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Hodl, you showed me last night your clear and obvious lack of knowledge in O&G and you have done it again in this most recent post. Quite frankly you have zero credibility and merit in the discussion of technicals aspects of topsides modifications. You can google your way to an argument all you want but don't be fooled in to thinking you know what you are talking about.
Change out of pipework and plant topsides is a relatively straightforward process, more so onshore as you don't have to deal with the same logistical issues, simops, etc. You may think scale makes things more difficult, but you are wrong. It makes things more expensive and time consuming, but "difficulty" is not a factor. For example, a problem exists on one well that exists on 10 wells. You have the solution (e.g. swapping out pipework and heater treaters), you have a standard procedure, the materials, the engineering work and the personnel. Do you think difficulty increases on wells 2, 3 and 4? No, it actually decreases in difficulty. Again your fundamental lack of knowledge on this subject is obvious.
Changing out equipment isn't as difficult as you think it is. It literally can be done in a matter of days, speed is important because Operators want to limit downtime. Time is money in O&G after all.
"You conveniently forget c40km of gas gathering lines, an oil gathering system, a new oil processing facility, gas sales pipeline into the sales network, gas plant upgrades, 8 production well drills, 1 injector well drill and the budgeting of $49m."
Nope, I didn't forget that, mostly because you have made up most of it being a problem. Please provide reference to the change-out of 40km of pipeline, the oil gathering system (export pipelines / manifold?), a new oil plant. I also didn't know we were selling gas - a reference for that would be useful too. My understanding was that the heater treaters were used the separate the butane from the export stream so that the gas can be reinjected. The export pipeline is owned by PipeCo, which COPL owns as part of the Atomic acquisition.
And just for completeness. I didn't argue that there isn't a lot of work to do. I argued that it isn't difficult, which it's not, if you understand the issues.
Sorry hodl, but you don't know what you're talking about. The team size is not important. Experience and knowledge of the asset is, which SWP and COPL have in abundance. They will outsource services to contractors if needed who have the expertise to carry out the work, fairly typical in O&G.
They are not re-engineering to new pressure standards at all. The standards exist and have done for decades. They are changing out pipework with a higher pressure rating, which can be as simple as an increase in wall thickness and/or material (more likely the former). Hardly rocket science.
A global supply chain issue and recruitment challenges? Come off it. You can't be serious that is the stumbling block and why it makes these mods so difficult.
Sorry but it gets my back up when people post thinking they know what they are talking about when they clearly have no clue.
HODL. Topsides fixes can be simple, whether they are EOR or not (which is irrelevant really), if you know the solution and have an experienced team to carry those mods out. Changing out pipework and heater treaters for example are simple fixes. Onshore is vastly easier than offshore where you worry about access and lifting requirements. Shut in, double isolate, unbolt flanges, change-out, pressure test, commission. The engineering work will have been done well in advance to the correct codes and verified by a IVB.
Feel free to explain to me how difficult it is.
The market may not trust Arthur currently, but once the company start delivering and production trends up month on month, it is funny how short people's memories can be.
As I said previously, all of the issues that are present have an associated solution that has been advised will be resolved in time - production constraints, finance, communications.
The talk of debt is irrelevant in the context it is wholly negative. It is what that debt buys, that is what is important. $380M NAV for $65M in debt is a good deal by any measure. I'd suggest research some of the majors and mid-tiers and look at the debt they hold, despite booking profits. It's how companies progress and I'm not aware many (if any) successful O&G companies that haven't taken on debt at some stage. In fact, there are credit and tax benefits in holding debt.
The share price will begin to converge with NAV once the known issues are resolved, and I expect they will be given time. That is what investing is, forward looking and one of the metrics to assess an undervalued or overvalued stock is NAV vs MCAP.
This company is now trading at 13% of NAV, discounting any consideration of the new discovery. You think it will remain at that when they remove the production constraints?
The company have made it clear their plans to rectify the issues, which are relatively easy to implement with limited risk. Install topsides mods, install a pipeline, work over the wells, drill new wells and tie this in to the existing infrastructure. It is straightforward, the majority of it bread and butter stuff for the operational team. They have the finance to do all of those things.
However, the company have to wait until the summer to get after the bulk of that work. The perception is there is no good news until this happens, hence a lull in activity. The oil market is buoyant with no signs of dipping.
Set your sights further down the line and it will provide some reassurance.
Morning Illusion. Yes, understood regarding the gas line. However, is it the over-riding constraint in the system? i.e. the pipeline is the bottleneck regardless of the system upgrades upstream. For example, if the pipeline can handle for arguments sake, 70% of working pressures but the wellhead pipework can only handle 60%, there is an incremental increase of 10% by changing out the wellhead pipework to align that with the pipeline safe operating pressure. Albeit, not fully optimised, but it allows for some benefit.
I'm not sure it will be as much as that gold. I'm not certain where all the constraints in the system are. There are likely several modifications required to fully optimise the unit, one of those being the new pipeline. However, these wellhead modifications may or may not provide incremental production increases. For example, if the true constraint is the pipeline, the company will have to choke the wells until that is remedied and this is just preparation for that. However, if there are constraints in the wellhead pipework, then it is possible the change-out will allow SWP to ease the choke and provide a better production rate.
It's one to keep an eye on but most importantly, SWP are getting on with things. As time goes, we should see more of these modifications completed and ultimately it should reflect in better flowrates.
SWP have recently (4th May) received approval for topsides modifications on two wells in the Shannon, expected to be completed in around 2 days. First up is well 34-20V, scheduled this month, followed by well 44-21V in July. Both wells are among those with better response to MF, albeit producing just 170bbls/d currently. It will be interesting to see the effect the modifications have on production going forward. Note the following example of well restrictions in the AIF.
"Another example is the undersized and low-pressure heater treaters on most of the wells. The recent unrestricted testing of one well proved that it could be flowing at 600 to 800 bbls/d if it did not have to be restricted by the undersized treater and the low-pressure gas gathering lines to prevent flaring of the gas. As a result, the well is choked back to 150 to 250 bbls/d until the bottlenecks can be remedied. More and more of these types of restrictions are expected as the field continues to respond to the positive effects of the miscible flood."
Thanks for the clarity 3LP. I will happily stand corrected if that is the case. My take was that court sanctioned approval and confirmation that oils sales were being accrued direct in to SWPs accounts as stated essentially meant it was bookable as revenue. Oil sales as of January stopped going to CUDA and direct to SWP to reduce the recievable over time. A finer detail I suppose and as you say, has the same effect essentially.
It can be considered income. COPL were burdened for most, if not all, of 2021 with shouldering CUDAs OPEX costs which were reflected in accounts receivables. As of January, that changed. Not only will that arrears stop increasing, it will actually be decreasing as of January because effectively, CUDA (via SWP taking their WI in oil sales) has started paying it off. So there is a two fold positive there - OPEX burden decreased and oil sales to settle the arrears begun. That will be reflected in the cashflow in Q1.
Whether it is enough to push them in to profit remains to be seen but my guess is that it has.
Iron, the initial court case in December approved that SWP could take CUDAs share of oil production to settle their arrears to SWP (as it confirmed SWP were first lien creditor). As such, as of end of December (effectively start of Q1), COPL have increased their WI by 27%.
See ref 10th January RNS
"Southwestern continues to take Cuda's operating net revenue through set off or "net billing" to reduce the arrears over time. As such, Cuda's working interest share of the oil production and expenses in the Barron Flats Shannon Unit accrues to the account of Southwestern as the field operator, and creditor, until the arrears are satisfied."
I'm expecting a net profit in Q1 for the first time in COPL's history. Not necessarily a huge profit but nevertheless it will be a significant milestone if that is achieved.
Net production to COPL will be higher as CUDAs share on production is being accumulated in to COPLs books to settle the outstanding arrears as of January. As well, I suspect CAPEX will be down somewhat as we are out with the drilling window in Q1 (Q4 the company were still completing the discovery drill).
Overall, I'm optimistic on the Q1 results which may also include the Ryder Scott report.
Agreed coed. Unfortunately this will be the case for a period still. Emotions running high following news of the placing, but as with previous, it will run out of steam and settle. For now, not much to do other than let it play out.
Cuda purchase is made up of the $20M secured credit loan, >$3M receivable as first lien and a portion of existing cash reserves which stand at approx. $7-8M. Purchase price TBC.
New placing is intended for topsides modifications and drilling plan going forward i.e. the pipeline and other mods to optimise exisitng production. As well as new drilling campaign
I was having a read through the AIF again. Some really good and detailed information in there. I strongly recommend shareholders invest some time to read through it in full to get a better understanding of company plans to optimise production from the asset.
One example that jumped out at me was the below. Resolving this is expected to result in a circa. 400% increase in production.
"Another example is the undersized and low-pressure heater treaters on most of the wells. The recent unrestricted testing of one well proved that it could be flowing at 600 to 800 bbls/d if it did not have to be restricted by the undersized treater and the low-pressure gas gathering lines to prevent flaring of the gas. As a result, the well is choked back to 150 to 250 bbls/d until the bottlenecks can be remedied."
Expand this remedy to "most of the wells" affected by this constraint. Immediate production increase several times that of existing production.
There are other constraints noted in the AIF and detailed solutions to address each. It will require some capital expenditure, however if optimisation can produce results in line with the example above, it will be well worth the initial outlay and provide security moving forward.
Dunc
Give it time ART. We should all be aware of the roadmap and project lifecycle here. Understand there is work to do but be cognisant of the intentions and potential of developing this asset. I don't think it's appropriate to compare COPL with other companies that are at a different stage.
There was a lot of information in the AIF, filed alongside the MD&A and Annual Financials, detailing what needs to be done to optimise existing production and injection unit.
The company cannot divulge anything on CUDA as it is a legal process. However, there is a domino effect once this is resolved.
CUDA WI consolidation unlocks an increased NAV and increased production WI.
Greater NAV and increased WI enables refinancing of the SCF.
Refinancing of the SCF provides funding for the pipeline installation.
Pipeline installation resolves much of the topsides production constraints, albeit there are others to fully optimise.
Production optimisation allows the company to workover existing wells and indeed drill new wells on the unit, providing maximum benefit from these operations.
Then factor in the Frontier / Dakota reserves report and subsequently progress on delineation & field development.
Communications will be improved as operations gather pace, BUT we aren't there yet.
I see our posts crossed paths Tiburn and largely say the same thing... but I'll post it anyway
Dunc
8) If COPL does acquire CUDA's assets that will mean a lot of extra outlay, which is not good as the company can only just keep up with their costs at the moment.
You do realise SWP have been picking up the costs for CUDA since middle of last year? Hence why they have a substantial receivable due from CUDA. As of January, they have started settling this through CUDAs WI in oil sales
9) To increase production a lot of extra wells will need to be drilled and as things are going at the moment that might mean a lot of extra cash which will mean lots of extra dilution and a very low share price.
This will need significant funding, hence why the company are refinancing. We should expect some dilution I'd suggest but I expect this to be heavily weighted on credit. Again, how else can the company exploit the field. That is fundamentally how this works.
10) Poor management with a lack of information is not helping things here, nor is the permanently low share price. Shareholders are more than a little p*ssed off.
No argument that communications need to be improved. Hopefully going forward this will be addressed
I'll answer these one by one Art.
1) the company incurred a lot of debt when acquiring this asset
That is true for many companies. In fact, I'd argue companies in O&G must take on debt to progress. It is primarily what you are getting for that debt, that's the question. $35M debt on the SCF (excl. add ons) for ~$250M NAV is a good deal by any measure.
2) immediately production was increased with gas injections and then the next thing we know there was no gas available so production figures dropped back to where they were before.
Not true. Production has largely been sustained at approx. 2kbpd. It hasn't dropped back at all.
3) Partners CUDA mysteriously slipped into administration - not a good sign.
Because they could not manage repayments on their debt facility. I recall something like $70M debt on <500bpd at $40b. Completely different scenario.
4) Production can be increased by laying 2 km of pipeline - but this can only be done when the CUDA administration problem has been resolved and then there might be further questions/problems depending on what happens to CUDA's assets
Consolidation of their WI? We has been heavily suggested that this is progressing and is coming to a close. Yes, we need a pipeline, but much of the engineering has been completed. There are other topsides optimisations required, all documented in Annual Results. There's a solution. Main point is the problem is resultant of good field response.
5) The huge oil discovery drill was fraught with problems - and could only initially flow at 100 bopd.
Misleading. The discovery flow tested the lowest zone, the Dakota. The primary focus will be the zone up from this, Frontier. Expectations are several thousand barrels per day per well.
6) They need to refinance the debt which will no doubt come with the obligatory placing as lenders like to see the company come up with a chunk of the cash themselves - and at the current share price that will mean further dilution
Possibly but this misses the bigger picture. If a combination of credit and equity increases NAV and provides funding for development, what is the concern. Would you rather the company did not fast track development of this field?
7) Without knowing the details some amount of current production is hedged at some silly low price and we are getting virtually no gain from the $100 barrel oil price. To be honest this is just bad management as the hedge needs to be reset to meet the current high oil prices
Again, misleading. The 'hedge' is part of a swap agreement whereby the company have sell swaps on their oil and purchase swaps on butane for MF. The company have a net gain of $0.2M on the swap agreement last quarter.
8) If COPL does acquire CUDA's assets that will mean a lot of extra outlay, which is not good as the company can only just keep up with their costs at the moment.
You do realise SWP have been picking up the costs for CUDA since middle of last year? Hence why t
I've had a very quick look at the company filings to assess valuation. This is what I see as of 31st December. Happy to be corrected.
Key tangible assets:
Cash and Equivalents: $7.8M
Accounts Receivables: $6.8M
Exploration & evaluation: £5.2M
Property & Equipment: $78.0M
Total tangible assets: $98.8M
Liabilities:
Accounts payable: $12.4M
Secured Credit Facility: $36.4M
Other liabilities: $5.6M
Total liabilities: $63.7M
NPV of Producing Asset after tax (assuming 10% tax):
Proved Developed: $78.7M
Proved Undeveloped: $35.2M
Probable: $99.7M
Total: $214.4M
Net Asset Value, based on the above, is $249.4M.
Excludes any reserve valuation of new discovery in the Frontier / Dakota zones. Excludes potential of increased NAV due to acquiring Cuda WI.