Member Info for londoner7

Dignity agued against a price cap, so they have their wish.

Average revenues have fallen over the last two years, so Dignity should be able to manage their revenues back up without flagging issues under the revised regime. Just don’t be greedy gents – 2018 revenues plus inflation should stay under the CMA radar.

So now we know.

On Tuesday someone from the CMA let slip insider info on the detail on the PDR issued today.

My quick read read is that "we are watching" assessing revenues and sales, but the implementation of price controls has been suspended due to the CMA deadline and issues around the Covid pandemic.

I guess Dignity will provide a fuller explanation of impact within a few days.

L3Trader, I also misunderstood your connection with MOL. Yes, S/C routed through Kittiwake. The only development suggested here has been Eagle, so I took your lack of news comment from MOL to be related to Eagle. On Kittiwake, with the S/C production improvement, AB had included this hub within his definition of a low-cost facility -the S/C rework more than doubled production from the hub - so I’d guess still time for further development if the POO plays ball.

I don’t know the detail of other opportunities around either Kittiwake or The Dons, but in their 2015 Capital markets Day Enquest referred to “exploration opportunities in the area” and even supplied a map (slide 20) of “Significant Prospectivity Around GKA”.

https://www.enquest.com/fileadmin/content/statements_reports_presentations_and_general_PDFs/151208CapitalMarketsDay.pdf

I’m assuming Enquest applications under the 32nd license support these comments.

Hi L3Trader, good to see you back firmly on message.

MOL Group has a share in Scolty/Crathes but I don’t think this extends to the Kittiwake hub – if you know otherwise please share your reference. If so, MOL would not have an interest in any planned works in relation to Kittwake, such as an Eagle tie back – something to watch but not high up on my list of expectations near term, but could be essential to an extension of the Kittwake hub a year or two out. I don’t think anything else in the portfolio helps Kittiwake but the 32nd licensing round might.

Catcher reserves have been upgraded based on exceptional production and due to an infill well due online soon – my interest here in through CNE. An S/C reserves upgrade is possible, but IMO would be small if it came – something else low on my list of expectations.

You ask, “should not ENQ take the long view and smooth out OPEX/bbl over several years when deciding whether to stop production?”
Perhaps they have taken the long view, however, the situation was dire last Spring, and these marginal fields may have been an option they couldn’t afford to carry – hence the decision to decom. There is still oil there – I’ll go with your 2P reduction which will probably be disclosed in next month’s interims – which is something the OGA will take into account in assessing the application to decom. There may yet be a twist, but I’d guess Enquest’s main criteria is the generation of FCF. At least I hope it is!

You say, “share of the Malaysia production will be higher this year because the POO is low, and the Tanjoram field is now history.”

Yes, Tanjoram is now history, and the return of $50m will more than cover the repayment of the Tanjoram loan, but how significant is the variation in Malaysian production with respect to POO?

A clear cut director's buy in Dignity is as rare as hen teeth, so best take note when they happen.

Hi hitman1a, I don’t see any new news, but your post prompted me to look back to an exchange here in June on hedging which followed a reported comment by IR that their hedging programme ended in Sept. I concluded that the IR comment referred to their $31 swap but didn’t extend to the $52-$70 hedging programme required under the terms of the Oz loan.
As of the latest update I see two hedging programmes in place, the $31 swap and the Oz related $52-$70 hedge.

$31 swap
I estimate that this hedging represents about one third of oil production April through to end Sept, or roughly all North Sea production excluding Kraken. While a $31 swap looked a panic response to the oil price turmoil last Spring, I recently posted a view that this action may have been prompted by terms under the credit facility. Above an oil price of $31 this hedged production represents an opportunity cost which will be reflected in a profit/loss line in the accounts (earlier hedge programmes have been positive so I don’t know which side of zero the final outcome will be).
At an oil price of $45 I estimate ‘cost’ of this swap at c$10m/ month through Aug and Sept, after a cost of c$8m/ month through Jun and July, and, on balance, flat through Apr and May.

I’m sure you’re not suggesting otherwise, but to be clear, Enquest are benefitting from a higher Brent price on the remaining two-thirds of production along with any Kraken and Malaysian price premiums.

Oz related $52-$70.
This hedge roughly covers the repayments, including interest, due under the Oz loan which is to be fully repaid within 5 years. To date, Enquest repayments are ahead of the curve, helped by a $16m repayment during the first two month of 2020.
In today’s price environment this requirement of the Oz loan contract is benefitting Enquest.

SVT working capital facility
Unrelated to hedging I recently read that this facility, $32m at last update, is repayable this year – shame as it’s their cheapest borrowing.
“On 1 December 2017, EnQuest NNS Limited entered into a £42.0 million revolving loan facility with a joint operator partner to fund the short-term working capital cash requirements on the acquisition of SVT and other interests. The facility is able to be drawn down against, in instalments, and accrues interest at 1.0% per annum plus GBP LIBOR. The facility is repayable three years from the initial availability of the facility.”

Breedon is a beneficiary of the OIL price crash

Breedon is a beneficiary of the price crash through lower transport and fuel costs and lower bitumen costs. Breedon attempt to negate bitumen pricing through various financial mechanisms but still benefit from any sustained decline.

Bitumen pricing dropped 40% through Mar/Apr against 2019 pricing, but stabilised through July/Aug 20% down on 2019 levels. Brent oil is a good benchmark for bitumen and seems to have stabilised at $45 with little prospect of any appreciable gain through 2021 above $50.

Transportation costs were a smaller % cost against H1 revenue, but there may be a number of factors playing out through lockdown that make any extrapolation risky.

Carbon pricing has been more volatile but has returned towards 2019 levels cEuro25/t, which was a stabilisation after the significant rises through 2018. Possible that traders have overplayed their hand against the pullback in industrial activity, so could come back. Like bitumen I'd guess Breedon attempt to hedge here too.

Pat said pricing had increased above inflation in H1. The June revenue number suggests good momentum into July.

Taken together H2 margins may hold or even beat 2019.

ronok, this Dashboard should give you the production figures you're after.

https://data-ogauthority.opendata.arcgis.com/pages/production

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.

I posted a comment on the CNE board about the SPA and its impact on CNE. It developed into a view on the Bressay development, which might interest some here.

CNE is in an interesting position following Enquest’s SPA agreement with Equinor on the Bressay development. An option in the development would be to use the Kraken FSPO. As a 29.5% partner in Kraken this would bring CNE into the equation.

No timelines provided but I expect an FDP to be submitted in 2021. It is possible that Enquest might have the option to double their stake in Bressay to c81% for an additional $15m paid to Equinor. At that stage CNE may be able to buy out Chrysaor’s 18.4% stake and top it to 29.5% for a similar sum. Equivalising their relevant stakes would ease the CapEx sums. Alternatively, CNE may choose to exit Kraken.

It’s difficult to estimate the ‘saving’ Kraken FPSO brings to the development. It is currently leased at c$160m p.a. (gross), but there is a buy option June 2024 c$200m (gross). A simplistic view (if it works over 12Km) would be to replicate the recent Worcester development, but that was $90m for two wells targeting 6MM bbls. The SPA points to 2C of 280MMbbls (gross) in Bressay, which suggests there may be a more cost effective alternative development plan, than simply adding drills and pipework as slots become available at Kraken.

I'm more aligned with chilting on his 50K top end working number for AK.

AK has the top sides capacity to process 80K of incoming oil, but I don't think that is the pinch point. We're talking heavy oil, and it requires high pressure heated water injected into the field to move it to the well bores. No engineer wants to over specify a design, so I guess there's a compromise between what can be termed the front end, injection and the associated energy demands, and the the back end, the processing of the incoming fluids.

I'd guess in their dreams Enquest hoped for 80K. They planned for the possibility.
The template target was 60K - the target assigned to the FPSO contractors.
In practice they are hitting peak daily c50K and averaging c40K over a good six month period.

Perhaps additional infrastructure can raise the combined front end efficiency but I doubt AK alone is capable of much more than what she's doing , unless the top sides kit can be upgraded.

The Kraken field development was not plug and play design, or a repeat of anything close to what had been done before. Faced with a similar problem - heavy oil at depth - Equinor went with a different solution on Mariner. I can't judge how well Mariner is performing but Equinor has turned to Enquest to operate Bressay - I take that to mean Enquest has a very large part in the say on development, but note the additional contingent on FDP risk. What does that mean?

Perhaps there is a route to a sole full development of Bressay, but the generosity of the terms suggests to me that Enquinor has decided that it requires, Enquest expertise, the AK, or a combination of both to get something out of a development Probably the latter. If so, then the FDP may be a partial development of Bressay, timed and perhaps expanded as the Kraken field declines and spare AK increases. Again I come back to the optionality that the alternative of organic development of Kraken offers - Western Flank and Maureen.

Equinor and Chrysaor may be thankful for any return they can get on their investment to date on the Bressay license.

Well done Therapist, you beat me to it. You've also highlighted the same key points. Here's my take:

The best net North Sea monthly oil production for Enquest since Sept 2019, when Crathes surged into the frame. The Scolty/Crathes combo is in decline but still supplying c4.5Kbopd. I suspect this combo will be c3Kbopd by year end.

Kraken had its 3rd best month at c42Kbopd, and that’s before the Worcester wells come on stream. I’d guess production efficiency is back over 90%, and I believe this is as good as can be expected from the current wells. Let’s see what Worcester adds in Q3.

Magnus interests me most as I see it as the key swing producer for Enquest over the next year. At c19Kbopd in May it maintained the April production number which included first oil from the two new wells, and I suspect a surge element, so I see maintaining the total production into May as encouraging. 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.
Enquest trading updates had covered the period up to the end of April so this update on May production is new data. I can only assume Malaysia production is holding up, if so then a same again North Sea production number for June (Kraken looks okay) could come out >67Kboepd in total for H1.

H2 includes maintenance – don’t underestimate the impact of around two weeks lost production. While S/C and other fields will struggle to hold their base H1 numbers and A/G now offline, I’m more optimistic on both Kraken and Magnus nudging their base H2 numbers a little higher (before maintenance impact).

I’d see an H2 number over 60Kboepd as a good result which would mean just beating top end guidance for the year. But we know things happen, and in oil production it isn’t normally good news. When the operations guy comes on duty and gets a status update, he’s hopeful nothing has failed and is least expecting news of a surge in production.

Good point Frac.

I was thinking along similar lines but note the timing. There's is a credit refinancing deadline of 15th Oct 2020, which would offer optionality on the Bond repayment dates. But this Bressay deal is expected to close sometime in Q4.

Does a prospective 2C number have value?

Yes, as laymen we focus on what we see and can relate too – a big FPSO and other surface infrastructure. But I’m reminded that in calls Enquest has commented on the sub-surface work at Kraken clearly with some pride – the longest gravel bed something or other, the first this, etc. But these comments are made to analysts who probably have no more understanding of geology than we do.

Within the ‘heavy oil bubble’ of geologists and engineers the truth will out. Enquest expertise in the industry may carry much more weight than we appreciate. Then again, I might be blowing smoke up their ….

I’m a numbers guy. At some point Enquest will present a project plan, it will cost us this $$$ and we’ll get out this $$$. I’ll add a bit to the first, knock a bit off the second, plug it into my spreadsheet and hey presto, make an investment decision. I’ll leave Enquest to do the Centipoises to dollar conversions.

Still no OGA updates. Wake up boys!

I fear I’ve already spent too long today considering this morning’s RNS. My near-term focus is on tomorrow’s OGA numbers particularly Magnus, which has become my recent interest. We’ll only get a single number bopd so not much to extrapolate the various forces I see in play, but hey ho! I’ll speculate anyway if only to myself.

But to close out my thoughts on today. I don’t see the news as worthy of any rerate today, but that isn’t to say, it doesn’t offer huge optionality a few years out at little upfront cost. To see the news as anything but positive seems strange to me.

My main reference is a link I posted earlier. April 2014, both Mariner and Kraken had been sanctioned and Bressay was close to an FID at $6-$7B CapEx. Gulp! I doubt that today either Mariner nor Kraken would be sanctioned, but Bressay is now getting a look. Why? I have no technical expertise (where are you ProdOpt?), but I believe Kraken is the decisive factor. The OGA remit is to maximise economic value for UK assets. They will see the merit in optimising existing assets although their focus may be more towards the Aberdeen oil service sector than Enquest shareholders. Pardon the pun, but I don’t give two hoots (mon) about the oil sector service workers. Besides, Sturgeon probably has them earmarked for green jobs on wind farms and solar panel sites, okay maybe not solar (it’s Scotland after all).

In 2014, every man and his dog, (maybe not L3Trader’s), was building out North Sea infrastructure, and $6-$7B was considered the going rate for Bressay. I’d guess it’s much cheaper today. I’m trying very hard not to present an FDP here, but I do see a two-piece infrastructure with Kraken a key component. I don’t see it going ahead without the Kraken FPSO, and while Enquest has strong rights to the FPSO long term, I see a bit of give and take with the other partners, otherwise how does the development work for them? Enquest has the option of developing Kraken organically, but without that development I see production at 50% current levels 3-4 years out (refer to the 2015 CMD). I come back to optionality.

In support of romaron’s earlier post, I see this ‘option’ as Enquest getting back to their strengths, which is why I invested in Enquest in the first place. I do see a differentiator. BA pilots and Ryanair pilots are each capable of getting me safely to where I want to go. But the Ryanair pilots don’t go home to a big house in Surrey. It is the new world.

The small talk on Bressay gas fuelling the Kraken FPSO struck me as a strong pointer. Without the Kracken FSPO I don’t see Bressay being developed anytime soon.

L3Trader, Jam!!!

At best I'm hopeful of Marmite, and I don't like Marmite. ;-)

romaron, I now have a picture in my mind of you waking in a cold sweat on "Test reference date" day fearing an RNS. SFA (arghh). SPA (phew), I hope you had your glasses on this morning. ;-)

Before querying your comment I took a look at the section in the prospectus. I adopt a 20/80 rule to focus on what matters most so didn't examine the detail but on a cursory look at what I interpreted as restrictive obligations on each 13 week period, it occurred to me that my earlier assessment of a panic response leading to a 4MM bbl hedge at $31, might have been wrong and was actually the result of an obligation on ENQ to ensure certain cashflow targets over the period.

Perhaps I was too harsh in my earlier assessment, in which case I'm sure there'll be considerable relief in ENQ finance when these SFA restrictions are lifted.