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L3, Let’s resume dividend talk at 55+ oil
Londoner7,
Thank you for your comprehensive response. Your outstanding observation, data interpretation and investigation skills are
much appreciated.
Scolty/Crathes: My suspition is that the 12MMbbls have been revised upwards, but neither partner (Enq&MOL) has explcitly stated it, unless I missed something. Thus my interest in the profuction figures because the depletion rate will surely be below 40% y-on-y. The reference you make to Eagle leads me to believe that it might go ahead by the end of 2021 because of the synergies it brings to the Kittiwake hub, by extending its life.
Magnus: Thank you for adding to your previous statements.
I am still expecting the half-yearly payment of the 75% vendor loan to have gone ahead, despite the low POO b/w March and June. But, I am not counting on much cash have been sent to BP as part of the 50/50 cash sharing agreement. And, I am quite keen on such repayment being made at a fast pace to enhance the BSheet.
Kraken: I am a bit puzzled how the current levels of production (which will decline, but are still good) plus Worcester, and
in the future, the Maureen sands will fit with Bressay production. As you and Chilting have mentioned AK probably on average cannot handle more than 40/45Kbopd per day. If so, I would expect the natural decline from the wells in production at the moment to be compensated by the oil from he Worcester/Maureen sands in the future (these have plenty of 2C reserves). So, there would be no space for the Bressay oil for 2/3 years.
POO: With epiphany121 on holiday we have not had any comments on rig count and US Oil companies results. I have read some of the recent earnings transcripts, and as usual I see them still talking too much about growing production if the poo goes up. One has to wonder if elasticity of production wrt price will be very similar in the current upswing to that in the last one. This would not be good news. We shall see, but I am planning to use $47.5/bbl for August in my calculations.
Modestus,:
Goehring & Rozencwajg are some of the very best in their business. But while their neural network models can be good
at capturing shale production, they, like anyone else, has no idea in what mood MBS wakes up everyday. And, that as we have seen can in the short term bring pain to the E&P oil companies, as we saw. Going forward, a lot of oil can come into the market at some point, e.g., from Libya, Iran, Venezuela, etc. The world is awash with "potential" medium-term spare capacity, and that is will keep a ceiling on the POO. As Londoner7 wrote a few years ago every man and his dog believed in the sustainability of high oil prices in the years ahead, but that is no longer the case. Notwithstanding this, I still see the POO returning to levels above $55.
GLA
L3Trader,
Dunlin Bypass – Thistle and Heather. You ask, “I am puzzled by this because money was spent on the Dunlin bypass to service these fields (does it service any others?). Why would that happen if the netbacks per bll were negligible in an environment with $60/bbl oil? How did you get to your conclusion?”
This might help:
https://www.ogauthority.co.uk/media/6087/cross-jv-collaboration-dunlin-bypass-002.pdf
Heather wasn’t routed through Dunlin. The affected fields are Thistle and Dons. The Dons is still operational. The Dunlin Bypass project was sanctioned in 2018 Q3 when oil was $70-$80.
As you know Enquest doesn’t routinely split out the operating costs (and by implication the netback rates) for individual fields. But it doesn’t take much effort to figure out the numbers for Magnus, Malaysia and Kraken by other routes, e.g. the RI prospectus and partner updates. These fields provide the bulk of Enquest’s production, so historic and target operating cost, point to significantly higher costs on the smaller fields.
I don’t know the operating costs for Thistle hub but I don’t think I’d be far out on $35 during 2019 H1. At $60 oil that’s a $25 netback. In 2019 H1 Thistle hub production average 5.9Kbopd, worth $4.5m per month to cash flow. In the 4-month period up to the shutdown production average was 3.6Kbopd. That equates to a unit cost of (5.9/3.6)*35 = $57. At $60 oil netback is $3, and production worth $0.3m per month to cash flow.
There was a shutdown and you can quibble about fixed/variable costs but that calculation essentially supports my comment about negligible netbacks in the period leading up to the field shutdowns, meaning their impact post shutdown on cash flow was also negligible.
On Magnus. “I had not read anything about additional water injection capacity. Was this in an update?”
No. Put it down to good observation skills, data interpretation and investigation. Let’s see if it gets a mention in next month’s update.
Scolty/Crathes. You say, “My understanding was that the 2P reserves were 12MMbbls. Since 7.2MMbbls have been produced, less than 5MMbbls left. Unless the 2P reserves were increased. I cannot find a reference to this. Have you seen any revised figures on the reserves?”
When S/C came back on-line last year you posted the 12MM bbls 2P reserves number pointing out that the production volume at that time wasn’t sustainable. I’ve no reason to query your reserves number, or reason to believe that the new pipework would prompt a revision to reserves. Without going into detail, my understanding is that the new pipework implementation corrects an earlier failing. Using your numbers, at current production, the reserves will be exhausted by the end of next year. Typical production profiles point to a steady decline over a period, i.e. there will be a long-tail production profile extending past the end of next year.
I would guess that Enquest has a forecast of production declines for Kittiwake hub (including S/C) which shows the economic viability of the hub against various scenarios. S/C has extended the hub’s viability. Eagle is the next option for extension, planned for 2021, but has been suspended. The fate of Eagle, and by extension the Kittiwake hub, comes down to the oil price.
Dunlin Bypass to follow.
OGA: Therapist, thank you for the updated data. Could you please share your lovely graphs and excel spreadsheets with traffic colors?Thank you.
Londoner7, your comments on Magnus's production are key to my views on the accounts. I was wondering if you could elaborate further. As per the latest ENQ's production forecast Magnus was supposed to average 18Kbopd this year. You write "Enquest reported gas compressor problems through April so there may be more to come from a fix, and additional water injection capacity expected in the summer." I had not read anything about additional water injection capacity. Was this in an update? Excellent production from Kraken, but VFLSO prices were low at the time. (Imagine what the May production would do the Excel spreadsheet if AB was not a gambler and had hedged Q2 when the poo was in the $60s in Jan/early Feb...) It pains me to see ENQ selling its 1P reserves at the low May / $31/bbl prices.
Bressay: Thank you to Hitman1a, Londoner7, gkb47 and several others for all the information you posted on this oilfield and ideas on how to
develop it further. I am pretty sure the deal with Equinor must have been underway before the pandemic hit. It is a good deal, but we have to bear in mind that it is a challenging project. The field has not been developed for over 40 years. It is good to add those 2P reserves, but the market does not give a toss about 2P reserves at the moment, given the term structure of the oil prices (poo in 2025 still below $50). At $60 poo, that would be a different story. I hope CNE is brought into the project.
Accounts: Londoner7, you say Scolty/Crathes's production might decline henceforth. My understanding was that the 2P reserves were 12MMbbls. Since 7.2MMbbls have been produced, less than 5MMbbls left. Unless the 2P reserves were increased. I cannot find a reference to this. Have you seen any revised figures on the reserves?
Another one for you. You wrote; "My conclusion was that the shutdowns at Thistle and Heather had limited cash impacts because they had marginal netbacks to begin with. They were not operating well before the failures which forced shutdown." I believe you, but I am puzzled by this because money was spent on the Dunlin bypass to service these fields (does it service any others?). Why would that happen if the netbacks per bll were negligible in an environment with $60/bbl oil? How did you get to your conclusion? If indeed the OPEX of thase 2 fields was that high, that would have been another reason to hedge their production at high prices well into the future. Why? Because a drop in the poo would cover the losses and allow to keep them going (of course you can decouple the derivatives from oil fields, but they provide "insurance for short term losses" which buys option value if the poo goes up.
Finally, for Pelle: No time on the spike mat allowed!
GLA
p.s.: Londoner7: "Build it, and Marmite will come."