Member Info for londoner7

Correction that's millions - '$15m' and $23m

hitman1a, you say, 'We know the annual EBITDA only changes $6m for every $1 movement'

Are you looking at old guidance?

In their finals presentation, slide 22, Enquest guidance for 2019 is, 'EBITDA increases c.$150 million at $70/bbl vs $60/bbl'. That's $15 for every $1 movement in the oil price. But my cash metric is even higher. In my assessments I'm at $23 / $1 oil.

e121, Retail and High-yield bonds can be extended to 2023. Enquest show 2023 repayment date in a presentation of the repayment profile.

The RI document has this, 'The Company has the option to extend the maturity date of both notes to 15 April 2023.'

GabsterX, you're right to highlight the guidance comments. What they have done is change the guidance to a reference to the pre-exceptions number.

Since the July update they have added another £10m of exceptions which has reduced the post exception number below the July guidance.

'In addition, the exceptional charge included £6.7m against another legacy contract and £4.6m in respect of the restructure completed within the Construction business which has simplified the business and management structure'

e121, while reading the posts between you and Pelle I was reminded that Oct 2020 is a significant date. I couldn't remember why but just found it.
' In addition, the maturity of the Retail Notes will be automatically extended to 15 October 2023 if the SFA is not repaid or refinanced in full prior to 15 October 2020;'

On the OZ loan I suspect ENQ have little control over repayments unless the lender agrees to a change in terms. But sufficient revenues from the 15% Kraken ring fenced stake ahead of amortisation would help. It hasn't happened so far judging by the capitalised interest charge but that's probably due to the DC4 capex. Repayments in H2 should be better.

e121, my interpretation of page 276 (RI prospectus) is that the RCG ceiling drops by $120m 1st April 2020. It drops $100m in the current period to 1st Oct 2019.

My reading of point F) is that it refers to the capitalised interest on the Bonds (and perhaps on the RCF). This would make sense as at the time of writing these conditions the lenders wouldn't know how often the <$65 oil PIK event had been triggered. It represents a large relief to paying off the RCF so I'd guess they would want this cleared too.

This one is interesting, '(G) at least 10 business days before the date on which the distribution is made or paid, the
Company confirms to the SFA Lenders that all the above conditions are, or will be,
satisfied on the date on which the distribution is made or paid.'

I'll look out for any unusual share price activity 2 weeks ahead of interims and finals.

romaron, I have a similar level of investment in Cairn to my holding here so I follow their activities. I can't judge the merits or justification for their write down of Kraken reserves but along with the write off on the India asset (or should I say ex-India asset) I thought it was a straightforward and successful attempt to reset the CNE share price lower ahead of their long term bonus awards. I have more confidence here that AB's interests are aligned with shareholders.

As to any similarity in the recent performance of the share price I doubt it has any relationship to their common interest in Kraken. At its heart CNE is an explorer, very different from ENQ and why I view it as a very different investment. Its share price performance over the coming year will have more to do with the drill bit and the sanction of SNE (and the tax dispute for the punters) than how well Kraken performs.

But any ENQ investor should take note of CNE updates in relation to Kraken. They provide an alternative and sometimes more detailed view than that given by ENQ.

They provided an early heads up on the Western Flank development in 2020, although Enquest as operator and majority holder are the primary movers. Yesterday they stated that the development will be producing oil in 2020 H2. The information on the total Kraken well capacity of >47,000 bop post DC4 is a useful nugget. Their Kraken Capex expenditures are also informative with respect to the timing of Enquest's declarations. While the Western Flank development will increase their Kraken reserves I didn't get any sense that they are close to unwinding their earlier revision.

I fear an image that has formed in my mind of you in flares and Cuban heals may last the day!

Good production and financials but this is an explorer and there has been little to shout about wrt the drill bit for a long time.

I sense the focus is now turning towards the more promising drill programmes over the next 3-4 months, Chimera and Mexico. I also sensed that analysts were sceptical of SNE sanction this year with < 4months remaining - CNE remained firm in their expectations. I'm not here for the Indian tribunal case - nice if it happens but - it was interesting to hear that an award could be made with little to no notice.

It appears Cairn has woken from a slumber!

In a previous post I overstated the PIK impact so I've taken a more detailed look.

$960m on the bonds (retail and high-yield) is subject to the ‘$65 oil’ PIK assessment. A reference to PIK on the RCF made me think that the RCF was also subject to the assessment but having looked at the detail I see that PIK was a ‘penalty’ for exceeding a $890m RCF threshold. The RCF PIK amounts to $15.1m and accrues a capitalized interest of 9% (roughly additional $1.5m p.a.) payable at termination of the RCF.

Fair to say, PIK on the RCF isn’t a concern. However, PIK on the bonds is worth a look.

Bond interest payment dates are split and semi-annual, so there are four interest payments per year each with a $65 oil assessment as a condition of cash payment. If oil is below the $65 average threshold over the proceeding 6-month period then a PIK is enacted. The next assessment date is 15th Sept (High-yield, interest due $26m), followed by 15th Jan 2020 (Retail, interest due $8m). It’s marginal on the 15th Sept assessment, expect confirmation around 2nd Oct.

The good news is that the 9% PIK interest penalty only applied to the RCF. There is no additional interest charge on a Bond PIK. The capitalized interest rolls up at 7% until the bond matures. Assuming one PIK event on each bond type, with $34m interest forgone, and therefore available to pay down the RCF, adds approximately $45m to Bond debt ($34m plus $11m interest rolled up over four years).

Therefore, as a 2020 delta I’m going to attribute an $11m cost (against FCF or additional to net debt – whichever metric you prefer) for each pair of PIKs enacted.

While this is a useful safety valve in meeting the next RCF repayment ($120m due Apr 2020) Enquest doesn’t have the option to pay the interest in cash if a PIK is enacted. To romaron’s point about credit market sentiment, creditor’s would look on Enquest more favorably if they demonstrated their ability to repay the RCF without the benefit of a PIK.

Michael, you say, 'some healthy "opposition" i.e. strong voicing of alternative opinions at the board level can only be productive.' I agree but how do you know that isn't the case.

I'm an experienced investor with my finger in many pies. I see challenges, risks and opportunity in my investment in Enquest. Following the recent interim update/webcast I was very clear on AB's vision over the next 2-5 years and was happy with what I heard. But it isn't for me to influence your investment decisions.

One market concern is the negative mood music coming from BP in relation to their review of exports to SVT. This news may lend support to SVT.

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

My thanks to Genghus15 on the HUR board for the link

If Lincoln is successful, as it appears, then there are two clear positive outcomes. 1) additional oil tied back to the FSPO, and 2) the Spirit partnership and GWA development ongoing - I recall Dr T saying that the 500M at Lincoln would maintain the relationship. But to my mind this suggests to me that the 3rd well is still key in getting full development of GWA back on track, with the full $250m carry. So any announcement of success will be great for the share price but perhaps we need success on the 3rd drill to get us back to where we were - admittedly with a higher level of de-risking to be added.

Pelle, you say, 'But why you have PIK as a negative post?'

You raise a very good point, and with respect to ability to repay the RCF your assessment is the correct one. I'd missed this component until a poster raised it a month or two back so I wanted to capture it as a line item in my sheet. In the long term I view it as a negative event in that an extra $32m would be added to debt if oil averaged below $65 for the next two six month periods.

But you are right to point out that if a PIK event occurs it enhances Enquest's ability to repay the RCF. Now you've drawn it to my attention I realise that it is a very significant safety valve in the lead up to the $120m repayment due April 2020. If one PIK event occurs before then it saves roughly ((7%*$1600)/2) = $56m in interest payments - a big chuck of the $120m repayment. Clearly, a key component of Enquest's repayment strategy when the terms were arranged. Of course from the creditor's point of view it's a way of keeping the goat alive while they bleed it.

Thanks.

Hi Pelle, I smiled at our matching Magnus 3-4K number. Let's hope we're right. But I want to correct an earlier comment you made in relation to my FCF post.

You said, 'Squif, Londoner estimated another 140 mill debt reduction this year.'

No I don't. My post was incomplete in that I didn't identify a number for full year 2019, but referred back to a previous post.

My original expectation was a reduction of net debt in 2019 of £194m. I've since made many corrections to line items but my estimate is still <$200m. With H1 at $136m, I'm expecting <$64 in H2. At best, I'm expecting same again production volumes, but there are headwinds: lower oil price (currently), higher H2 weighting on Capex and Opex, higher BP Magus payments. Whatever the final outcome for 2019 will be I think the 'delta' in line items for 2020 is easier to predict. The total I have as $143m. To be clear that means (<200+143) = <$343m for 2020. Obviously the big unknow and uncontrollable item is the oil price and the biggest controllable item is Capex. Some investors, perhaps you included, might think $343m in 2020 an easy beat. I don't but it coincidentally matches the rate of cash generation needed to overcome the scheduled RCF repayments to Oct 2021.

If achieved Enquest will be sitting very pretty in 2021, assuming 2P reserve levels can be held above 200M. That's my run rate target over the next couple of years. Anything better is the 'cherry on the top' but I see downside risk too - that's a column I have on the other side of my spreadsheet.

We refer to free cash flows. In Enquest's case they are not free. They must go towards the repayment of scheduled debt ($120m due April 2020) and from recent commentary I'm sure that Enquest management is laser focused on that objective.

Another Magnus type deal might appear, but in it's absence AB is clearly focused on managing the scheduled repayments and converting 2C resource as and when the oil price and cash reserves allow. The sanction of the Karaken Western Flank is a positive cash flow indicator.

Hi L3Trader, yesterday I passed on your 14:59 post because it looked detailed and I had other plans for the afternoon. But looking at it this morning I see the two main points have been addressed.

BP provision increase - e121 covered this and I agree with his explanation.

The unrealised hedge charge - you'll have seen the discussion I had with e121 on this topic. I've nothing else to add except looking back at your earlier posts (I've been out of the loop a few days) I notice that like e121 you also refer the possibility of unreported hedging into 2020. You've both been in Enquest much longer than me so will have better knowledge of their hedging history. If this is true then I understand your concern. It's a simple question to address to IR - one I'll leave you guys to fight over.

Other bits:

Discrepancy in how the Oz loan is presented. I agree it's odd. Is it a fee, is it capitalised interest, is it both. I suspect the later. Basically I see it as another $3m cash charge over the cost of repaying the loan and interest. Perhaps it's due to failing to meet the 'run rate' for paying off the loan in 5 years. I'm speculating now. Without the Kraken Capex charge in H2 more should be paid off the Oz loan so I'll wait to see the full year 'fee', before adding another line item charge to my spreadsheet. (Fortunately Excel permits over 64,000 rows).

You touched on production costs earlier. I've kind of given up on the headline number as I think there's some dodgy reclassification of charges going on. IMO lease costs ($5/bbl) should be at least referenced in the headline number. I'm also suspicious of the change in the handling of 3rd party gas costs, but within the next year or two I believe this will drop out as existing contracts expire. Besides a quick sum suggest it isn't a biggie. Gas 7% 68,500 = 867K boepd in H1. Gas revenue $70m, other costs $50m, net $20m. Equates to $23 revenue boe. Low but nothing to get sparked up about.

On costs Enquest revised down to $550m full year (after removing the 3rd party gas element), with $250m in H1 leaves $300m for H2. They put this weighting down to greater maintenance in H2 (specifically Q3). I think at best H2 production will match H1, so I get H2 production cost per barrel (Enquest method) of (300/250)*$20= $24. $22 averaged over the full year.

L3Trader, there's lots to digest from your post, but the sun is shinning so I'm off out to enjoy it. Get back to you later or tomorrow.

On your 'Magnus Contingent' query. I agree with e121's explanation. Essentially, and perversely, I saw the increase as a good news item.

Hi e121, I'm impressed with your knowledge of the detail of these hedges. I've read through your post a couple of times and happy to accept your calculation. To sum up I think you have a $7m mark to market 'loss' at 30th June 2019.

But I think you have missed the gist of my post. First, there is no 'loss' or 'gain' until the hedges are realised. We are talking here about unrealised hedges. Don't you need to do the same calculation for the unrealised hedge position at 31st Dec 2018?

Then look at the difference between those calculations. It may be that your Dec calculation says there is no 'loss' because the oil price is within the collar.

I maintain that a layman's interpretation of the valuation of the these hedges is that they had a greater unrealised value in Dec when oil was priced below $55 than June when oil was priced at $65. And it is the difference that is referenced by the $43m number as a 'fair value remeasurement'.

If you get a different interpretation from IR then fine I'll accept it, but in the meantime I'm comfortable with my understanding. And to repeat something we are in agreement on, these are non cash items.

Best.

Hi Pelle, I liked it in the sense that there were no surprises in the numbers and good clarification on operational matters, although that part did include some surprises. (Just to add, I thought L3Trader posted an excellent summary of his expectations the evening before the update)

On the numbers, when I make adjustments for the timing of Capex, Opex and BP obligation payments the net debt number is where I expected it. My expectations for the full year are only slightly lower due the low 60s rather than mid 60s I expect for the oil price in H2, partly offset by my better understanding of the financials since my initial estimation a few months back. (Thanks to the posters here who helped in my better understanding).

Operationally much of the news was good. Unforeseen problems are part of the industry but good to see some explanations behind some shortfalls, Heather (now fixed), Dons June production impacted by Dunlin which is now operational, and an unquantified improvement in production following the Scotly pipework completion (albeit it still to be paid for in H2).

I'm less certain/happy about the Kraken maintenance news. Good to know the poor numbers for July and August can be pinned to something (pipework) and use was made of these downtimes. But surprised that they now expect to delay the significant 3 week maintenance window expected this month to next year. Albeit with a minimal shutdown of each train for 5-6 days. Worth adding they have the ability to direct the best producing fields to the operating train during these activities so better than 50% is achievable. I'm wondering if a large intrusive fix was ever in the plan or if it has been postponed to next year. Either way my expectations for Kraken are now 80-85% PE equating to 40K-43K gross, with greatest risk to the downside. Cairn's update on Tuesday may have more to add.

Subsurface the Kraken field in on plateau. Cairn gave a heads up that a Western development was likely in 2020. Enquest as operator (and tightest on cash) has now confirmed its sanction. I've no doubt this development is necessary to maintain plateau (or close to) through the end of 2020. I'll be interested in the forecast for Kraken production in 2020 and very surprised in the top number is above 40K gross.

Given the update I think we can now estimate CapEx for 2020. Here are my numbers:
$50m NS licensing requirements (the minimal level excluding drills)
$40m Kraken (Enquest share - might get clarification on this from Cairn Tuesday)
$20m Magnus
$20m Malaysia
-----------------------
Total $130m, which I'm rounding up to $150m guidance

These are now my incremental changes to cash flow in 2020
FSPO/rent leases 0
Magnus 25% vendor 34
Magnus 75% vendor 0
BP 50% on 75% -50
CapEx 125
Interest 16
Admin 0
Working Capital 50
PIK @ <$65 -32
Prod vol 67K 0
Oil price $63 0
-----------------------
Total 'additional to 2019' cash flows $143m

e121, you say, 'Yes, analysts didn't ask about the mark to market hedge losses. I'm still hoping that L3 can break the ice and write/talk to IR. ;-). Remember that these are only mark to market 'losses', but it is needed though.'

It seems to me you've answered your own question.

On Dec 31st 2018 unrealised hedges were marked to market. At the time the oil price was below $55. As I recall the hedge pricing was around $66, so they had a significant value.

Six months on some of those hedges have been realised for a 'realised' profit of $7m. The remaining 'unrealised' hedges, which might include some new ones, are marked to market at the June 30th 2019 oil price of around $65. Clearly, with the hedges at $66 then the value of the remaining hedges is significantly less that it was 31st Dec 2018. My understanding is that it is this difference that is represented by the 'fair value remeasurement' of $43m.

As you say, a non cash component.

At the moment with the oil price at $61, the value of these unrealised hedges has increased since the 30th June.