Member Info for PUTUP

His 36.8% is just an overall figure. The components to that are what they got via cost recovery and their share of profit oil, less the capacity building charge. The R factor for October was still <=1 and so the WI in profit oil was still 30% (and not lower). As has been stated often before, the WI is split 61.5% GKP, 18.5% MOL and 20% KRG. The KRG also withholds from receipts 20% of GKP's WI as a capacity building charge. There - you have everything you need to complete the figures for the full year scenario.

Still struggling DubiousInvestor?

a. Brent average for year $85 (your assumption)
b. Discount $21.1
c. # Days 365
d. Production bopd 55,000 (your assumption)

e. Proceeds from oil sales: (a-b)*c*d = $1,283 million
f. Royalty (10% of e) $128.3 million
g. Net proceeds from oil sales: e-f = $1,155 million

So that's what the field produced for the year and that's what is available for division between GKP, MOL and the KRG according to the "Production Sharing Contract".

h. Total Profit Oil: 0.6*g = $693 million

i. Contractor Cost Recovery: 0.4*g = $462 million This is reimbursement of past direct expenditure incurred. It reduces the Cost Recovery Pool while opex, direct G&A and capex increase the CRP

j. GKP Cost Recovery: 0.8*i = $369 million

k. KRG direct share of Profit Oil: 0.7*h = $485 million Remember for simplicity we assumed an R factor less than 1 which means the "Working Interest" in Profit Oil is 30%. The balance goes straight to the KRG.

l. Working Interest Share of Profit Oil: 0.3*h = $208 million. This is shared between GKP, MOL and the KRG.

Come on. At least make an effort on the last few numbers.....

m. GKP Profit Oil
n. GKP CBC withheld from receipts

o. GKP Revenues

p. GKP Net receipts (post CBC withheld)
q. % Cost Recovery

(Peak at answer: you ought to get to GKP Revenues of $497 million.)

You clueless? If you can't fill out those 17 lines then, yes, I agree. It's not hard. Here, I will do the first 7 for you:

a. Brent average for year $85 (your assumption)
b. Discount $21.1
c. # Days 365
d. Production bopd 55,000 (your assumption)

e. Proceeds from oil sales: (a-b)*c*d = $1,283 million
f. Royalty (10% of e) $128.3 million
g. Net proceeds from oil sales: e-f = $1,155 million

So that's what the field produced for the year and that's what is available for division between GKP, MOL and the KRG according to the "Production Sharing Contract". Have a go at filling in the remaining 10 numbers.

h. Total Profit Oil
(hint: if Cost Oil is 40% of net proceeds from oil sales then Profit Oil is the balance)

i. Contractor Cost Recovery
j. GKP Cost Recovery (hint: the contractors share Cost Recovery 80:20 GKP:MOL)

k. KRG Profit Oil
l. Working Interest Share of Profit Oil (hint: for simplicity in this first go, we assumed R less than or equal to 1)

m. GKP Profit Oil
n. GKP CBC withheld from receipts

o. GKP Revenues

p. GKP Net receipts (post CBC withheld)
q. % Cost Recovery

(Peak at answer: you ought to get to GKP Revenues of $497 million.)

Where I wrote "Net Revenues" should be "Net Sales" so as to not confuse it with GKP Revenues

No need for a spreadsheet (although it helps if you want to run it again at a later point with different assumptions). A pencil and pieces of paper will suffice. A calculator (or slide rule if you prefer) will help with the maths.

"PUTUP you put a lot of words but not many numbers. Please be precise on your calculations. If not you are playing a misleading game"

DI, these calculations have been posted many times before. Perhaps I and others get tired of people ignoring that or seeing it and still not endeavouring to do their own work. I will tell you what: have a stab and filling in the blanks on the following to arrive at an estimate of annual revenues for the year. I and others can then help you with any errors you may have made. We can afterwards, if you'd like, work further down the P&L statement. To make it easier for now, assume there is enough CRP for fully 40% of production to be allocated to cost recovery and that the R factor stays below 1 such that the Working Interest in Profit Oil remains at 30%. It shouldn't take long. It is the same calculation as for the monthly receipt except applying assumptions for the year.

Brent average for year
Discount (hint: $21.1)
# Days (hint: 365)
Production bopd

Gross Sales
Royalty (10%)
Net Revenues
Total Profit Oil

Contractor Cost Recovery
GKP Cost Recovery

KRG Profit Oil
Working Interest Share of Profit Oil

GKP Profit Oil
GKP CBC

GKP Revenues

GKP Net receipt (post CBC withheld)
% Cost Recovery

@damofarl First, remember that hedging protected the downside. It did not lock in lower prices. The company kept the upside but incurred the cost of the hedge. I think you will find if you speak with the company that prior hedging rolled off in September last year. I'm not sure if they've done more hedging since but I doubt it.

"Putup,
They only got $44bbl in H1. Is that discount to Brent likely to be similar in H2."

Not sure what you mean by "they" and "got". Oil is sold at a discount to Brent of circa $21.1. (You can see this figure in company presentations.) For now I see no reason to change this assumption. GKP "gets" a lot less than Brent less 21.1 as Revenue. What GKP gets is determined by the PSC... Oil is sold at Brent - 21.1 and then a 10% royalty is deducted. What's left is split up as per the PSC between GKP, MOL and the KRG. Only then do you get to GKP revenues.

"Prior payment rnss are a good guide. "

to Revenues...

Indeed if you can construct a simple model (you only need 15 lines or so!) to estimate a month's receipts you can do that for the year. Receipts are Revenues - CBC. In the financial accounts the CBC is deducted lower down the P&L. Having derived an estimate of revenues you need to deduct the direct opex (GKP share of $2.40 a barrel), direct Shaikan G&A, corporate overhead costs, depreciation, interest etc to get Profits.

"Yearly profit from oil at 55K bopd = 55K * 365 * ($35.496 || $30.6) = $712.5822m || $614.295m"

I'd go back and re-examine your model if I were you. Receipts aren't even as high as that using 55k bopd and $85 Brent, let alone profits. Under those assumptions REVENUE is closer to $498m from which a lot of costs need to be deducted. And even that figure assumes there's enough CRP to 'support' 40% of production going to cost recovery - an assumption that would likely prove very wrong.

"60% hedged around $40 and the rest @ $70 bbl"

Nothing is hedged

I never said we get 60% of the proceeds of production.

The company produces oil and so there isn't a need to use boepd; bopd suffices. I think you're asking who gets the spoils from the oil produced. Study slide 26 here to understand who gets what out of the field's daily production. https://wp-gulfkeystone-2020.s3.eu-west-2.amazonaws.com/media/2020/02/gkp-corporate-presentation-22-jan-2020-vfinal..pdf

And amend it to reflect a revised split of the WI in profit oil of, currently, 30% (declining to 15% as the R factor moves from 1 to 2) of 61.5% GKP, 18.5% MOL and 20% KRG.

That little chart, with the amendment above, has all you need to know except for the current level of the Cost Recovery Pool and the updated R factor. At the moment the CRP is high enough to have the maximum 40% of production be Cost Recovery (or 'Cost Oil'). The level of the CRP is only disclosed periodically. You can come up with your own estimate of its current level and forecasts of it by modeling it. IMO if oil holds at these levels the CRP will be normalised in the 4Q of this year at which point production swings more to Profit Oil as the Cost Recovery is "unused". We get less of PO than we do CO (which is only there to recover costs). The R factor is also only disclosed periodically but you can have a stab at modeling this also. It's likely rather close to 1 now.

Well you could look back at the accounts for accounting profit or, in my opinion, better look at the cash flow generated per barrel. Anyone who can estimate monthly receipts can figure this out with a few additional assumptions. If we assume $80 Brent, 55k bopd production, $2.4 a barrel opex, $4.2m annual direct Shaikan G&A, $15m of maintenance capex, $10m of corporate overhead and $10m of interest, an R factor less than one such that WI in profit oil is 30% of which we get 61.5% (aggressive given R will exceed 1 soon), I reckon the company produces a little over about $6 a barrel of cash flow to equity. If the WI in Profit Oil falls to 15% that number becomes closer to $2.67. But you should do your own analysis.

25% is far from horrendous. Your ex-div entry is 190-34=156. The 34p left the company and commensurately reduced its value. You're up 25% (or more) on the balance. Well done!

"80% of a 55k per day field?"

Unfortunately we don't have 80%

gain a sense of 'order of magnitude' value.

Goodnight!

You're welcome. Any questions, just ask. The foregoing is merely the application of understanding slide 26 here

https://wp-gulfkeystone-2020.s3.eu-west-2.amazonaws.com/media/2020/02/gkp-corporate-presentation-22-jan-2020-vfinal..pdf

adjusted for the fact that the KRG now has (albeit not fully documented) a WI in what's labelled in the chart as Contractor Income. The split is now 61.5% GKP, 18.5% MOL and 20% KRG.

If oil keeps on where it is now I believe the CRP will normalise at some point late next year (with the R factor likely shifting above 1 much earlier). I expect the company to continue to return to shareholders the cash it is recovering from historical capex/opex, ie the CRP, until it normalises to circa two-three months' (the invoicing payment period) opex/capex. Arrears will have been recovered by then also. If that excess capital has been paid out we're left with the present value of our expected Profit Oil cash flows less corporate overhead and other non-direct expenditure including financing costs as the value of the company. (Yes, opu will have more cash in his ISA but commensurately less in his GKP stock.) The good news for us and prospective buyers today is that little value, IMO, is embedded in the current stock price for our PO. (You should work out an estimate of the CRP, cash net of debt and arrears as of today and compare that with the current fully diluted market cap. Is it less or more? Then model what you think the present value of the PO less overhead cash flow stream is for a given oil price. Just pick, say, 55k average daily production.* You'll also have to assume an average WI share of PO knowing that it will, over time, slide from 30% to 15%. Compare that with the foregoing delta. Is 55k and your long term oil assumption priced in or not? What about if you assume production instantaneously doubles to 110k etc etc.)

* You can simplify to make the maths easy by assuming that cashflow stream continues in perpetuity and then apply PV = PMT/I where PV is the present value, PMT is the net cash flow each year and I is the discount rate. If the cash flows are net of the cost of any debt then you can discount at your required return for an equity investment of this type of risk. (For me that's quite high but maybe you're prepared to accept a lower return.) If you can model monthly receipts you're only a couple of steps from doing this modeling for the year and then layering corporate overhead etc. If, for example, your model churns out GKP making net cash flow of $90m a year (yes, 55k production, average 22.5% WI in PO, and $80 oil produces a figure of that magnitude) and you require a 15% return then the PV of that $90m per annum in perpetuity is $600m. With a FD share count of about 224 million and an exchange rate of, say, 1.35 to the pound that's £1.98 a share. Obviously modeling a static scenario in perpetuity is a huge simplification but it allows you to readily gain a sense of 'order of magnitu

I need to refine what I wrote below to be more precise: "the Contractor 'loses' 30% of it"

When the R factor is less than 1 the Working Interest share of PO is 30%. This WI is shared 61.5% GKP, 18.5% MOL and 20% KRG.

So the Contractor (GKP + MOL) opportunity cost of losing production from PO is 80% of 30%, ie 24%. As the 30% declines with a rising R factor the Contractor opportunity cost falls further. Less burden of investment but less share of profit oil from which to pay indirect costs and overhead albeit a smaller slice of, hopefully, a larger pie.

Not free.

Understand the PSC.

Compare the scenarios, with a normalised CRP, of what happens when new investment is incurred. When the CRP is normalised and investment is maintenance only, CO is small and almost all production is PO. CO, as we know, reimburses the Contractor for capex and opex ($2.4 per barrel plus direct Shaikan costs; $2.1m in 1H 2021). The amount of CO is limited by the PSC but if the 'base' level of production (in this case 55k) is high enough, CO can be large enough to cover quite a lot of capex and opex per annum. (I recommend you do this maths.) When the CRP is normalised (no longer recovering capex and opex incurred years ago) current capex and opex is returned via CO according to the payment terms (two months). It need only be funded by the Contractor for a couple of months. Debt facilities can manage that WC need. At an R factor less than 1, the Contractor gets 30% of PO. So when production is pushed from PO to CO the Contractor 'loses' 30% of it (its share of PO) but gains 100% because it gets 100% of CO. As the R factor rises the share of PO falls and the 'opportunity cost' of production being pushed from PO to CO falls. They guy that loses most is the guy with the large share of PO and they lose more as thee R factor rises. So they shoulder the larger share of the burden of investment in the hope of later getting even more PO.

As is always the case, our 'profit' is our share of PO (as CO merely recovers expenditure incurred) but under the above circumstances direct costs/investment expenditure is recovered quickly. Payback periods are short. And we get increased PO from the greater production. Our profits increase (assuming non direct costs are controlled).

Your question is exactly why there is an R factor...

(But it is important to realise that the bulk of receipts will still be CO which recovers expenditure of a few months prior and recycles that WC facility. The CO component of the receipt is not earnings and won't be available to pay out to shareholders via dividends or buybacks. The current situation is unique in that current receipts are recovering a very historical - although less and less historical by the day - expenditure. That capital can be returned and capital structure optimised... until the CRP is normalised. And I use the term normalised because the CRP is never fully depleted but will eventually normalise to the payment-period quantum of capex and opex.)

The company doesn't need to hoard cash to fund the next stage of the FDP (in whatever form it may take). It's not them that bare the burden of the capex. With oil at good levels, and a sufficient 'base' of production already achieved, the burden is borne by the KRG/MNR. If the oil price collapses they'll have ample reason to go-slow and not rush the additional capex.