbls, 3C 3.5 mmbbls (notwithstanding their original 3P-ish estimate of 24 mmbbls)
Budget (including pumps and ability to produce) $1.1 million
Operations support from Trinidad
production leads directly to refinery sales6 -12 wells (over 1 year) potentially yielding 100 -200 bopd
Operations support? Maybe a euphemism for "use cash from Trinidad operation that we hope to generate from successful Saffron-2 well and other drilling there"?

TRINIDAD
BPC/CEG obtained several small, producing but depleted field licence areas from the merger with CERP, allegedly producing 400-500 bbls/day. The immediate future seems to hinge on the potential of the Saffron-2 well in the Bonasse field area to increase this to in excess of 1000 bbl/day. Saffron-2, which was spudded a few days ago, despite the ongoing covid emergency in Trinidad, should be down to its TD in about one month.

Historical Review of CEG's Trinidad Acreage
Before looking in more detail at the future, it's as well to review the past. The history of the assets that CEG now owns is complicated, to say the least, and estimates of reserves vary accordingly. If you like long and complicated sagas, whose potential for future profitability is very hard to estimate, then this is for you!

The RNSs tell their own story.

RNS 8833K 27 April 2020
https://www.londonstockexchange.com/news-article/CERP/saffron-discoveries-lower-cruse-and-middle-cruse/14516801?lang=en
• Oil discoveries in the Lower Cruse and Middle Cruse
• 2363 ft of Gross sands with six reservoir intervals of interest with a 47% Net/Gross ratio
• Well reached Total Depth ("TD") at 4,634 feet, as planned
• 6 intervals identified for testing, with 3 intervals tested to date
• In the Lower Cruse, high quality, light oil (circa 40° API) recovered to surface
• Results in line with the Company's pre-drill estimates for recovery of oil from a Lower Cruse development (11.5mmbbl)
• Signed terms for a full carry of the second Saffron Lower Cruse appraisal and development well (expected Q3 2020)
• In the Middle Cruse, discovery of a medium quality crude (17° to 20° API)
• Currently producing oil from first perforated interval in the Middle Cruse
• Middle Cruse oil processed on location and first 340 bbls oil sold through existing infrastructure
• Preparing to test the Middle Cruse in additional oil bearing zones
• Preparing individual development plans for the Middle and Lower Cruse discoveries



Shares mag / RNS Number : 0687E 03 Nov 2020
https://www.sharesmagazine.co.uk/news/market/LSE20201103070006_3768015/Operational-Update-Trinidad-Tobago-and-Suriname

BPC (aka Challenger) has undertaken a comprehensive review of the drilling campaign that was undertaken for the Saffron #1 well (a discovery of undrained light oil in the Lower Cruse reservoir formation) by Columbus in early 2020. This has included a review of the well design, its operational execution, and a reassessment of the technical results from a geological and reservoir perspective. This work identified a number of operational issues with the Saffron #1 drilling campaign which BPC believes can be managed / optimised in future activities so as to improve overall asset performance.
More significantly, this work has also confirmed the potential for a material development of the Lower Cruse formation, as well as further draining of the Middle Cruse, across the mapped Saffron field, and has resulted in:
· confirmation of management's estimates that over 10 MMbbls of recoverable resources are available within the Saffron structure;
· an optimised subsurface target location for Saffron #2


According to RNS Number : 0737H
Bahamas Petroleum Company PLC
01 December 2020
Following completion of the merger of BPC with Columbus in August 2020, BPC commissioned an independent Competent Person's Report ("CPR") from ERC Equipoise ("ERCE"). The scope of the report was to focus on reserves and contingent resources across the Company's existing producing assets in Trinidad and Tobago, and the Company's Weg naar Zee licence in Suriname, so as to enable to Company to develop its work program for 2021 and make appropriate capital allocation decisions.
ERCE concluded

Reserves mmbbls

East Fields
1P 0.53
2P 1.09
3P 1.66
West Fields
1P 0.16
2P 0.20
3P 0.26

However, a footnote points out 4. ERCE have not audited the SWP (South West Peninsular), including Saffron as part of this Independent CPR

I ask myself why ERCE did not assess, or were not asked to assess, the Bonasse field, the Saffron #1 well and the potential for Saffron #2, when the associated reserves, variously predicted around 10 or 11mmbbls recoverable, would seem to constitute CEG's biggest potential asset?

For Columbus' (CERP) history, see RNS Number : 8387A
https://uk.advfn.com/stock-market/london/columbus-energy-resources-CERP/share-news/Columbus-Energy-Resources-PLC-Report-and-Accounts/80042689

showing CERP's (loss making) accounts at June 2019

going back futher to 2018, CERP acquired Trinidad assets from a local outfit named Steeldrum, according to
https://investegate.co.uk/columbus-energy-res--cerp-/rns/completion-of-steeldrum-acquisition/201810080700042027D/

RNS Number : 2027D
Columbus Energy Resources PLC
08 October 2018
"The portfolio includes low-risk but highly prospective exploration opportunities in the South West Peninsula ("SWP"), a development project in Cory Moruga and 5 producing oilfields (Goudron, Innis Trinity, South Erin, Bonasse and Icacos). This provides the Company with an excellent opportunity to exploit our existing and new assets ........"

and we learn
Steeldrum is the parent company for the West Indian Energy Group Ltd and is the owner of the licences for the Innis-Trinity field (100% and operator), South Erin field (100% and operator) and the Cory Moruga development project (83.8% and operator), all located in southern Trinidad and close to Columbus's existing assets.
The Innis-Trinity field and South Erin field are currently producing approximately 150 barrels of oil per day ("bopd") and 100 bopd respectively, with remaining 2P reserves of approximately 4 million barrels of oil ("mmbbl") and 1.6 mmbbl respectively. The Cory Moruga development is expected to have recoverable reserves of approximately 1.1 mmbbl.


The Bonasse field, where Saffron-1 well was drilled, doesn't get a mention and we are led to believe that the other fields mentioned above have total 2P reserves of approx 6.7 mmbbls.
Going back further still to Oct 2015, I learned that CERP was originally AIM:LGO (the name change occurred in mid 2017), which acquired the Bonasse field from BOLT (Beach Oilfield Ltd), see
https://www.proactiveinvestors.com/companies/news/116089/lgo-energy-strikes-bolt-deal-to-access-shallow-oil-116089.html
however in March 2018 this was renegotiated, according to
https://www.investegate.co.uk/columbus-energy-res/rns/renegotiation-of-bolt-transaction/201803190700050607I/
Renegotiation of BOLT Transaction
RNS Number : 0607I
Columbus Energy Resources PLC
19 March 2018
some key points emerge

e. Columbus acquiring access to all oil and gas rights on the SWP

g. Columbus paying deferred consideration to BOLT of: (i) US$500,000 upon the development of any field (other than the Bonasse Field) situated within the Existing Lease; and (ii) a royalty of 3% on net production from a development of the SWP licence (excluding the Bonasse Field). The royalty is payable on net production exceeding 10 million barrels of oil ("mmbbl") and capped at US$1.25 million per annum (NB. previous arrangements envisaged a royalty (or equity) of 7.5% payable from first production with no cap).

I assume that CEG (merged BPC and CERP, remember?) has effectively inherited all the assets, liabilites and the conditions attached to this acquisition

further, we learn

Simultaneous with the renegotiation of the BOLT transaction, Columbus is pleased to announce that it has signed an Agreement for Lease with Singh's (Cedros) Estates Limited (the "Future Lease").

There follows a description of the payment, drilling obligations, royalties etc for this deal without further explanation of the nature of the actual property. I assume it refers to the Cedros licence block in SW Trinidad.

That's enough history for now, so let's take a closer look at the Saffron-1 discovery.


SAFFRON-1 and -2 and the BONASSE FIELD
The 170sqkm 3D seismic survey on which this all depends was shot by TED (Trinidad Exploration and Development Company Limited) in 2001/2. They then drilled 6 additional shallow wells in the Bonasse area (Bonasse 6-9)

In 2001, Toreador then 25% owner of TED, reported " In Trinidad, all of our operations are conducted by, and licenses are held through, Trinidad Exploration and Development, Ltd. (“TED”), of which we are a 25% owner. In the South West Peninsula area of Trinidad, previously unperforated zones were put on production in the Bonasse Field. Four wells are currently on production at about 49 BBL/D. TED has an acreage position of 35,000 acres in Trinidad located on the Southwest Peninsula. This acreage position is located adjacent to Palo Seco to the east, Soldado and South West Soldado to the north, and the Pedernales Field in Venezuela to the west. Based on the proximity to the Palo Seco, Soldado and Pedernales Fields, we believe that there is potential to discover oil reserves on TED’s current acreage position. In addition, TED has contracted for a 3D seismic program covering 150 square kilometers on the Cedros Peninsula permit.

Most of the region’s onshore oil comes from shallow producing zones, but TED has identified an untested anticlinal feature at a deeper target horizon. It is in this horizon that we believe there exists the potential for oil discoveries."



SAFFRON-2
According to CERP (2017) the Bonasse Oilfield, discovered in 1911 by the Greig-1 well, lies some 10 kilometres from Icacos and has been producing intermittently from up to 16 wells at depths up to 1,200 feet. Production was restarted in 1997, but has been temporarily suspended since mid-2016. Oil production comes from sandstones of the Cruse Formation and the oil quality averages 23 degree API gravity.

In 1997 Bonasse field reportedly had original reserves of 425kboe, of which about 300kboe was oil and the rest gas (Source Petronews). At the time, Well Bonasse-1 flowed about 48 bbls/day from an interval 401 to 405m from the (Middle and Upper) Cruse formation. In 1999 the Bonasse field reportedly produced an average of just 11bbl/day (source Oil and Gas Journal Yearbook).

The Saffron discovery is on the site of the Bonasse field, but in the deeper unexplored horizons of the Lower Cruse formation at around 1400m depth.

The setting for this was illustrated in a CERP map and cross section, prior to drilling Saffron-1 back in Oct 2019
https://www.rns-pdf.londonstockexchange.com/rns/3068Q_1-2019-10-17.pdf

Image
page 19 (map showing Saffron prospect)


Image
page 18 (SN cross section)


the UBOT-1 well to the North penetrated the subthrust Lower Cruse formation. (UBOT was United British Oils of Trinidad, a Shell owned subsidiary. It changed its name to Shell Trinidad in 1936) UBOT-1 was probably drilled in the late 1920s and allegedly produced 207bbl of oil but CERP says "productivity uncertain". So, we can say for sure that there were oil shows downdip from the Bonasse field, but that's about it. The 3D seismic, shot in the early 2000s obviously gives some idea of what is going on from amplitude and attribute studies (see below), but is open to interpretation.

The mapped surface shows contours on estimated depth to the detachment along which the Upper and Middle Cruse are thrust over the Lower Cruse, subsidiary to the main Southern Anticline thrust fault to the South. Such detachments often form permeability barriers which constrain oil migrations pathway underneath. The Southern Anticline thrust serves as a migration pathway for oils from middle to late Miocene marine deposits to move into shallower reservoir sands in the upper Miocene-Pliocene, e.g. the Cruse formation from which most of Trinidad's onshore oil has been produced to date.

The map also shows what appear to be P10(dark blue), P50(light blue) and P90(pink) downdip limits, effectively the possible oil-water contacts within the reservoir sand complex.
Updip, the reservoir is sealed against the actively mobile Southern Anticline thrust fault.

A post drilling seismic section was published by BPC
https://d1ssu070pg2v9i.cloudfront.net/pex/bahamas/2021/03/25213812/bpc-update-presentation-march-21.pdf

Image
Page 16 seismic cross section from 3D survey South-North

On page 16, the South to North section, an inline from the 2001 reprocessed 3D seismic, shows horizon picks at detachment surface top Lower Cruse (light blue) and approx bottom lower Cruse (dark blue). Although the picks (i.e. the relationship between two way seismic time and drilled depth) at the well positions Saffron-1 and UBOT-1 are likely to be good, derived as they would be from logging and cuttings data, what goes on in between is interpreted. The quality of the seismic data are fair, but not wonderful, because wave propagation to this depth is going to be significantly affected by the hightly disturbed shallower section. There is some evidence on this section for faulting in the Lower Cruse interval between the wells and the stratigraphy comprises deltaic and turbidite sand shale sequences, which are expected to be patchy in terms of their extent, permeability and porosity, so there is no guarantee of lateral continuity or reservoir quality. Extrapolating even the quite short distance downdip from Saffron-1 reservoir interval to the position of Saffron-2, which is a deviated well drilled from the same pad, could turn up some surprises. Although I have seen better 3D seismic lines than this, the older 2D data from the pre-3D era in a 1977 SWP survey which I have also seen, shot for Trinidad and Tobago Oil Company, are terrible.

Image
2D seismic example line 42 (from my archive), illustrating what seismic interpreters had to deal with back in 1977

Line 42 2D South-North line runs about 2km east of and parallel to the 3D line shown earlier and Saffron-1 is 2km away, about where line 31 intersects, at the left hand (South) end of this line. The well penetrates to about halfway down the section. Line 31 is a strike line, i.e. runs roughly parallel to the Southern Anticline and, in the presence of steep dips, shows the typical confusion of out-of-plane reflections that sometimes make interpretation of 2D seismic data difficult or next to impossible.

3D seismic started to be used in earnest in around 1980 as computational power got cheaper and seismic field acquisition technology improved and in areas like SWP Trinidad, it makes a huge difference. TED failed to capitalize on the 3D dataset they acquired in 2001, in that they failed to test drill for the possibility of Lower Cruse accumulations below the detachment surface, hinted at by the shows in UBOT-1, thus handing CERP and subsequently CEG an interesting opportunity.


CERP RNS Number : 8833K 27 April 2020
https://www.londonstockexchange.com/news-article/CERP/saffron-discoveries-lower-cruse-and-middle-cruse/14516801?lang=en
this describes the describes Saffron-1 discovery, with key out takes:

TD 4634 ft

"2363 ft of Gross sands with six reservoir intervals of interest with a 47% Net/Gross ratio"
doesn't say what the total thickness of the "reservoir intervals of interest" was. However it's qualified later in the RNS by "the logging of the Lower Cruse showed over 300 feet of high-quality sands"

"In the Middle Cruse, we discovered medium quality crude (17° to 20° API) with a high water cut (circa 90%-95%)"
That's a very high water cut. History does not relate how the flow tests were done (probably open hole, over a large interval). We are not told anything about flow rates or pressure drop data. Possibly the tested interval included some unproductive sand bodies which contribute a lot of the water. In some parts of the SWP, deeper wells have encountered high formation pressures which have caused drilling problems. As far as I know, no pressure data were reported for Saffron-1.

"we now calculate has an NPV of circa US$90m"


That's as may be. Now to apply some extreme back of envelope arithmetic:

100m(300ft) gross @ 47% net/gross @ 90% water cut (10% saturation) @25% average porosity.
For each swept sq km of reservoir area we would get 1,000,000sq m x 100 x 0.47 x 0.25 x 0.1 cu m of oil, that is 1.175 million cu m of oil.
applying 6.3 barrels to the cubic m that's would be 7.4 million barrels/sq km. Going back to the map, I calculated the reservoir areas to be
P10 2.0 sq km
P50 1.27 sq km
P90 0.58 sq km

These would correspond to recoverables of
P10 14.8
P50 9.4
P90 4.3 mmbbls
(note that the "P"s here do not really represent actual probabilites, just three differnet scenarios for reservoir swept area)

The P50 estimate short of the 10mbbls ("recoverable" is P90 in my view) or so claimed by CERP and subsequently BPC and CEG, but remember, it's only a very crude estimate, which could be out by a large factor in either direction.

As for the NPV, of whatever oil is in place, we need to look at the finances and decide
1) what is the achievable production rate bbls/day likely to be?
2) what is the estimate for Opex?
3) what royalties, taxes, bonuses and general backhanders will be coming out of revenues?


From the same RNS (see above) where 10mmbbls of recoverables were claimed, relating to question 3 above, I am mildly reassured by
BPC has decided to drill the Saffron #2 well on a 100% basis, and will thus not be pursuing previous "drill for equity" type arrangements that had been contemplated by Columbus - BPC's analysis is that these arrangements represented unacceptable levels of value leakage

CONCLUSION
Finally, to decide what might be the effect on share price of a successful completion of Saffron-2, we have to resort to more back-of-envelope calculations.

I have only considered the Saffron discovery/Bonasse field area from CEG's much larger portfolio. Remember that audited 1P reserves stand at only about 0.7mmbbls. At 3p share price, the company's market cap would be around £24million (currently less than that). It has at least some cash, maybe $12.5m, in its balance sheet. If the reserves could generate free cash flow of $35/barrel (opex $30/bbl, OP $65/bbl) then the current price to book would be about 1:1.

One might look at a 10mmbbls 1P reserves figure and say wow, goody goody, allow $30 bucks a barrel opex against a $65/bbl oil price and that's $300 million in the bank (40cents a share)! However on an IRR (Internal Rate of Return) basis things look somewhat different.

As the rate of production of a given amount of reserves increases, IRR becomes lower as the time frame is stretched out, due to the effect of overheads and lost interest on the initial sum invested.
There may also be a limited time frame in which to benefit from oil in the ground. If decarbonisation happens as quickly as the recent EIA report would suggest that it might (although I personally doubt it), then there is only a limited time available to benefit from ownership of as yet unproduced assets. There are obviously going to be supply vs demand induced fluctuations in the oil price too, making it hard to predict investment returns. If we assume a 10 year period in which the likes of CEG could reasonably expect to profit from their current reserves, this implies that, each million barrels of reserves would have to be produced at approx 100,000 bbls/year, or about 274 bbls/day. If the Saffron discovery does indeed contain 10mmbbls, then it would have to be produced around ten time this, i.e. 2750 bbls/day.

If the Saffron field it comes in at only 1mmbbl, that would probably enable a doubling of CEG's production to around 1000 bbls/day, enabling it to survive and have a go at some of the other prospects in its portfolio. Recall that earlier in this dicussion CEG claimed an NPV of around $90m for Saffron and they are claiming about 10mmbbls of 1P reserves. So, $9million of NPV per million barrels of reserves.

This would correspond, for each million barrels of reserves, to:
say $15/bbl EBITDA ($50 oil price, $35 opex/bbl) i.e. $1.5million a year
which on an NPV basis over 10 years with discount rate of 10% pa comes to about $9 million.

Distributed over 750 million shares, each 1 million barrels ($9 million) would be worth around 12c (8.5p) / share. The current share price is around 2.8p, so the company at that level seems to be significantly undervalued and depending on how Saffron-2 pans out, we might expect significant uplift to the share price by several p.

That said, the lack of a set of consolidated accounts for the merged companies makes it difficult to know various key figures such as annual overheads and capex or opex/bbl, so the above figures are tentative in the extreme. And, of course, CEG's board doesn't intend to distribute the funds, but to plough them back into further exploration and development in their attempt to reboot, i.e. lift the company up by its own bootstraps.

Having lost their shirts numerous times over the course of LGO, CERP and BPC's history and indeed the history of AIM listed small oilies in general, add in the post millenial aversion to anything related to filthy, disgusting, carbon dioxide-spewing (aarghhh we're all going to die) hydrocarbons along with the recent EIA report and it is not surprising that investors are pretty leary about CEG.

On the plus side, there are several other potentially cash generating prospects besides Saffron, which could be progressed within the next 6 months given CEG's current cash postion. Although it was not successful, against all the odds BPC managed to complete the drilling of Perseverence-1 well against opposition from environmentalists and in an extremely difficult financial environment for small exploration companies wishing to drill expensive offshore wildcats. Against that background, with a Trinidad & Tobago government that seems to have a quite postive attitude towards oil and gas development, I think that CEG have a good chance of completing their 2021 programme successfully. Other operators onshore Trinidad, e.g. Touchstone and Predator, have shown that a combination of 3D seismic, new discoveries, modern drilling and completion technology, water and CO2 injection can reverse the 30 year decline in onshore Trinidad production.


On this basis, I persuaded myself to make a modest top-up last week at 2.9p to my miniscule holding of CEG and, already down about 10% on this, I await further results from Saffron-2 with interest.

DYOR and above all have fun!

S

spasmodicus
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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#421354

Postby spasmodicus » June 22nd, 2021, 10:44 am

Nearly there with results from Saffron-2. It should be down to TD in a day or two.

I don't know why I am bothering with this, as CEG is the smallest shareholding in my portfolio, but I decided to take a closer look at the Goudron field, another of Challenger's Trinidad properties, which may ultimately be make or break in its quest for fame, fortune and AIM respectability (an oxymoron, I know). I also have a small holding in TXP (Touchstone Exploration), ably covered by others in nearby threads. Having had a nice run from June 2020 to Feb 2021, in which their share price more than tripled from about 50p to 175p, they are now down in the dumps again at about 80p.

CEG's share price jumped nearly 10% yesterday for no particularly good reason that I could see, amid frenzied claims, counter claims.and trolling on LSE and ADVFN. Recently, although the oil price has surpassed a respectable $70/bbl, this has not been reflected by a general proportional rebound in oil company share prices. High debt levels or other weaknesses in performance or strategy will be punished by the markets. It is not enough to produce this or that number of barrels per day if the resultant cash flow is then wasted by inefficient operations, director's expenses and salaries, headline-grabbing wildcats or has to be used to pay down debt, or is simply dissipated in compliance with over zealous (to sometimes perfectly reasonable) regulatory and taxation regimes.

A LOOK AT THE GOUDRON FIELD
CEG are engaged in rehabilitation of the same kind of onshore fields and prospects fields in Trinidad as TXP, so here's a look at the history of the Goudron field in an attempt to determine what might make it profitable, or not.

First, let's take a look at CEG's plans for onshore Trinidad in their (BPC) March 2021 update
https://www.sharesmagazine.co.uk/news/market/LSE20210318070003_3914632/Trinidad-and-Tobago-and-Suriname-Update

South West Peninsular Exploration

The first phase of the of 3D seismic re-processing trials were completed by three companies*** in Q1 2021 and a preferred supplier for Phase 2 has been notified. Phase 2 consists of taking the best results from Phase 1, refining the re-process of the trial area, and extending it to the remainder of the seismic area. Phase 2 will commence in April 2021 and is anticipated to complete within 6 months. Results from Phase 2, along with existing data, will support the selection of future exploration drill targets.

*** aka a turkey shoot. They probably did it for free.

Infill Drilling Project
In recent months, the Company has undertaken a body of work to screen prospective infill drilling opportunities for new production wells in the existing producing fields. In total, over 40 potential locations were evaluated across the assets. As a result of this work the Company has identified up to four high potential drill sites which are considered to have a high chance of producing incremental volumes at a sufficient rate to offer excellent potential payback / IRR metrics.

Two of CEG's potential infill drill-sites are in Eastern fields, and two in Western fields. Target depths range from between 2,500 - 3,500 ft, estimated well costs are in the range of US$1.2 - 1.5 million per well, with estimated productions rates in the range 50 - 100 bopd per well and ultimate recovery of 75,000 bbls per well. Subject to permitting and rig and capital availability, the Company intends to proceed with these infill drilling opportunities during H2 2021.


The most active of these prospects seems to be the Goudron field, in the Eastern group. We learn from
https://www.voxmarkets.co.uk/articles/bpc-extends-goudron-licence-to-2030-with-new-espc-5fdaf33/
that its licence runs until 2030

and, according to Shares Mag March 2021
Goudron (Production enhancement / water injection)
The Company and Weatherford have agreed to an extended trial of Weatherford's proven well automation systems during Q2 2021 on five wells across the Goudron and Inniss Trinity fields. The trial will automate the pumping units to optimise the production rates, allow real time monitoring and improved data collection for analysis across the entire production system. The trial will last for 60 days and the installation and associated costs will be borne by Weatherford. Following the completion of the trial, BPC has the option to acquire at low cost the installed equipment on any or all of the trial wells.

Jolly good! Now let's examine the Goudron field itself.

Image
The base map is from a USGS report on Trindad (1981), overlain with a coloured outtake from Lenigas Oilbarrel presentation (2104), showing their assets in the Southern Basin Structurally, the field lies in the Southern Basin, just to the North of the major fault zone running right across the South of the island, a manifestation of the boundary between the South American and Caribbean tectonic plates. In late Miocene times, marine sediments, which are the source and reservoir rocks for the Goudron field, were accumulating in this area and oil migrated over time into its current disposition, along the active faults. This is significant because by drilling deeper, new reservoirs closer to the original source rocks may be found. The Los Bajos fault to the West has a right lateral displacement of up to 6.5kms in places, as well as a strong reverse (compressional) component and there are many associated faults, reverse, listric, normal, with overthrusts, flower structures and detachments etc indicative of the high tectonic strain in the area. This makes for complicated compartmentalized reservoirs and difficult conditions for seismic data gathering, interpretation and drilling.

Image
Inset map from LGO(2014) showing more detail and the location of a cross section A-A'

Image
cross section and seismic section from LGO(2014)
The fault zone can be seen to the right (South) of A' on the seismic section and there will be as many opinions as to what the configuration of the faulting is really like as there are geologists.

Does all this help us assess the viability of Goudron as an investment? Not really.

LIES, DAMN LIES AND CPRs
To find out more about Goudron, we need to go back to 2011 when LGO acquired the licence from GEPL.
https://www.proactiveinvestors.co.uk/companies/news/28328/leni-gas-oil-buying-onshore-trinidad-oilfield-for-up-to-us9-mln-33849.html

LGO said that the field has had very little investment over the last 25 years, and the existing production comes from about 30 wells, of which 12 are on production with beam pumps and the others flow naturally or are periodically swabbed.

Recent production has ranged between 100 and over 200 bopd. The oil reservoirs are generally between 300 and 3,500 feet below surface and the oil is light low sulphur crude with an API gravity ranging between 25 and 55 degrees and a mean of 32 degrees.

Oil in place in the existing producing zones is estimated to be between 120 and 225 million barrels stock tank barrels oil initially in place, with a P50 estimate of 166 mmbbls.

Proven reserves of 1.9 mmbbls are currently estimated within the field area and can be recovered using existing wells and a small number of infill wells. Proven and Probable reserves are estimated at 8.0 mmbbls. Additional recoverable reserves which can be produced from hydraulically fractured wells add a further 13.8 mmbbls.

LGO has assessed the opportunity for an initial work-over programme aimed at improving the production from up to 50 existing wells and estimates that production can be raised to 450-500 bopd through work involving well clean out, limited reperforation and the installation of additional electrical pumps. A preliminary estimate of the cost of that programme, which could take 12 to 18 months to execute, is US$4 million.

LGO has paid Sorgenia an initial US$1 million to acquire all GEPL shares and on completion of the transfer will pay a further US$1 million for the geological, reservoir engineering and environmental studies conducted on the field.

When and if field production reaches 1,000 bopd, LGO will pay Sorgenia another US$1 million and US$2 million if and when it reaches 2,000 bopd. Based on initial field redevelopment plans these levels will be reached in early 2013 and in 2014 respectively.


Later on, April 2013, after LGO had commissioned a CPR on Goudron field, its results were reported in
https://www.proactiveinvestors.com/companies/news/47215/leni-gas-oil-set-to-expand-trinidad-footprint-56289.html
During the year a competent person's report (CPR) was issued for Goudron, which estimated 7.2 million barrels of proven and probable (2P) reserves and 30.5 million barrels of proven, probable and possible (3P) reserves and a stock tank oil initially in place (STOIIP) of 350 million barrels.

Executive chairman David Lenigas said
"Goudron alone is a company-making asset....."
Which company would that be, I wonder? Perceptive Fools, familiar as we are with the contortions of AIM oilies, will recall other fields which have so far failed to live up to their promoter's promises. Here's one for starters.
https://www.guerillainvesting.co.uk/tag/david-lenigas/

In November 2014, LGO did a presentation at an Oilbarrel Conference in the City of London. Remember those? - Ah, happy days, I was there, to enjoy the free coffee and buns and rub shoulders with other sundry chancers. Slide 8 proclaims
Conducted over 70 well reactivations Carried out several recompletions Drilled 6 new wells in a 30 well redevelopment Placed 5 wells on stream (as @ end Oct 2014) Production has already increased from 30 bopd to over 900 bopd and is set to exceed 1,000 bopd in late 2014 Goudron well GY-257 Reactivated 2012
so 900 bopd already!

And later, in December we get a report from CERP, now the owners of LGO, on Goudron Well GY-670:
https://www.evaluateenergy.com/Universal/View.aspx?type=Story&id=135834
LGO is pleased to announce that its most recently completed well, GY-670, at the Goudron Field in Trinidad was perforated on 12 December over a 177-foot interval of oil pay in the C-sands and is now flowing at a stabilized, but highly restricted, rate of 1,085 barrels of oil per day ("bopd") of 37 degree API water-free oil through a 9/32" choke with a well-head flowing pressure of 1,290 psi. Over the last 48 hours the well has flowed at an average rate of 1,104 bopd. The initial open-hole flow rate calculated for the well exceeds 6,000 bopd.

in 2016 we learned
https://www.findingpetroleum.com/company/LGO-Energy/af3a526a.aspx
The Goudron Field (LGO 100%) lies between the East Moruga and Beach-Marcelle fields in south-eastern Trinidad and has direct access to the Petrotrin oil export pipeline to the Pointe-a-Pierre refinery in western Trinidad. The field was originally discovered by Trinidad Leaseholders Limited in 1927 and was largely developed by Texaco between 1956 and 1986, when ownership passed to Petrotrin and its predecessors. A field reactivation contract, Incremental Production Service Contract (IPSC), was signed in late 2009 and the contract acquired by LGO in October 2012. Since then LGO has reactivated over 70 wells and drilled 15 new deep production wells and is gearing up for an infill program of up to 70 new shallow wells and a waterflood EOR of the deeper reservoir. LGO's recent drilling has increased the oil in place estimate substantially and now stands at close to 1 billion barrels.

A billion barrels oil in place ! Holy Moses!!! But see the report below, from Edison in 2017.
https://www.edisoninvestmentresearch.com/?ACT=18&ID=19343

By this time, the field was being operated by CERP and one's enthusiasm for investing in the extraction of the aforesaid 1 billion bbls may be dampened a little by:
Goudron production increase targets cash breakeven
"Goudron is currently producing between 380-420bopd, which is not enough to cover production and central costs. However, with management costs falling, only a small increase in production will be required to generate free cash flow. A water injection programme has been accelerated, smart pumps are being installed and a well stimulation programme is planned."
(my bold)

Again, it's a little strange that CEG/BPC's ERCE CPR (Competent Person's Report - see my previous post) didn't mention this asset specifically. I assume that Goudron is included in "East Fields" which were lumped together with 3P reserves of 1.66 million barrels, i.e. 600 times less than the OOIP prognosed above. In the face of 3P reserves anywhere between 1.6 mmbbls and 1 billion bbls, we should perhaps focus on the fact that at around 380-420 bbls/day, the field was loss making at the then prevailing oil price of around $50/bbl. Other data that I have from back in 1997 or so stated Goudron's 2P reserves as 4.8million barrels, with annual production of about 10000bbls/year or approx 40 bbls/day. There may well be plenty of oil in place but it's just a question of getting the stuff out of the ground cheaply enough.

So what happened to that 900 bopd and rising, reported back in 2014? With both reserves estimates and production fluctuating like the head of a nodding donkey, it's clear that producing this field is not a straightforward matter. It's a bit worrying that CEG's total onshore production in Trinidad is currently stated as being only 500-600bbls/day, from all of their assets. How much is Goudron contributing to this and is it still making a loss?

OK, everybody knows that these fields are difficult to produce. Texaco would not have sold it to Petrotrin in 1986 and they to Goudron E&P Ltd if this was easy money. However, recent history suggests that newly drilled or worked over wells at Goudron can produce at a respectable rate initially, but production tails off rapidly. But, because the major pipeline and support infrastructure is already paid for, it should be possible to turn a profit if drilling and operating costs can be kept down.

I decided to research the wells actually drilled in recent times at Goudron to try to form a picture of how this might work. The table below shows what I gleaned from various reports, starting with the 2014 Oilbarrel presentation, with later wells added by googling for their results

GOUDRON WELL RESULTS
Well name | spud date | completed | TD ft | net pay ft | Reservoir     | flow bopd | choke | wellhead psi | remark                                     
GY-50 | | 05/05/16 | | | | | | | Re-completion
GY-275 | | 1958 | | | | 24 | | | still going!
GY-664 | | 13/05/14 | 4212 | 571 | all | 490 | open | |
GY-665 | 27/05/14 | 08/06/14 | 2750 | 460 | Goudron/Morne | 700 | open | |
GY-666 | 16/06/14 | 03/07/14 | 3357 | 422 | all | 300 | open | |
GY-667 | 10/07/14 | 10/07/14 | 4006 | 434 | all | 220 | open | |
GY-668 | 09/08/14 | 10/07/14 | 3026 | 445 | Goudron/Morne | 330 | open | |
GY-669 | 05/10/14 | 24/10/14 | 3505 | 227 | Goudron | ?? | | |
GY-670 | 28/10/14 | 15/12/14 | | 177 | C sands | 1085 | unk | | open hole 6000 bopd. 105000 bbls by 7/09/15
GY-671 | 22/11/14 | 08/12/14 | 3598 | 244 | C sands | | | |
GY-671 | | 28/04/16 | | 208 | C sands | 80 | 6/32 | 260 | Re-completion
GY-672 | | 24/09/15 | 3608 | 272 | Goudron | 60 | open | |
GY-673 | 01/05/14 | | 3193 | | C sands | | | |
GY-673 | | 28/07/16 | | | Mayaro | 30 | unk | | recompletion in shallow sands. Pumped prodn
GY-674 | | 16/07/15 | 3458 | 277 | C sands | 240 | 8/32 | | open hole 500 bopd
GY-675 | | 20/09/15 | 3700 | 95 | C sands | 325 | 7/32 | 640 | Open hole 850 bopd
GY-676 | | 19/07/15 | 3545 | 222 | | 240 | 9/32 | |
GY-677 | 27/07/15 | 08/08/15 | 3135 | 355 | | 380 | 5/32 | |
GY-677 | | 22/08/16 | | | | 34 | | | Re-completed
GY-678 | 17/08/15 | 07/09/15 | 4219 | 479 | C sands | | | | Not tested due to stuck pipe problem
GY-682 | 04/03/17 | 22/03/17 | 1145 | 273 | Mayaro | 55 | 9/32 | 1290 | shallow production well
GY-683 | 31/03/17 | 09/04/17 | 1250 | | Mayaro | 80 | 7/64 | 40 | Production rate after "stabilization


A picture emerges of quite variable flow rates. The most productive target is the "C-sands", i.e. deeper horizons between the pre-Mayaro unconformity (the base Goudron Sands) and the pre-Cruse.

GY-683 was the second of a 10 well infill programme, said to be finishing with GY-688, a "data gathering well". It seems to be the last new well drilled to date. The missing wells in the sequence, GY-679, 680, 681 along with GY-684 were apparently drilled by Range Resources on the nearby Beach-Marcelle field, due to some historic quirk of the local well numbering system. (RR sold it to LandOcean in 2019).

These wells can be drilled to TD of around 4000 feet in less than two months. Because of environmental restrictions and to keep costs down, several deviated wells may be drilled from the same pad. Drilling cost is variously said to be about $500,000 to $1million per well. Production cost (is that opex/barrel, or does it include capex?) is variously stated as $10/bbl and,in this RNS.

Feb 2017 RNS Number : 9365W
https://markets.ft.com/data/announce/full?dockey=1323-13128402-6PJ6AMTOTE2H3EU1BA0MATMBV3
.......During 2016, as a result of these capital constraints, the production at the Goudron Field declined from late 2015 levels, but was maintained through carefully selected recompletions, at an average level of 425 barrels oil per day for the year to 31 December 2016. Goudron is a low cost onshore operation and has the additional advantage of reduced royalty payments as oil prices fall. As a consequence Goudron remains profitable at current production rates even at oil prices below US$25 per barrel.......
.........The wells are estimated to cost US$500,000 per completed well, with initial production targets conservatively set at an average of 45 barrels of oil per day ("bopd") per well, although some wells are predicted to have higher production capacity based on the large body of historic data.


Initial open hole flow rates are quite high, maybe 200-300 bbls/day, but subject to rapid decline rates of 20%/year or more, even when flow is choked. Thus, to maintain field production at the 1000 bbls/day level would require the equivalent of at least one new well every year, along with maintenance of the existing well stock. The shallower production intervals are on pumped production.The water cut (% of water mixed with the produced oil) is not specified and nor do we know what level, if any, of waterflooding or injection has been used to maintain reservoir pressure. From 2018 onwards there are hints about this issue in various RNSs, e.g.
Oct 2018
Continued operation of the Waterflood Pilot "A" is planned in Q4 2018 to add to the cumulative 79,000 Barrels of produced water already injected into GY-667. Following the injection of twice the historical produced fluid volume of GY-667, the Company has obtained positive evidence that the well is not in its own compartment and pressure responses show evidence of reservoir charge. This is a positive result within the expected water injection timeframe and the Company will continue injection whilst awaiting an oil response in the adjacent offtake wells.

Monitoring of offset wells for definitive production gains continues with a decision on adding injection into GY-209 planned by year end. The availability of over 1,500 BWPD of produced water allows plans to be drawn up for submission of a separate Goudron Mayaro reservoir layer water injection to complement the existing Pilot A, "C" sand injection which targets prolific production wells GY-664 and GY-665.

If 1500 BWPD (Barrels of Water Per Day) is being produced from the field, while oil production is of the order of 500 bbl/day, it suggests quite a high water cut of 66% or so. Aside from the possible benefits of reinjection, this water has to be disposed of in an environmentally safe way and pumping it back into the reservoir sands is as good a way as any.

2015-16 was a bad year for the Goudron field. Not only did the oil price plummet that year, but a stuck drill pipe led to the loss of well GY-678, which had penetrated an unexpectedly thick section of productive, but apparently untested, C-sands. 2017 through 2019 were spent trying to refinance and recover from this and then the covid pandemic hit in early 2020.

If CEG can pick up CERP/LGO's lost momentum on drilling wells in the C-sands at Goudron, it seems to me quite possible that they could increase the production rate to 1000 bbls/day. However, this is not a glamorous offshore multimillion wildcat type operation (like Perseverence-1) where fame can be won and fortunes trousered, for directors at least, on AIM spin and hype from headline grabbing farm outs.

Diligent housekeeping of the existing Goudron well stock, combined with creative infill drilling, waterflooding and deeper investigation of C-sands has the potential for modest but significant increases in shareholder value. Estimated oil in place is a bit of an irrelevance, because at 1000 bbls/day Goudron could theoretically go on producing far beyond the end of CEG's lease, which potentially terminates in 2030.


To determine whether this field can actually be profitable, we can take CERP's accounts for 2017,
https://uk.advfn.com/stock-market/london/columbus-energy-CERP/share-news/Columbus-Energy-Resources-PLC-Accounts-for-year-to/77641266?nomobile
with Trinidad sales revenue at $4.5 million out of a total of 4.79 million
cost of sales 3.56 million – fixed and variable production costs at 400bbl/day production level
depreciation 1.16 million – well replacement will be a big number in here
that gives an operating cost of $35600000/(400*365), or $24.4/barrel

As we saw above during 2017, CERP, with Goudron as its main producing asset, was breaking even at about 400 bbls/day, at an oil price of say $50/bbl, i.e. about $7.3million/year gross revenue. We need to deduct a fair chunk for PRT and royalties, probably around 25%, which brings it down to around the 4.5million figure from the report.

It's time for more extreme back-of-envelope calculations:
We can take the cost of sales, knock off 560k for costs unrelated to Goudron and divide into equal fixed and variable costs of 1.5m each, that is (3.56 – 0.56)/2, we get an approx figure for producing 1000 bbl/day of
fixed cost 1.5 m plus variable cost 1.5 x 1000/400 = 3.75 m grand total 5.25 million, which gives us an operating cost of $14.5/barrel at 1000bbl/day production rate.

Now, 2 wells a year need to be drilled, at say $500,00 for shallower ones and $1million for deep ones, that's an average cost of perhaps $750,000 per well, so capex (depreciation) of perhaps $1.5million/year, in the same ballpark as depreciation mentioned in the accounts. That adds another $4.1/barrel to the opex, to give capex + opex $18.5/barrel. Note that this was claimed to be $10/bbl at one point.

On the revenue side, knock out about 25% for govt. PRT and royalties, so that a $60/bbl oil price would translate to (60*0.75 – 18.5) = $9.7million annual free cash flow for 1000 bbl/day

This extremely rough calculation indicates that Goudron might generate free cash at up to $10 million/year, at 1000bbl/day production rate, if past statements about operating costs are anywhere near the mark and the oil price remains above $60/bbl. However, the current production rate is probably only about 400-500 bbls/day, so substantial up front spending on new wells and workovers would be needed to achieve this. In a 2019 RNS, CERP acknowledged this
https://markets.ft.com/data/announce/full?dockey=1323-14045129-17ME1LD88PCKSM7FP4Q1RIPBFM
April 2019
As I mentioned in early January, we have been managing our operations in Trinidad in a different manner, focussing on optimising profit as opposed to simply growing the total production numbers. With lower oil prices and the impact of SPT between US$50-US$60/bbl, we have taken action to reduce our rig activity and we have also reduced operating costs in a number of other areas. Despite the lower production and resultant lower revenues, we have slightly increased our cash netback from operations and will look to continue to maintain a tight ship until the economic conditions and commercial terms allow us to pursue real production growth again. There are more effective ways of spending operational profits at such times and during Q1 2019 the technical work on the SWP, the Inniss-Trinity CO₂ project and M&A activities took precedence over production growth.




CONCLUSION
In conclusion, the Goudron field could be quite a nice little earner, if development and workovers keep on coming and costs can be kept down at the same time.

However, the lack of a decent set of accounts is in this context worrying, as we have no real means of assessing whether this is in fact being achieved. Success at Saffron-2 would be icing on the cake, if cake there be. I just hope that the company's operational skills are a not a reflection of its inability to produce a decent set of accounts on time.

Free cash spun off by ongoing production at the Goudron and Saffron fields would almost certainly be ploughed back into CEG's other ventures, e.g. Suriname and Uruguay and maybe on the Bahamas shelf. The appetite of the markets for the latter is very questionable as a resurgence in oil prices due to supply/demand imbalances is likely to be more short lived than the timescale from discovery to production of such frontier oil provinces. The days of speculative frontier drilling by small or micro cap oil companies are surely numbered, if not over already, but I do think that there is money to be made by extending the life of existing fields and polishing green credentials with CO2 sequestration / stimulation as carried out by TXP (Touchstone) in Trinidad. As ever with AIM size oilies, the degree of alignment of director's and shareholders interests is the hardest thing to judge, along with the trajectory of the oil price, so let's wait and see and, as ever, do our own research.

S

spasmodicus
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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#425230

Postby spasmodicus » July 6th, 2021, 1:16 pm

A look at another of CEG's Trinidad assets, while their share price gently declines with no concrete news on their Saffron-2 well, now supposedly in testing.

The Innis-Trinity joint PRD-CEG (Predator-Challenger) CO2 Injection Project

The Innis-Trinity field is another of CEG’s Trinidad assets, picked up from the BPC-CERP merger. Like Goudron, it has a long history and is somewhat depleted and of questionable financial viability. That depends on how much OOIP (Original Oil In Place) there was, itself an estimate based on G&G, drilling and production data, how much oil has been missed and of course on the effectiveness and costs of the technology that was/will be used over the years to produce it.

PRD Predator will be well known to readers of this forum as a bit of a market darling, but their recent duster in Morocco has taken off a bit of the shine. As a result PRD will maybe concentrate a bit harder on cash flow in Trinidad, instead of basking in the glory of a successful wildcat. Sic transit gloria mundi.


INNIS-TRINITY FIELD BACKGROUND
(from a 2014 article in Oilfield Technology magazine)
The Trinity and Inniss fields were originally discovered in 1956, and were developed by Texaco from 1958 with the drilling of a total of 134 wells targeting the Herrera Sandstones in thrust fold structures along the Rock Dome anticline in the Southern Range Thrust and Fold Belt. Production to-date totals approximately 23 million bbls, derived from five Herrera Sandstone intervals of which Units 3 to 5 are the most productive and account for approximately 80% of the production to-date. Peak production was realized by Texaco in 1958 at a level of 4200 bpd.
The net pay interval ranges from 100 to 280 ft with an average porosity of 27%. Based on studies carried out in the last 5 years the estimated STOOIP ranges from 68 to over 200 million bbls. There is extensive 2D seismic data over the Field area and recent studies have collated all relevant historic production and pressure data to allow more accurate reservoir models to be built.

THE JOINT VENTURE
From PRD's 2019-Jan_New-Presentation.pdf Investor Presentation

Predator is applying proven North American C02 Enhanced Oil Recovery (“EOR”) technology to a mature producing oil field –Inniss-Trinity
•Entered into a well participation agreement with FRAM Exploration (Trinidad) Limited (“FRAM”), funding the cost of two pilot CO2 production wells on the Innis Trinity Field (FRAM Operator) in return for 50% of revenues from production (100% until cost recovery)
•Initial reservoir engineering study completed, independently validating feasibility of the technical case for CO2 EOR operations
•Expected combined production rate of 300 bopdfrom first 2 wells
•Start up capital costs estimated at $600,000 –funded from existing cash within Predator
•Subject to successful pilot, potential exists to target between 8.12 and 15.62 million barrels of
incremental resources.

The licence holder FRAM is/was a wholly owned subsidiary of Columbus CERP, which merged into CEG.

https://www.energy-pedia.com/news/trinidad/predator-oil-and-gas-announces-offer-to-acquire-fram-exploration-(trinidad)-180119

The Offer comprised a cash consideration of one million seven hundred and fifty thousand United States Dollars (US$ 1,750,000) exclusive of VAT, where applicable.

It didn’t happen , as PRD apparently decided that a JV would be more profitable than a buyout, see website
https://www.predatoroilandgas.com/operations/trinidad/
where existing terms and conditions are laid out

and this RNS from 5 October 2020
https://data.fca.org.uk/artefacts/NSM/RNS/3737602.html
concluding that
Extension of exclusivity over Trinidad's entire surplus liquid CO2 supply and the successful execution of Trinidad and Tobago's first large scale CO2 EOR project for many years are compatible with the Company's strategy of developing and offering a flexible CO2 EOR services business in Trinidad to other operators. This is achievable without the onerous burden of licence liabilities.

CO2 INJECTION: GREENWASH, OR A PATH TO ENVIRONMENTALLY ACCEPTABLE OIL PRODUCTION?
I’m trying to be inclusive and reaching out a hand of friendship and reassurance to all those nauseous at the prospect of investing in anything so obviously uncool and dangerous to life as we know it, as oil and gas, but am cognizant of the fact that such people will avoid forums such as this in the first place. So, before considering the possible financial effects of the Innis Trinty field JV on the fortunes of both PRD abd CEG, which after all is what we are here for, lets take a look at CO2.

Anything to do with CO2, especially getting rid thereof, makes environmentalists prick up their ears, in a negative sense to confirm all that they think that they know about the greenhouse effect and, more positively from an investment point of view, seeking to greenwash their fossil fuel dependent lifestyles by considering only projects with green credentials. In short, the idea in this case is to use CO2 to stimulate oil production from sluggishly producing fields such as Innis-Trinity, thereby winning more oil and getting rid of greenhouse gas by burying it underground

SKIP THIS BIT IF NOT INTERESTED IN CO2 GREENWASHING
Here, the quantities of CO2 required are revealed
https://www.energy-pedia.com/news/trinidad/predator-announces-the-results-of-its-pilot-co2-eor-project-in-the-inniss-trinity-field-onshore-trinidad-181721
443.58 metric tonnes ("MT") of CO2 injected over a planned cumulative period of 45 days. This represents 2% of the pre-Pilot desktop volume estimated to be required to recover 459,000 barrels of oil from the Herrera #2 Sand over the five year life of a full-scale CO2 EOR operation in the AT-4 Block.

That is 443.58 x 50 MT (Metric Tonnes) injected for 459000/7 MT of oil extracted , i.e. 65000 MT of oil from 22000 MT of CO2 sequestration, or about 2.95:1 weight for weight oil for CO2. A MT of oil is about 7 barrels.

Now,
https://www.google.com/search?client=firefox-b-d&q=how+much+CO2+from+1+ton+of+oil

says that on average a MT of oil produces about 3.07 MT of CO2 when burned. Thus, while this CO2 sequestration is a “good thing”, it’s not anywhere near CO2 neutral, because in the end 1 MT of CO2 injected results in up to 2.95 x 3.07 or about 9.05 MT of CO2 being released into the atmosphere, depending on whether the produced oil is burned, or used for chemical or plastic feedstock. I think that we have effectively disposed of the green arguments for CO2 injection.

Some useful stats here
https://www.iea.org/commentaries/is-carbon-capture-too-expensive

Predator has done some homework and secured a supply of CO2 from a local ammonia plant. The CO2 arising from the production of ammonia comes from the burning of fossil fuel required to sustain a supply of (blue) hydrogen and maintain the high pressures and elevated temperatures used in the Haber-Bosch process. The CO2 is captured from in the same way as for fossil fuel power plants. (let’s not get into this now). Cement factories also produce lots of CO2 which can be captured as well.

WHAT ARE THE PROSPECTS FOR INNIS-TRINITY?
300 bbl/day production from an initial investment of $600,000 with full cost recovery and 50-50 profit share thereafter. 300bpd. Lets assume opex of $25/bbl, tax $10/bbl and a $65/bbl oil price, giving annual revenue of around $30 x 300 x 365 giving $3.285m. In the first year, each partner would make approx $(3.285-0.6)/2m, or about $1.34m. In subsequent years, this might increase if the operation were to be scaled up, with startup cost already accounted for. A useful, if not make or break contribution to both partner’s cash flows, which in CEG’s case might pave the way towards increasing production in other Trinidad fields.

CARBON OFFSET?
It is also possible that because of carbon pricing, the CO2 used in the injection process might be subject to a carbon pricing offset, i.e. by disposing of CO2 in this way the original company that generated it might avoid paying carbon taxes. They might then give the CO2 away for free, or even pay for its disposal. How this worked would depend on the extra cost to the Ammonia or cement producer of capturing the CO2, rather than discharging it into then atomosphere. There may come a point when oil could be burned to power a plant for direct air capture of CO2, which would all be reinjected and sequestrated in the depleted oil reservoir.


Conclusion: If the CO2 injection works as well as PRD says that it will, it would provide a useful cash flow boost to both companies, but it's not a game changer. But nowadays it seems that oil companies, large and small, are only as good as their cash flow. Cash is still King, if I am not mistaken.

Good luck to all,
S

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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#430266

Postby spasmodicus » July 25th, 2021, 1:31 pm

The timing of Challenger’s RNS last Friday, outlining a share bonus incentive scheme for directors and employees, seemed a little strange, considering that the market still awaits the overdue test results from their Saffron-2 well, which reached TD a couple of weeks ago.

https://www.lse.co.uk/rns/CEG/incentive-arrangements-update-qrsu8rb1dcq936w.html
Over on ADVFN and LSE you can get an idea about what the market thinks about this. For some, it triggered outrage that directors would be helping themselves to yet another tranche of the shareholder’s pot, while others pointed out that the bonus share exercise price (of 4 to 5p) was somewhat above the current share price (of around 2p) and therefore, unless Saffron-2 comes good, directors, shareholders and employees will all be in the same (sinking) boat.

As ever, it’s difficult to fathom what is going on at CEG. For sure, their BOD knows plenty that the market doesn’t and for sensible investors, this is bargepole territory. As pointed out previously, the lack of a proper set of accounts (according to a June RNS, AIM allowed their expected end 2020 report to be delayed by 3 months) makes it difficult to assess the impact of Saffron-2 on the company’s future prospects, even if we did know the results of production testing. It would also be interesting to see some concrete results for the JV at Innis-Trinity with Predator, who are also licking their wounds after a less than wonderful result at their MOU-1 well in Morocco a couple of weeks ago.

My own view is that a 200-300 bbl/day uplift to CEG’s current production of around 450 bbl/day would provide them with enough cash flow to keep their heads above water for the time being and service the $10m CLN (Convertible Loan Note) outlined in an earlier RNS. How much of that will spill over into an improved balance sheet and share price remains to be seen, but given current market scepticism about the oil sector in general, increases are likely to be modest and probably limited to around the 3.5p offer price of the recent placing.

If we don’t get a test result for Saffron-2 soon, CEG's incentive scheme will likely prove worthless.

S

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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#437350

Postby spasmodicus » August 25th, 2021, 4:11 pm

Oh dear, the oil business is really rather challenging. A long awaited RNS from Challenger caused the share price to dive more than 20% to 1.3p, nearly back in penny share territory.
https://www.lse.co.uk/rns/CEG/appraisal-update-saffron-2-production-test-iucrrg9dzhwdc3j.html

It’s all about the results from testing the Saffron-2 well, which are somewhat underwhelming, reported as commercial production rate (81 bopd) has thus far been established at Saffron-2, from approximately 66 feet of Middle Cruse reservoir units

Febrile speculation had been rife on ADVFN and LSE chat boards for CEG, with some holding out for 200-300 bpd as originally prognosed, or even more, while others were claiming that “no news is bad news”, i.e. the CEG directors are trying to think of ways of spinning what is basically a poor result in the hope of raising more funds to keep them in the luxury to which they probably aspire.
You can hear it from the horse’s mouth in an interview with CEO Eytan Uliel here
https://www.voxmarkets.co.uk/articles/challenger-energy-results-of-their-saffron-2-production-test-7909cad

He plays down the results and talks about other prospects that CEG has, but I think that their problem in the medium term is going to be cash.

CEG’s daily production is currently ranging between 400 to 500 bopd, inclusive of Saffron-2 and the RNS concludes
Over the coming months, in addition to continuing clean-up operations, perforating and production testing of additional zones, and further maximising oil production revenues from the Saffron-2 well, the Company will be working to incorporate the results of the well into an optimal forward plan for the Saffron project. These operations also provide a significant input into defining the prospective and contingent resources for both the Saffron location and other targets within the Company's South West Peninsula portfolio, which will contribute to an update of resource estimates.
Further announcements will be made as appropriate.


The trouble is, messing about with perforating and testing new zones and trying to stimulate the already producing zone in Saffron-2 is going to impact the extra 81 bopd that they do have.

As we have seen elsewhere on this board, even those companies with arguably better production, reserves and prospects, e.g. their neighbours TXP, are currently languishing. And there has been a deafening silence on the results of the CO2 injection joint venture that CEG has with Predator in the Innis-Trinity field.

If they are to survive, they are going to have to concentrate on the unglamorous business of production enhancement in Trinidad and, unless market sentiment changes radically, they should probably forget about Suriname (new well was scheduled for September, but delays are hinted at) and especially the Bahamas shelf (ongoing court case, hoping to farm it out later).

So much for the director's and employee's incentive scheme,
S

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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#476611

Postby Cyb3ria » January 27th, 2022, 4:36 pm

spasmodicus ,

I guess it could be argued that we are ALL proper fools when it comes to investing and no amount of due diligence/research is going to remove that label.

But, being proper fools, lemonfools at that, I take it that you have followed the current excitement boiling red white heat on the forums?

The only "positive" spin is: "Challenger Energy shakes up board as it raises GBP5 million" with significant dilution.

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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#476616

Postby Cyb3ria » January 27th, 2022, 4:46 pm

Of course, when you are in deep what is a fool to do? Close, take the hit or appeal to pure and applied mathematics and forget about the company, what it's doing or not, and just depend on averaging. You could argue that this is where investing turns into a casino with the house always having the advantage. In this case, the house are the insiders. The investors are playing roulette. Double, treble up and place the tokens all on red. Spin the wheel and hope for the best.

Naturally, not being a fool I would just close and go for the next due diligence and well researched investment. :lol: :lol: :lol:

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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#477864

Postby Hallucigenia » February 1st, 2022, 5:57 pm

Good stuff spasmodicus - but sweet mother of Jesus, what a mess. Take the RNS's of the last week :

At 16:54 on Wednesday they announced a bookbuild and open offer, and at 07:53 on Thursday they announced the result :
the Bookbuild has closed and the Company has raised gross proceeds of approximately £5.0 million through the successful firm and conditional placing, including a firm and conditional direct subscription, (the "Placing") of 5,019,100,000 new Ordinary Shares (the "Placing Shares") at a price of 0.10 pence per Ordinary Share (the "Placing Price").

Approximately £0.7 million has been raised as part of the Firm Placing pursuant to the Company's existing share issuance authorities in place, and approximately £4.3 million has been conditionally raised as part of the Placing ("Conditional Placing"). The Conditional Placing is subject to shareholder approval, which will be sought at an Extraordinary General Meeting of shareholders to be convened on or about 28 February 2022.

In addition to the Placing, and as set out in the Launch Announcement, the Company will also undertake an Open Offer to raise up to a further £2.0 million. Under the Open Offer, all Qualifying Shareholders will have the ability to subscribe for new Ordinary Shares in the capital of the Company (the "Open Offer Shares") at the Placing Price on the basis of 2.51 Open Offer Shares for every 1 existing Ordinary Share held at the Record Date.


And yes, that is 5 billion new shares. Bear in mind that the shareprice had been about 25p in Nov 2020 before The Big Well in the Bahamas, collapsed to 5p after that failed to be commercial, and had drifted down to 0.6p on Wednesday. So of course it collapsed to around 0.1p first thing Thursday. But hey, at least existing shareholders get to participate, at 2.51 offer shares per existing share.

Except on Friday they announce : The original announcement erroneously stated that 2.51 Open Offer Shares for would be available for every 1 existing Ordinary Share held at the Record Date. This figure should have been 1.34.

Oops. But it gets better - yesterday they casually mention :
The Open Offer component of the Fundraising was included as a means of enabling existing shareholders to participate in the Fundraising at the same price as new institutional and other investors participating in the Placing. Since completion of the Bookbuild, the Company has subsequently been advised that, in accordance with the Financial Services and Markets Act 2000, as amended, the Company would be required to issue a Prospectus in connection with the Open Offer. This is due to the aggregation of the £6.9 million (€8.0 million) open offer conducted by the Company in April 2021 and the proposed Open Offer component of the Fundraising. Accordingly, due to the expected time and cost of complying with the requirements of that process, the Company considers the Open Offer not to be in the best interests of its shareholders and will therefore no longer proceed with the Open Offer.

In substitution, and so as to remain true to the commercial intent of providing as many existing shareholders as possible with the same opportunity to participate in the Fundraising on the same basis as new institutional and other investors, the Company has entered into an amended and restated placing agreement with its broker, Arden Partners Plc ("Arden"), and placing agent, Gneiss Energy Limited ("Gneiss"), (the "Placing Agreement"), to facilitate Arden raising up to an additional £2.0 million for the Company at the Placing Price (the "Broker Option") or such increased amount as may be agreed among the Company, Arden and Gneiss.


What the hell do Arden, Gneiss and in particular the Nomad, Strand Hanson, think they're playing at? This is basic stuff that they're screwing up. One for the FSA (to do nothing about)?

(no position - I get the sense that CEG has some OK assets, but this is not the financial structure that should be holding them)

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Re: Challenger Energy Group – Bahamas Petroleum reboot?

#478821

Postby spasmodicus » February 5th, 2022, 9:09 pm

Fellow fools...
of both Lemon- and plain old fashioned idiot- variety, the latter category seeming to be the one to which I belong. Challenged, rather than Challenger Energy Group would seem a better name for the company and I only hope that others were not seduced into buying shares in this rotten outfit by my G&G assessments passim, which did sadly did not include a character analysis of the board of directors of the said company. On that subject I will say no more, as the moderators would surely take issue with the immoderate language required to do that subject justice.

The really sad thing (apart from the unrecoverable loss of a couple of grand on my part) is that I still think that Challenger's acreage could really have been a modest little earner. Let me tell you a tale. Back in the 90s, one of my colleagues in Houston had inherited the family ranch, a pretty microscopic property by Texas standards, on the Austin chalk out towards San Antonio. There were two 2 stripper wells on the propery which went down a few hundred feet, with the usual nodding donkeys and separator tanks, that produced a few barrels of oil a week and a lot more water, which were trucked away every so often by a local oil company, who periodically sent a check (cheque). The wells had to be swabbed out occasionally and there were electricity bills to pay, but our man reckoned that he broke even at an oil price of just over 20 bucks a barrel. The point being that money can be made with a very simple operation.

That's the kind of outfit that Challenger needs to be. They are trying to do too much. Forget about new exploration play concepts and especially forget about drilling the Bahamas shelf. It all harks back to what will come to be regarded as the halcyon days of small AIM oil and gas companies, i.e. raise some millions on the stock market and, as directors, cream off as much as possible in fancy offices, salaries and expenses. When you drill a duster, go back to the market and raise some more dosh from the idiot punters. Rinse and repeat. If you get lucky with your wildcat as about 25% do, then you can unload your shares and retire, to the Bahamas probably, where you can occupy your time protesting about environmentally destructive oil drilling. The amazing thing is that in all the time that Challenger and its various antecedents have been going, nobody has actually managed to drill a decent well or two that covered their costs. However, if they were paid by the RNS, then we'd all be millionaires.

These days, you don't even get paper share certificates that you can frame and stick on the wall to remind your grandchildren of the follies of investing in small oil companies. Bah, I wonder if my worthless CEG shares could be converted into a Non Fungible Token?

Take care,
S


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