Member Info for londoner7

hitman1a, you say, 'Some people might think the 2h average realised price might be lower than 1H, and they might also think production might be lower in 2h'

I do, with one caveat, Scolty. I'm looking forward to the update on Scolty Sept production either from ENQ at the CMD or the OAG number early Dec.

In addition, H2 capex, opex and interest has been guided higher - I estimate $25m of H1 interest was deferred to H2. For these reasons I struggle to see how H2 FCF will be higher than H1 but I'd love to be wrong.

I expect the year end net debt number to be close to the number reported for end Oct, which is why I question HMNn's >$100m additional reduction in net debt.

romaron, no doubt Jim knew his stuff!

Fracking will not happen in the UK.
Cost of energy to extract energy ….
Shale production / well falls off rapidly
Shale equity holders will not make money

and some stuff he didn't see, 'Eagle Ford is the poster child'. Guess he didn't see the Permian coming.

My point is that you can be very smart and knowledgeable and still make duff investment predictions. It's a while since I saw the full video but as I recall Jim did not anticipate the volume of US shale production or its impact on world markets.

Hence I take current 'knowledgeable' forecasts on the demise of US shale with some skepticism. As an investor in conventional oil I hope for the best but plan for the worst.- or at least tune my spreadsheets accordingly. ;-)

Hi HMNN, you say, 'I don't expect fireworks for the 4 months ending October. My model is spitting out Net Debt of $1.460bn, but due to scewness in the Capex/Opex spending during maintenance season and Scolty/Crathes + PM8/Seligi I would be happy if we'd end up in the $1.5-1.525bn range. '

What are you referring to? ENQ guided on Capex and Opex, are you now expecting something different?

I haven't seen any material comment on PM8/Seligi. What are you referring to?

Working your numbers it appears you expect a >$100m ($1.5bn minus 1.399bn) reduction in net debt between end Oct and year end. Why do you expect debt reduction to accelerate over the final two months?

L3Trader, in answer to your questions on Magnus voidage I'll point you to pg170 of the RI document.

'EnQuest is planning to increase water injection capacity from the current 150 Mbwpd to about 200 Mbwpd by re-activating a de-aeration tower and water injection pumps during 2019. This will improve the voidage replacement and oil production from the field. EnQuest has not presented any reservoir studies that support the estimated incremental recovery of 2.6 MMBbl (Mid Case, no incremental is attributed in the Low Case). The forecast is based on an assumed reduced decline rate, resulting in an incremental forecast that increases with time. In reality, any benefits would be expected to be in the short to medium term, rather than in later field life. GCA has accepted, however, that there would be an overall reduction in field decline and that the estimated additional recovery should be achievable.'

In simple terms I interpret this as, increased water injection and improved voidage as GOOD, reduced water injection as BAD. 2.6Mbo over 11 years equates to 650 bopd, but if the water injection is expected to have a greater benefit in the short to medium term then then I'd guess the short term benefits would be >>650bopd. On this basis the current problems (to Oct minimum) with water injection should have (are having) a detrimental impact on production, so I was relieved by the Aug number. I don't know where this goes over the coming months but ENQ still intend to get both towers into operation in the medium term. As I said, I'd expect an update at the CMD.

On my Kraken number over 50K bopd across two offloads, I hope I got the message across that it surprises me so I wonder if my calculations are correct. Following MO's update on his 527K calculation, even a more conservative estimate around a 500K for NO and 450K for the possibly 'light' AS offload leads to 46.5Kbopd. Still very impressive and a record to date for Kraken. Again, I hope for an update at the CMD. It should be an interesting update albeit one tempered by news on Thistle, Heather and Magnus.

On the OZ loan, it isn't something I'm paying much attention to. I took an interest in it earlier in the year when I wanted to understand its operation. Now I treat it as another debt component reduced by FCF albeit a a slightly higher interest rate than the other loans.

Again, vendor loan payments 'come out in the wash' in my FCF calculations. The $100m loan on 75% Magnus is slightly different. Enquest expected it to be repaid by year end. I wonder how a reduction in Magnus production impacts this expectation.

One for the tanker nerds.

I understand and agree with MO’s comments on using draught to gauge production rates but I still see it as a useful check. For me the primary input is the turnaround between offloads and like most I use disconnect to disconnect because it is less affected by the loss of AIS data around hookup time. To date I’ve used a standard 500K offload irrespective of my draught calculation which worked April thro July but was 7% short on the Aug number. My conclusion is that loads 43 and 44 were 550K offloads – both spirit class tankers which I may have underestimated. I believe my estimates on the larger Navion Oceania are more accurate.

All seems reasonable until I consider the latest loads, 49 (AS) & 50 (NO). I too thought the AS load was light but the Aug data suggests a normal 500K offload. I’m inclined to go with 550K for the recent NO offload. Against the offload timings these numbers point to a 51.4Kbopd average over the two loads.

Those following this stuff know that is an exceptional number for Kraken. I have some doubts, but as an investor I hope that OAG or ENQ confirm these numbers over the coming months and perhaps at the CMD.

The question I ask myself is how such an improvement in Kraken production might come about. The OAG numbers indicate an improvement in water injection at Kraken and resultant an improvement in voidage. Perhaps that is helping to beat the >47K bopd max achieved in the Q2 well tests, and reported by Cairn in Sept.

L3Trader, you asked me about current status. I held off responding because I wanted to see the impact on the Aug production number first – I was cautious about the impact but I didn’t want to introduce unnecessarily alarmist comment. In the event I thought the 16K bopd oil number was a good result in spite of continuing issues with water injection. The OAG August number indicates only 16% of normal water injection. I understand the restrictions on water injection extended into at least Oct. With water production continuing at normal rates (speaking as a layman) I would expect voidage to become an issue but I know from the RI report that the Magnus wells are produced in a variety of ways so who knows, outside of Enquest, what the ongoing impact will be on oil production.
However, Enquest are below their stated goal of 200K bpd water injection on Magnus following the introduction of the 2nd tower so I’d expect an update at the CMD.

Interesting posts around the measure of gas volumes. I'm in the gbk47 camp, in that we each have our own measures to reach our forecasts and we clearly interpret the gas data differently - whatever works for you.

On shrinkage I apply it at the point I'm calculating cash flows and in spite of putting in a lot of time to determine gas numbers I found the net cash impact of gas sales to be minimal. However, the work wasn't wasted because I've found that adding my gas calculations to the OAG oil numbers gets me close enough to ENQ reported boepd numbers.

It's clear that adding OAG oil and gas numbers results in a much higher number than the ENQ reported number, so there are adjustments. Rightly or wrongly the conclusion I came to is 1) OAG subtract gas injection from gas produced (Magnus), 2) flared gas is counted by OAG but not ENQ, and 3) fuel gas/oil used at the field is not counted by ENQ but fuel gas/oil used further down the line e.g. terminals, is counted by ENQ as production but lost to sales (shrinkage).

For each field I determined a flared, fuel gas or exported gas volume number, which is now factored in my spreadsheet around the oil number, because I can only be bothered to enter the oil numbers from the OAG data. Less precise than entering the actual gas numbers but I've found the end result has been within a whisker of the ENQ number. As I recall I posted these factors a few months back.

For the record my calculation of net Magnus production for August (or my guesstimate of the ENQ number) is 18,157boepd, just over a number I saw attributed to Therapist of 17,662 boepd, and well below the OAG number of 20,225 boepd.

Hi HMHn, in an earlier 2019 forecast (around May?) you had free cash flow of $663m which would lead to year end net debt of $1,111m. Following your adjustments at the H1 report you had Enquest closing 2019 with $1,285m net debt.

Now your 2020 starting forecast appears to be $1,330m + $85m = $1,415m.

These are large revisions. What factors are driving these revisions?

You say, 'I sincerely believe my numbers to be correct'. As I recall you had similar strong beliefs in your original forecast, so I'd be interested to know why it should be different this time. Back testing is an important tool in forecasting.

While the speculation on this board on the likely impact of the incident at Thistle is understandable, the fact is that IR will have been fielding calls from their institutional investors wanting updates and clarification. That news is now in the market. Perhaps we'll get an RNS, but I believe the SP reaction is as good a guide as any to the impact on ENQ.

When I saw the news last night I thought there would be a more severe reaction. I'm happy there wasn't.

Hi L3Trader, My thinking at the time of writing was that Enquest put out a 2019 target of 63K-70K in light of all available knowledge at the time anticipating 'stuff happens' and I listed stuff that I'm aware has happened year to date. You say Dons occurred in Q1. If your point is that it has been fixed and doesn't impact H2 then I agree - stuff happens, some gets fixed easily, but some doesn't and more may occur in Q4. That's the oil business and I state it just to negate my (and others) early year optimism in the numbers when 70K plus production and $65 oil looked a reasonable outcome for 2019. I'm expecting lower production in H2 compared to H1, but the largest unknown (outside black swan events) is the positive impact of Scolty/Crathes. I'd expect a numbers update at the CMD. If not we only have to wait a week for the OAG data.

You ask, 'Are the water injection problems at Magnus something recent and related to the decrease in production in July?
Yes.

You go on to say, 'If so, I had not seen a reference to it.'
When the OAG data was published showing Magnus July oil production 0f 13K bopd I referred to a comment in the H1 trading statement and copied it to this board. My assessment was that it highlighted a problem on Magnus. No one here picked up. I dug deeper. The OAG data revealed a possible problem. I contacted IR and they confirmed my suspicions.

Sometimes sweating the detail gives you an edge - I just like to be informed.

AB knows more about the current status than anybody here and he's just bought at 18.5p. An 'expert' credit analysist has ENQ at $400m FCF for 2019 at 63K production and $60 oil.

No worries!

What's that, AB is growing a beard!

Santos have indicated a potential return to Dukas in 2021. Central is exploring options and opportunities to accelerate timing for the Dukas-1 well completion.

https://wcsecure.weblink.com.au/pdf/CTP/02161711.pdf

Should be interesting.

hitman1a, until I saw your post I hadn't attached too much significance to the 'Capital Market Day'. I was anticipating a trading update around that time. I now appreciate the difference.

I came aboard Enquest (cue piped whistles) in May with a 2019 target of 70K production (top end of guidance) and $65 oil. Both seemed realistic at the time, particularly as those production levels were being achieved inspite of dire early year Kraken production.

Six months on things don't look so rosy. The oil price is struggling to hold the bottom of my expectations for a $60-$70 range and early indications are that H2 production will come in well below the 68.5K H1 number. I expect full year production to hold within guidance 63K-70K but now understand why same again guidance was maintained at the Sept update when others expected a tightening in the upper range. Stuff happens, and in the oil industry it's usually bad: water injector problems on Dons; compressor issue on Heather; Kraken pipework repairs (albeit offset by postponed Q3 maintenance to 2020); water injection problems at Magnus; fire incident on Heather. We're three quarters into the year with one more to go.
On a positive note we await news on the Scolty/Crathes rework (if it is to 'replace' full year field declines with four months production then I have high expectations), and a higher oil price would float all boats. I don't want to read too much into the timing, but to romaron's point about a good news item at the CMD, moving the update to late Nov from early Dec means ENQ can update us on the Sept Scolty/Crathes production numbers before the OAG update 1st Dec.

At the interim stage my $200 FCF for the full year was at the bottom of published expectations on this board - one month on from the report I'm not inclined to raise it. The debt repayment profile is well known. I'm not as comfortable at $60 oil as some here. Also, I see 2020 production levels around 2019 levels and 2C resource has to be developed to maintain 2P numbers which means capex. I see the CMD as an opportunity for ENQ to get ahead of the game and that could be based on a restructuring of debt.

Just adding my dollop of speculation to the pot.

slipanchor, you say, 'You can juggle the ballast or the figures whatever way you like but a draught of 11.4 doesn't equate out to 450k barrels.'
I haven't seen the 450K number but I operate a filter so may have missed it. My estimate of circa 400K is based on the draught numbers posted on Marine Traffic. But it is just that, an estimate (subject to the warnings Pisces21 highlighted yesterday).

If you have additional insight into local swell conditions etc, you're free to include that in your own assessment.

DiveCentre, I won't quibble with your maths.

The HUR statement was 'over 1.6m' so based on your maths let's say over 372K for the 4th offload. I guess the 422K and 456K are from our friend in Rotterdam so let's what he says about this load.

Fred_Bloggs, I may be getting my FSPOs mixed up, but I had it in mind that the AM had a large scale gas compressor for gas export (22 MMscfd ) in place from its previous operation. This wasn't commissioned for the Lancaster field, but a new, smaller facility was put in place to supply the gas turbine generators. It's my understanding that it is the old plant that is being commissioned.

As I say, I'm going from memory so might be thinking of a different FSPO. Perhaps others posters can confirm.

slipanchor, the same vessel (NO) was used on the previous offload when it left with a draught of 11.2m. That offload didn't go to Rotterdam so we didn't get our independent, but the 1.6m number provided at the last update supported a 400K offload.

Pisces21, I agree with every thing you say, however I'm been using assessments based on draught on 3 fields I monitor and I have high confidence in the measure.

SG2, My assumptions assume the empty vessel arrives with full ballast and this is discharged as the oil cargo is loaded.

Based on draught I make it another circa 400K offload, and with the shorter offload cycle >15,500 bopd for the period.

HUR has guided to a lower 11,000 bopd in Q4 due to gas compressor commissioning so we should expect a drop in production over coming months, but the 2.8m bbls guided for 2019 production still points to a further two circa 400K offloads this year.

I said, 'But as I posted a month or so back gas export solutions are holding up a number of developments'. I now recall I posted that to a different board following a link posted here by Genghis15.

https://www.energyvoice.com/oilandgas/north-sea/207243/siccar-point-aims-to-keep-options-open-with-new-gas-line-west-of-shetland/#

feelinlucky, I don't have any particular insight into this. Your post intrigued me, but when I looked into it I found the legislation applied from Nov 2018 not the coming Nov as you post implied, which is why I posted the link for clarification.

The impact of the legislation applies at 'cease of production, allowing the buyer to utilise the sellers 'history' of tax losses against the decom costs, so more broadly I think it has more relevance to companies like Enquest who operated in the area of 'end of life assets'.

But to the specifics of HUR and Solan. Previous commentary from the PMO CEO has indicated that the Solan asset may play a role in HUR development of their assets, and the assets of other producers in the region, but as far as I know HUR hasn't mentioned it publicly. Does a link up have legs? A remit of the OAG is to maximise the value of North Sea assets through collaborations, so possibly. When I first looked at this several months back I noted that Solan doesn't have a gas export solution, so it didn't look like an obvious fit. But as I posted a month or so back gas export solutions are holding up a number of developments, which the OAG are looking into so there is a bigger picture at play in the WOS region.