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"The prospect of significant additional gas being produced has been under discussion with GOG and third parties for some time." Yes that was implied from Tullow's messaging but how is that going to be achievable? It's raw gas basically with minimal treatment on the FPSO and therefore needs to go through a GNPC gas processing plant (GPP) onshore to get the gas into sellable form. Since the GPP has a capacity of about 125 mmscfd and gross gas export is currently about 100 mmscfd from the FPSO where is the scope for "significant" additional gas volumes? It will take 2 yrs to build a GPP II if it were ever sanctioned. As usual we need more info, hard info from Tullow. The additional gas may be a long way off?, or may not even happen? given Kosmos have already signalled TEN will have to compete for capital against their other developments.

Anton, well its a lot less than most on here hoped for! As for guidance. Kosmos tend to stick to the operator's script. So they will wait for Tullow to revise guidance should that happen.

Simplistically I was expecting kind of (77+77+70)/3 = 74.7 for 1Q from loading intervals. We got 72.3K production. So maybe a bit came out of ullage in 1Q? And maybe a bit is going back into ullage now? But overall the production numbers are very disappointing.

@RD3 My conservative to the downside analysis of tanker loading intervals suggested Jan and Feb stable at or below 78K with a fall off the the low 70's March producing days before shutdown. But reality was even worse. Post shut down we appear to be 60K to 65K for the producing days unless some of that has gone into ullage (600K spare).

@RD3 TLW/KOS and the former CEO Dhir thought TEN was capable of producing at up to 80Kboepd. Reality today 17K. That is partly due to increasing GOR now 60% but also as the seismic model wasn't backed up by drilling results which resulted in a large reserves downgrade. GOR on Jubilee is fairly stable at 30% to 31% but production performance continually disappoints against management expectations. The current messaging is that the new 4D will reveal where the bypassed oil is (assuming its there). But that remains to be seen.

It's also possible the 4D could also result in another reserves down grade! They don't know yet. One thing we do know is based on quite old 3D Tullow's understanding of the field is sub-optimal.

(72,285 BOPD was 1Q)

Anton - Other than the $40m + $40m Kenya is an irrelevance at the moment. The only story in town is falling Jubilee production. Net out the shutdown down time and you get an adjusted 72,285 BOPD which is even less than I was predicting! And it's getting worse. Tanker loadings appear to suggest we are closer to 60K bopd than 70K bopd since production resumed. Couple that with the OP...... How can they refinance?

Rd3,

Kenya is an irrelevant destruction at the moment. Would you be numbers or even worse when I was

Anton $25 Kenya was based on the assumption of 1bn barrels reserves, or about double actual reserves.

$3/mcf. But Ghana don't pay it as over $50m in arrears. ENI are owed $1bn of gas 'sales'.

Last line should read "if the production profile of the original 80K bopd development as postulated is anything to go by."

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Block 13T - The Government of Kenya, either itself or through a nominee (including the National Oil Company of Kenya), has a participation/back-in right of up to 22.5% during exploration (carried by the Contractor until such time as the government elects to convert its participating interest to a full working interest in accordance with the 13T PSC then the parties shall agree to make the necessary adjustments to the 13T PSC, observing the principle of the mutual economic benefits of the parties) and development (to be funded by the Government of Kenya). The Contractor is entitled to recover its petroleum costs (i.e., costs and expenditures incurred by the Contractor in exploration, development and production) up to an annual cap of 65% of all crude oil produced and saved from the development area(s) in the applicable fiscal year. Capital expenditure incurred in a development area is recoverable at a rate of 20% per annum. Following cost recovery, the remainder of production is then shared between the Government of Kenya and the Contractor based on percentage splits determined by reference to the average daily production (with the Government of Kenya percentage share increasing at higher production rates and the Contractor recovering between 50% and 25% of total production.

If the answer is more than 3 yrs decline will set in by then so production will likely be well under 100K bopd if the production profile of the original 80K bopd as postulated is anything to go by.

MarcelKrell a few points to consider. (1) It would be useful to know the production profile of Kenya. Whilst 130K(?) bopd is the nominal capacity of the development - plateau production will likely be 90% of that. (2) How many years will it take the contractor(s) to recover costs through Cost Recovery Oil? I'm not clever enough to do the calcs but the following inputs will help you.

Block 10BB - The Government of Kenya has a participation/back-in right of up to a 20% participating interest during exploration (where such interest is carried by the Contractor) and development (where costs applicable to such interest will be funded by the Government of Kenya). The Contractor is entitled to recover its petroleum costs (i.e., costs and expenditures incurred by the Contractor in exploration, development and production) up to an annual cap of 55% of all crude oil produced and saved from the development area(s) in the applicable fiscal year. Capital expenditure incurred in a development area is recoverable at a rate of 20% per annum. Following cost recovery, the remainder of production is then shared between the Government of Kenya and the Contractor based on percentage splits determined by reference to the average daily production (with the Government of Kenya percentage share increasing at higher production rates and the Contractor receiving between 45% and 22% of total production). Where the value of crude oil exceeds $50/bbl (calculated on certain FOB delivery terms), the Contractor is required to pay the Government of Kenya a “Second Tier Amount.” Such amount is calculated in accordance with a formula based on the value of the crude oil and the Contractor’s share of profit oil.

Seplat produce 130K boepd and were only asking for $650m. Tullow OTOH.......

"So Noble could find 5,000-10,000 bopd of light oil per production well in the Jubilee field with two wells potentially adding 10,000-20,000 bopd gross." Using the same methodology the previous 21 wells should have added between 105,000 bopd to 210,000 bopd. Clearly that didn't happen.

Gogadget, Maybe factor in that the previous tanker 'Habshan' finished loading on 21/Mar, or 5 days before shutdown. Putting it another way there was a 32 day interval between these two shipments. The next 'Agios Fanourios 1' will apparently arrive 06:00 5/May which if true would give a 14 day interval after loading (it may arrive early/late/not at all as things change).

Gabon: "Effective date for the Transaction is 1 January 2025." which usually means the final consideration received for the deal at closing will be adjusted to take into account FCF etc between effective and closing dates.

The 50K - 55K includes 6K of gas. Meaning it's 44K - 49K for oil which included Gabon.

So if you incorporate KOS's splits you get something like this for mid-range

JUB 28,455 TEN 8,774 GAB 9,500 CDI 500 total 47,230 BOPD (not including the gas!)