Member Info for PUTUP

Just to highlight my point again Belgrano, here is where you are going wrong:

"Then found out they were so dumb they didn't even know exactly what the contracts were.

This has been rectified and explained to them, and they now understand exactly why there was a big difference in the two types of contracts. Strangely enough they then understood the rational behind all the contracts which I suspect is fairer than they administer out in SOMO."

It's not the contracts. It's the understanding as to why costs, and hence cost reimbursement, are so high. All the contracts have a formula for cost reimbursement and prior precedents aren't miles off our current PSC i.e. the contracts are very similar in this regard. It is the nature of the fields that's different - developmental and hence capex loaded. Now that this is better understood hopefully they can begin looking at the cost reimbursement mechanisms in the current contracts themselves and see that these are broadly in line with precedents. (At least enough such that they don't feel the need to renegotiate them.) And then move onto the other important elements of the contracts...

Morbox " at least cash in-hand hasn’t decreased (up 2m)"

FCFY "GKP building cash while waiting is a huge positive. "

You guys do realise that cash has FALLEN by $3m since the last update a month ago, right...?

And as I said from the outset:

"Proactively managing and reducing accounts payable with balances trending towards levels in line with ongoing monthly expenditures"

"So that's a huge initial jump and for the hard bargaining double dealing Arabs signifies that they most certainly want to play ball. "

Don't mistake understanding cost structures (field development expenditures, opex and direct G&A) with contract discussions. I would suspect the second part hasn't even begun. They've only been going through the discussion of why payments (including cost reimbursement) have been/need to be so high. (And likely why there's only been limited involved in discussion by the operators.) You are giving credit to APIKUR where it is not due.

As I've said before, I expect contract discussions to retain the variable cost reimbursement element of all prior contracts. In fact, outside of the royalty, the current contract is quite a good basis for future operation. Merely convert its terms from a PSC to a RSC. No margin is made on cost reimbursement aka cost oil.

As FCFY mentions, once direct expenditure and reimbursement is understood there's still agreement on transportation costs and then the remuneration fee/'profit oil' component to go. Our current contract is 'fair' versus other precedents in this regard.

The scary part is the relatively low royalty...

Silly expectations lead to disappointment. Time and time again. Plus ca change...

No premium paid. Simply an off-book trade, conducted earlier in the day, reported after hours. Well within the trading range for the day. (And hardly large.) I wouldn't read anything into it itself. Nonetheless tomorrow is another day. Let's see what it brings...

This board conjures images of a bunch of feeble, wrinkly, old men slowly dying in a care home arguing over politics (and, worse, football) in their pajamas and zimmer frames. Some with greater levels of dementia than most.

(What happened to the nutter swinging at spin bowls in his head? Rhetorical question of course...)

By "untimely" I didn't mean sluggish/late payment of what is due. That risk sits on top of a potential mismatch between expected expenditure (FDP) in a given month or couple of months and that which can be recovered in the same period.

"Can they hold the line?" No idea. All depends on whether the recovery envelope makes that easy or really hard. Everything is at stake in the current negotiations. Turning the tap back on ("the oil will flow") is the least of our worries. I'm certainly not prepared to pay now for highly uncertain growth in the future. Luckily, we aren't currently being asked to by the current share price.

Let's see what happens.

People here have perpetually failed to understand the nature of the working relationship with the resource owner, the role GKP performs and the checks and balances on their investment - both push and pull. (Let alone the agreement that dictates how they are paid.)

The contract, PSC or otherwise, will dictate when, how and what costs will be reimbursed and what 'remuneration fee' or Profit Oil component exists for the operator. The CRP is nothing other than a ledger.

If they can maintain capital discipline, GKP won't agree to implement an FDP that requires a significant building of the CRP ledger due to untimely cost recovery. Hopefully they can manage this. Hopefully the agreed cost recovery formula allows enough headroom to achieve good production volume growth. Before they start investing again, GKP will want to recover the last sliver of the historical CRP and have high confidence on receivables recovery. Don't expect to get back to March '23 volumes anytime soon...

Last 6 months: Genel -26%; GKP -7%. Don't want to 'catch up' with Genel.

BB

The first stage is recognition of the development nature of the Kurd fields and hence their high capex. (I doubt an opex figure of $3 to $3.40 per barrel is an issue.) The next stage is to figure out how to implement a contract. Even the EDPC / DPC, BID ROUND 5 contracts were sensible regarding cost recovery. According to this document (table pg 16) https://iraqenergy.org/product/iraq-5th-bid-round-analysis-report/

"Begins when commercial production begins; from a maximum share of revenues after royalty, from 30% if oil price is $21.5/bbl or below, to 70% if oil price is $50 per barrel or above."

People will recall that our current contract provides for a maximum of 40% of post royalty 'revenues'. (I prefer the term field sales so as to avoid confusion with company revenues.) At reasonable Brent prices and even with our historical $32 discount (incl transportation) that formula above provides for a similar cost recovery. (Not forgetting, of course, that contractors can't recover more than they've spent. Cost recovery for a billable period is the minimum of the EOP CRP and the amount permitted under the agreed formula.)

It all comes down to how SOMO/Baghdad want to pursue field development. I certainly don't expect the agreed contract to be a fixed number in the same way that the latest rounds weren't either. Rather I think all the chatter about $20 or so is about UNDERSTANDING the current development and extraction costs of the region.

In any event, as you note above and as I've said many times before, we need GKP and other IOCs to exert capital discipline and only agree to implement an FDP that fits well within the cost recovery envelope based on conservative expectations as to future sales prices. Company 'revenues' might be down but the matching costs should fall in line. There's no margin made on cost recovery.

The second question is then what is the "remuneration fee" (otherwise known to us in the current PSC as 'Profit Oil'). Just like EDPC / DPC, BID ROUND 5, the current PSC is a share of revenue remaining after royalty (and deduction of amounts going to cost recovery). The current PSC is different in that it uses a sliding scale based on an R Factor but again the concept is broadly similar - a small share of revenues in return for executing the FDP on behalf of the resource owner (KRG/Iraq). At the moment, given the CRP still exceeds current monthly costs albeit not for much longer if exports restart, we are currently getting about 10% of revenues post royalty and cost recovery, again firmly within the EDPC / DPC, BID ROUND 5 range. (We pay a CBC and the KRG pay our taxes.) This is where GKP makes its money. (Profit Oil/Remuneration Fee less non-recoverable costs.)

Hopefully they don't revisit the royalty. Currently for us it is 10%. EDPC / DPC, BID ROUND 5 contracts were (according to the document) much higher...25%.

We will have to wait to see what unfolds.

Average closing price last 3 months: 121.08p. Current price 116.3. Nice to have the rise today, but some of you getting giddy.

Awaiting real news.

They recovered $20 per barrel for Sep '22 production - the last paid invoice. For Aug '22 it was $28. $32 for July. As Brent fell closer to its current level in February 23 (averaging $82.59) the Contractor invoiced about $19.20 a barrel for cost recovery.

Given almost all historical costs have been recovered or are invoiced in the receivables balance (the Contractor balance for Shaikan CRP is only about $65 million now) GKP should simply throttle recoverable costs (opex, direct Shaikan G&A and capex) to stay comfortably inside whatever upper limit is allowed. Smaller envelope, smaller/slower field development.

Ha. I have no master. Please load up anytime. Please just make sure you have the volume to make a difference. Chump change isn't going to cut it. :)

My point was that the current share price ALREADY prices in a full restart to exports via the pipeline sometime in 2Q 24. If it ever looks like things will take even longer then I'd expect the stock to be pressured to the downside. Receivables recovery isn't priced in. You can argue there's a little of each priced in rather than all of one and none of the other. However, I regard receivables recovery as much more at risk than pipeline restart and hence like to characterise things that way. In my opinion, a significant share price pop based on export restart that isn't supported by confidence in receivable recovery will be short-lived.

SP Drivers:

- pipeline restart: already large in the price

- clarity on cost recovery mechanism and PSC/successor contract sales pie sharing agreement: need to see details of the agreement reached and compare it to current PSC

- receivables recovery: key driver. Over what time period will these be covered and what risks are attached to actually getting payments?

- price Shaikan crude is sold at (ex transport): can we recover the 'discount for KBT'? Can we do even better? Might be good driver but wait and see

- production volumes: I don't expect volumes to exceed 50k bopd this year. Field has been starved of investment. Investment (new drilling) will be throttled until CRP and receivables have been recovered. New investment in the field will be limited to that which fits within the cost recovery envelope of the new contract as expect new discipline from GKP and all other operators.

What do you consider are "definite signs of stock accumulation"?

"How sustainable over a prolonged period it is, remains to be seen"

Let's assume it is sustainable. Do you think the current share price reflects selling modest volumes locally at $30 a barrel? Or do you think there's a lot more optimism priced in?

"If they fear being ripped off by IOCs then they should simply ensure the allowable costs are verified in a robust manner - there are lots of countries that manage to achieve that! "

People here repeatedly forget that GKP (and other IOCs in Kurdistan) have had to agree expenditures with the KRG, both via a FDP and authorization of significant expenses. Why? Because the KRG has had to reimburse the operator for those expenses. GKP implements an agreed strategy, fronts the capex which is reimbursed from production proceeds over time and earns a small amount per barrel for doing so. The 5th and 6th round contracts are no different. (I refer people again to the summary provided I the link previously posted.) Once again, don't confuse cost reimbursement (on which no margin is made) with a 'profit' amount which must cover all the company's non-recoverable costs. A tighter cap on cost reimbursement should mean that the operators throttle their field development accordingly - assuming they have discipline that certainly didn't exist prior to 2016.

It's been a good call...

Not even close.

The key issue at hand is cost RECOVERY. I have all-capped that last word on purpose. The IOCs won't be paid for costs they haven't incurred. The Profit Oil component is much smaller - GKP has already been working for $4.14 a barrel (PO-CBC per barrel, last paid invoice of September 22 production). As seems all too prevalent, Kheldar has trouble understanding the company's economic fundamentals. (He also seems to think that costs can remain constrained at $6 while output is ramped to more than double its current level.)

In response to highlander1970, the low lifting cost (opex plus direct Shaikan G&A) per barrel is real. The problem is that people then think the company gets the difference between the opex per barrel and the price the oil is sold at (and oftentimes even think the barrel is sold at Brent pricing as even his post implies). That's far from the case. Prior to the ITP closure the realised price per barrel was $32 BELOW Brent. From that a 10% royalty is deducted before we even get to divvying up the balance. The reason why there were zero invoices wasn't because lifting costs per barrel were high but rather because the realised sale price per barrel was so low.

"OK putup, what’s YOUR view then ?

«Let's assume, this moment has passed and the pipeline is open and GKP now is producing 50k bpd

How much would you value the company»"

End Feb fair value ex receivables: 130p (assuming back to 50k production by June)

"I honestly couldn't answer that,higher than today's price but how much higher I don't think anybody knows."

That's hilarious. Long a stock with no view as to what it might be worth...