Member Info for noelpbz

scottabeme - the known total HUR overheads to lift a barrel of oil is $35 - which HUR (Maris) have since said they are aiming to reduce in size. With Brent at $63 this will generate a nett profit per barrel of $28. Typical lift over 40- 45 days at 12100 per day will will produce around 500K barrels.
Nett profit circa $14M.

I'm told its year end "jiggery - pokkery" - so there - not related to offloads.

HUR claim $19M increase in net free cash since 30th November 2020 - $106M compared to $87M.

The December offload (stated at 12,700 bopd) at best could have been 395K - which at near $52 per barrel totals $20.54M - how does this nett $19M ? Typical nett operational costs are running at near $35/barrel suggesting an increase of $6.7M.

For information the oil production figures are :
Quarter 1 - 1.4m (RNS 8th JULY2020)
Quarter 2 - 1.3m (RNS 8th October2020)
Quarter 3 - 1.25M (RNS dated 8th October2020)
Quarter 4 - 1.17M (RNS dated 14th January2020)

Total 5.12M barrels.

PlantedBHA - Next tanker offload probably due 6th October - previous offload completed on the 29th August, so with the 5days* lost due to maintenance shut down, then running at 13500 bopd (mid 12800 to 14200 forecast) next offload should be near 450K barrels.

*( HUR statement : “A scheduled annual maintenance took place over five days in early September 2020, with production restarted on 8 September 2020” )

The production days between the July lift completion (28th) and the start of the August lift (28th) was 31 days. However RNS dated 6th August advised of a maintenance shut down which commenced on the 2nd of August - so possibly 4 days lost. Total production days then 27.

Knowledgeable contributors on this board have calculated that the Navion Oceania offload at Rotterdam after August lift was approx. 500,000 barrels - derived mainly from a change in draft at offload.

Putting these two numbers together gives a production rate at 18,500 barrels per day.

A possible reason for this increased volume above 17,000bod could be a reduced water cut from 7z.

Methinks Planted is on the right highway, or possibly motorway - Friday will reveal.

Figure of $102m comes from CMD presentation (27 April 2020) p46.

Balance from 2019 currently approx. $102m - plus any net income from sale of 2.7m barrels in the first half (forget July and August sales for now) - lets say conservatively nett at $12/barrel, so add $32m - total $134m !

OK Captain I take your point - - assuming we compare 18000 and 15300 bpd the marginal overhead at Aoka Mizu becomes $20 and the gross overhead becomes $30.60.

Assuming Brent averaging $43.50 then nett income per barrel of $12.90. - as you correctly point out.

Gross nett income to bottom line becomes $77m - still OK

HUR overheads and nett income.

When Lancaster was running at !8000bpd nett the marginal overhead at Aoka Mizu was $17 per barrel. Now running at 17000bpd increases that marginal overhead to $18 per barrel (simple arithmetic)

Using the same maths the gross over head becomes $27.50 per barrel.

Assuming Brent crude continues at average $43.50 then the nett return per barrel becomes $16 - which with annual production now at 6M barrels produces a gross nett income of $96m - straight to the bottom line. Happy days.

7z well - according to HUR CMD (4/20) conclusions have been drawn that that — “a 10m high permeability water bearing zone has been identified within an interpreted 40m producing interval in the 205/21a-7Z well”

Reading various messages on this board and elsewhere there seems to be an interpretation that this water bearing zone is in the early part of the horizontal beyond the casing.

Is my understanding correct ??

If this is correct then I have another question - what is the cost to re- enter and extend the casing - is it within $20 - $30M ?? If so, then is it not worth that cost to produce 10K barrels per day from this one well ??

NB. I note the use of ESP’s has also been ascribed on this board as to be suitable to reduce this water ingress - this to some extent also suggested by Schlumberger technical data. So maybe this decision is more financially beneficial than re-entry - to give a better return.

adoubleuk - thanks again for the explanation of detail of pigging. I'm happy now.

adouble - slift 's post has raised another issue in my understanding - how far does the pig go - does it enter the well head and actual casing ?

adoubleuk - many thanks for clear explanation - I'm learning slowly.

Slift - your assumptions are correct - further reading of CMD report shows footnote to "operating costs" as -;
Note 1. Cash operating costs are defined as statutory cost of sales, less non-cash depreciation charges and accounting movements in crude oil inventory, and include all FPSO lease payments.
2.Underlying profit excludes gains on the Convertible Bond embedded derivative.

Perhaps the suggestion to email HUR has merit. Good luck

Questions, as a NON oil person regarding the ESP’s :

1. where are the ESP’s actually located - are they at the Lancaster Manifold or directly at the well head or elsewhere ?

2. it has been said that there are two ESP”s (adoubleuk) installed per well (6 and 7z) - are they placed in series or in parallel ?

many thanks for any assistance.

Slift - regarding your excellent analysis of the overheads, the missing $30m from the overheads assessment may be due to depreciation and impairment as per the annual report - see notes 2.3 viz ;

Oil and gas assets – depreciation

Oil and gas properties are depreciated from the commencement of production on a unit-of-production basis. This is the ratio of oil and gas production in the period to the estimated reserves base, which is proved plus probable reserves (2P reserves), at the end of the period, plus the production in the period, on a field-by-field basis. Costs used in the unit-of-production calculation comprise the net carrying amount of capitalised costs, taking into account future development expenditures necessary to bring those reserves into production.

Impairment
An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of an oil and gas property may exceed its recoverable amount.

The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. The cash-generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash-generating unit where the cash inflows of each field are interdependent.
Any impairment identified is charged to the income statement. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any depreciation that would have been charged since the impairment.

Maverick - marginal cost was $17 at Aoka Mizu when production was 20K barrels/day - now at 12k barrels/day cost must be higher. Overall production cost was $26 per barrel taking into account full overheads inc. head office etc.

At AGM on 5th June 2019 the forecast for reserves was 100m barrels by H1 2020, 300+ barrels by 2021 and 800+ barrels by 2022.
Can we expect similar declarations AGM 3rd June 2020 ??

Excellent CMD - full of vital info. - pity about the camera position, too low. However best news was 'Initial material balance analysis indicates a minimum of half a billion in place barrels being 'seen' by the current wells'. No complaints.

Peterthesyreet - Hur will wish to hold SP down because of CB holders. They would wish to sell on open market (if they choose to release more shares) at going price rather than give them away at 40p. (Albeit at nil cost - but missing out on the income).