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This is not a negative post on GKP’s chances – far from it, it is, however, a call to remove the wool form your eyes and consider the bigger picture. GKP can have quite a good future in front of it, earning reasonable profits and paying reasonable dividends, but what it cannot do is escape the closing window of opportunity to maximise the potential of the Shaikan field. Every PF or CPF will need between 3 to 4 years to design, manufacture, ship and install, commission and debug – how many of those chunks of time are now left to the company?

The imminent WooDmac Report, if agreed and implemented by all partners, should at least give increased planning confidence to enable some of the above to be tackled.

The Aug-2016 Restructuring Prospectus gave all the detailed planning numbers for future field development – at that point output was in the low-40s Mbopd.

Today, ten years later, we are stuck at the same output, but when you look at the detailed planning content (P258 onwards) you can see just how far we have fallen behind.

Aug-2016 9 wells low 40s Mbopd output

Mar-2016 18 wells low 40s Mbopd output

Planned 2016 was 110Mbopd

Considering the number of new wells drilled in this period this clearly shows a field depletion rate of ca 5% - that’s no big deal of course, but the long-term effects - particularly on Capex funding are significant; it’s called running hard to stay still. Project that going forward and see what you get when planning new PFs or CPFs for 2031 or 2034.

Moving on from here is now a considerably greater challenge – whether we just go for a plain vanilla 3rd copycat PF to take us up to ca 75-80Mbopd, whether we go for the Big One, a CPF, with enhanced water- and gas handling to take us up to nearer 100Mbopd will need to be decided soon.

The capital costs are known (all in the Prospectus, but don’t forget inflation and don’t forget fabricator capacity), as is the time for realisation of such projects – but we are now in Mid-2026, 10 years have gone and can never be recovered; the contract ends June-2043.

Near-term, consideration must be given to the initial planned development of the Triassic – and that must include consideration of how to deal with its fluids (Condensate?) and its very high volumes of very sour Gas. Neither condensate nor very high volumes of very sour gas (Triassic KCB has 28% of non-HC solution gas vs only a fraction of that in the Jurassic) can be put thru a 3rd PF copycat GOSP, but will require expensive and separate (only very partially integrated) facilities – Costs again.

While you might get a copycat PF3 for $250-300M or so, a CPF capable of handling the condensate production and increased sour gas load from 1 or 2 Triassic wells could set you back $480M. There’s also separate tankage, and sour-service flowlines etc etc to consider plus where are you going to sell that condensate? – AND there’s the question of what to do with that quantity of very sour gas? Asking the market for debt funding will almost certainly mean a new Environmental Impact Assessment, which will fail on flaring of the H2S & CO content.

I expect the following:

Ankara will negotiate a completely new agreement before July 2026, because Gabar output needs a pipeline for its soon-to-be 100Mbopd and because losing the transit revenue entirely is worse than the current messy situation.

Gabar and KRI streams will be batched as only the current pipeline leg is usable.

Botas fees will increase to between $4.50 - $5.00/bbl.

The completely new contract will give TR the explicit right to transit Gabar crude using the old pipeline and will introduce a structured settlement / mutual write-down of the arbitration award (instead of full payment). IMO the $1.5Bn will never be paid in full, but expect a noml trade-off against the TR claim. TR will try to link it to gas/electricity cooperation as well AND will try to accelerate the Ovakoy Bridge, Road and Rail route.

Baghdad has no real alternative export route for the Med and will reluctantly accept all of this.

Make no mistake; Publication of the WoodMac report will be an important watershed moment for GKP.

Even accepting that it will only address the operational Cost side of those OilCos participating, it appears that Baghdad have accepted the logic of, and begun addressing, the capital costs repayment concerns – even if the Profit side is being kicked down the road. For GKP, this is fine as far as it goes, but it doesn’t go far enough – time’s a passin, and the wells have suffered a lot these last 2 years plus the field needs further development. Bearing in mind that a new PF or even CPF (larger, more complex) will require approx. 30 months from start to finish (from FEED, thru manufacturing, to shipping, to installation and then to final commissioning) the decision whether to order yet another PF, or go for a larger and more complex CPF (with some additional gas- and water handling), cannot be put off much longer.

For example; it is expected that GKP will attempt to drill at least 1 Triassic well, which will produce Condensate. Condensate cannot be processed by simply putting it thru the GOSP (which is what both PFs essentially are) and that output must either be put thru a completely separate module, or a dedicated section of the new PF/CPF. That implies extra investment and the total cost of such a CPF, incl condensate processing (plus tankage etc) will approach $450M (I expect a “copy & paste” PF3 to cost around $300M). In the same vein, the water cut will continue to increase, and the present additional kit already purchased or leased is not an ideal integrated solution, it’s a bolt-on extra that’ll just about do it - it’s not what you would try to integrate within a full-spec PF or CPF.

So, to my mind, the decision has now to be made – do we go for a Copycat PF3, or do we go for a full-spec CPF with more flow/throughput, increased water handling, better gas-handling (wet- and sour gas) AND Triassic/Condensate handling.

The Capex implications are significant and cannot be properly addressed by relying on current hand-to-mouth revenues funding necessary development.

The company will have to make up its mind soon – stumble on or seek a well-heeled suitor.

IMO

The First Amendment to the Iraqi Federal Budget Law for 2023-2025 was passed by the Iraqi Parliament on 2 February 2025. The amendment to Article 12-2-c provides that "the fair estimated COSTS OF PRODUCTION AND TRANSPORTATION are calculated for each field separately by a specialized international technical consulting body, to be determined by the Federal Ministry of Oil in agreement with the Ministry of Natural Resources in the region, within 60 days of the entry into force of this law." (CAPS ARE MINE)

Note that it does not mention PSC entitlements or profit oil.

Wood Mackenzie's appointment was announced later in May by MNR, and was described so:

“Wood Mackenzie has been tasked with reviewing production costs, investment levels, AND PROFIT MARGINS per barrel of oil for international companies operating in the Kurdistan Region”.

Note that this is NOT what the 1st Amendment noted above says. (CAPS ARE MINE)

The law text is specific and rather narrow; the amendment does not refer to the profits of oil sales, but rather only provides for compensation in respect of costs of production and transportation. It remains to be seen how this matter of profit and costs will be addressed by the technical consulting body in the future.

As even Rudaw reported on the tripartite agreement: any disputes raised by IOCs regarding the final report are to be resolved directly with the Ministry without amendment of SOMO payments under the agreement.

This an important qualifier - even if say GKP or DNO dispute WoodMac's findings, SOMO continues paying at whatever rate the report sets — there is no contractual mechanism to suspend payments pending dispute resolution. The IOC's only recourse will be to negotiate with the ministry, while their leverage (withholding oil) has been structurally removed by the arrangement.

There is a structural problem with the WoodMac mandate that goes beyond methodology. Under the agreement, any disputes raised by IOCs regarding the final report have to be resolved directly with the Ministry of Oil without amendment of SOMO payments. This means the $16/bbl rate will continue to be paid regardless of what WoodMac finds or what the IOCs dispute — Baghdad has effectively insulated the payment mechanism from challenge during the review process. This gives Baghdad significant leverage: it can accept WoodMac's findings selectively, accept the cost element but resist the profit element, or simply delay implementation of any upward adjustment.

In my view, the most likely outcome of the WoodMac process is a revised per-barrel payment in the range of $18-24/bbl — above $16 but below the IOCs' full PSC existing contractual entitlement — perhaps accompanied by a sliding scale mechanism that PARTIALLY links IOC compensation to the prevailing oil price, giving IOCs some upside at higher prices. This would mean Baghdad pragmatically accepting that $16 is insufficient to sustain production, while falling well short of honouring the PSC's original cost- and profit-oil framework.

By withholding binding commitments and leaning on ill-defined repayment schemes, Baghdad therefore keeps investors cautious, reinforcing its significant leverage over Erbil. The final result will be financial uncertainty that undercuts the deal's lifeline. This is a continued characterisation of Baghdad's strategy — and it means the WoodMac report is unlikely to be the clean resolution that IOCs are hoping for, but rather the next round of negotiation conducted with technical evidence.

You are now seeing some of the consequences of this uncertainty, but expect more after Baghdad releases the WoodMac report.

512,463 shares issued.

Price was NOK 22.10, approx. 170.5p.

Plus 25,624 new shares to underwriters...

VanVan,

my interpretation is: "depending on how things go in the next couple of months (WoodMac, contracts, outstanding receivables, timeliness of payments, etc), we will evaluate whether shareholder distributions (dividends) can be increased or should be reduced".

"The Company is pursuing the Listing as part of ongoing efforts to increase the liquidity of its issued share capital, attract new institutional and retail shareholders AND IMPROVE ITS ACCESS TO CAPITAL MARKETS".

(CAPS are mine)

That's what I have said all along - getting ready for the next bond issue.

Fingers burnt in London...

Putup,

the R-factor formula is more or less the same a GKP's but with the different trigger points.

The DNO PSC states:

R less than one starts with the high value of 38%

R greater than 2.4 gives you lowest value of 16%

Didn't work . Fu** it

One last try:

R

There appears to be an LSE problem - it will not accept / display my input properly.

Have a look at the DNO PSC yourself.

The site LSE software is messing up my input, for some reason. Here is what I tried to post:

R

Of course they have the R-factor - I just gave you the headline number!

Crude Oil Only (excl. Gas)

R 2.4 16%

Carelessness yet again,

Profit Oil = 38%

Careless typing!

Cost Oil = 45%

Profit Oil = 36%

Not surprised, DNO's PSC for the Tawke block has higher Cost Oil percentage (45%) AND higher Cost Oil percentage (38%) than GKP's.

Our copy is signed and countersigned 13th March 2008.

Putup,

re yr 17:40 yesterday, you said: "Who cares about how many gallons of water there is?"

You should care very much about just how much non-oil fluids are being handled / processed, as the PF (assuming this is where the separation is taking place) is configured for a defined throughput of fluids. Also the separation of water (and gas) from an incoming crude oil stream is time-consuming (check out dwell time inside separator unit) and to a certain extent becomes the bottleneck for the production plant. If the PF is configured for throughput of say 55Mbbl per day and 20Mbbl of that is produced water, then only 35Mbopd (barrels of oil per day) can be throughput. It's not clear if 2- or 3-stage separators will be utilized for water separation at PF2 / PF1, but their sensible integration into the general process stream layout may be limited by existing plant considerations (space). We don't yet know what water cut is expected.

Starsalign,

I've nothing against the logic and basic thrust of your argument / view, but with oil production facilities such as PF1 & PF2 there are ALWAYS capital expenses going through the books; Pumps fail, pipework fails, electrical instrumentation fails - even the light bulbs fail! There are also plant optimization & improvement measures, as well as ongoing maintenance work. It all adds up.

These of course are generally relatively minor amounts but there is one major item that must by now be either delivered and awaiting installation & commissioning, or on order: The Water Handling Equipment.

We haven't been told how much water is or may be produced, and whether the produced water will be stored/tanked before disposal or put straight into a disposal pipeline (nor has it been confirmed that an existing well will be used as a disposal well), etc. but the costs are not insignificant and, depending on anticipated H2O volumes, could well be several $M. If the equipment is required at both PFs then the cost of course may double.

In the greater scheme of things of course, with a good production rate and a healthy crude price, such capital costs could be recovered in a month or two.

At the moment we don't even know if the 40% CO recovery formula will remain valid, or if an omnibus figure will be applied.