Member Info for epiphany121

Lol...you talking about the troll. I see at least 10 or 15 filtered messages in the last hour - Wow...that must be a bleeding record..;-)

Yes, WEny also going in my filter list. Have too many people on here who take the bait with trolls and clog this board.

Obviously, ENQ's ownership stakes in SVT, and the related pipelines have increased as of December 1st. It's possible that as a result there may be a bit more revenue being generated for ENQ.

IMO, the extra benefit was for BP that they could get rid of a non-essential/non-core operatorship (for them) and couple the SVT deal to the Magnus transaction. That's the way I'd look at it

If Brent averages close to $70 in 2019, then easy peasy... ;-)

Tariffs and other income is miniscule at $6 mill for H1 and it 'probably' pertains to SVT. The only reference you'd find about SVT is that ENQ as the operator is reducing costs, rather than it being a revenue generating venture for ENQ.

OK, I see that post was for L3 - I saw E3 and I assumed that was me.. ;-)

Thanks for the updates, Chilts. The north sea weather is indeed challenging to say the least.

Thanks for the offer, Fernan. To be honest, I'm not really tracking/modelling PMO like I'm with ENQ. I do have some shares there, but is tiny when compared to ENQ. :-)

Also, I forgot to thank you for your note explaining your investments in the O&G sector. I hope it works out well for you. Once Brent gets into the 70s, we should all be OK. ;-)

All the best..

I'm saying it's one-off, and is worth clarifying...

Fernan,

It's not a question of GCA getting it wrong and to be clear, I'm not saying that this increase is a recurring Opex, which is what you seem to be implying.. GCA numbers would've been based on the feedback from ENQ, no doubt. I'm still re-iterating that I'd rather base my cash flow numbers for 2019 on the guidance from a week ago, than base it on a report that they'd have written back in July/August. There could've been additional unanticipated expenses that ENQ has figured was needed in 2019 and et voila. I'll check this with IR and get it verified.

As I said already, income before tax for H1 2018 was circa 25% higher in 2018 vs 2017. The average Brent price difference between H2 2017 to H2 2018 is approx 25% higher on average and we can extrapolate that income may also increase similarly. I'd say that the tax will be $15 mill or less. And given that your anticipated Brent price is $63, which is 12% less than 2018 average, tax for 2019 will less than half of what you've modelled.

Best

P and F,

Regarding Opex, you're going by what the Magnus prospectus was forecasting back in September, but I'm going by what Enquest has stated less than a week ago. They've clearly stated in the update that the increase is driven by the 75% Magnus stake, as below. I'd like to think that what the company has guided very recently is more realistic than basing your numbers on Magnus prospectus. I can only speculate that additional expenditure is needed on Magnus this year and this accounts for Fernan's discrepancy/difference with regards to 75% Magnus and remaining business, compared to mine, and I'm going with ENQ has stated.

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Operating expenditures are expected to be approximately $600 million, with the increase over 2018 driven by the full year impact of an additional 75% interest in Magnus.
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Also, I have an issue with Malaysian tax figures of $29 mill for 2019. The net income from Malaysian ops for H1 2018 is $20 million vs $16 mill in 2017 and say we end up double that for H2, and assume $40 mill taxable income for 2019 as well, I can't see how Malaysia taxes will go from $11 mill in 2017 to $29 mill in 2019.

We'll know more next month in the AR.

Morning all,

I've already said this to Fernan in response to their last post, but her/his FCF numbers look WRONG to me. I can't see how you can have 52 kbopd for a year (excl the 75% Magnus) and at $63 a barrel (low end of the range pricing, IMO) , you end up zero FCF. That's more likely to be spreadsheet issues to me. ;-)

Let me try to break this down:

Lets start with 75% Magnus and then move on to remaining business/production.

Magnus 75%:

I assumed an average of overall production (conservative) of 17.5 kbopd for 2019 (excluding the circa 1 kboepd gas they produce). Assumed opex/bbl of $30. And assumed Capex of $35 mill. Revenues (at $63) and at 13.125 kbopd, is circa $302 million. Opex is circa $144 mill, giving an EBITDA of $158 mill. Capex share is $26 mill and you end up with circa $132 mill cash flow, out of which BP vendor load repayment would be 27.5 mill.

ENQ would get $102 mill FCF and BP $2 mill profit share. LIke I said this is based on a conservative 17.5 kbopd production and $63 price (a bit too conservative, IMO). Each $ increase in Brent generated an additional $2.4 mill FCF for ENQ.

Remaining business:

I assumed 52 kbopd production for the remaining business, assuming no material increase at Kraken and 9 kbopd from Malaysia. 9k Malaysia fetches circa $41/bbl (65% of Brent) and I assumed remaining at 98% of Brent, assuming a slight Kraken discount and a small impact because of the Mercuria deal which closes in Q2. That's circa $1.1 bill in revenues and the allocated opex based on the $600 opex guidance is circa $455 mill. G&A is say $10 mill and gains from Q1 Hedging, I assume will be $24 mill on the 3 mmbbls hedged. You end up with EBITDA at circa $660 mill.

Bond and RCF interest is circa $133 mill and AK lease interest is $57 mill. Kraken lease could be assumed at $100 mill, based on the current liabilities figures as of 30/06. Malaysian taxes assumed at $15 mill and Magnus 25% repayment is assumed $20 mill. Capex share for this business is assumed at $245 mill. We finally end up with an FCF of $90 mill at a $63/bbl price for 2019. Every additional $ is a circa $15 mill increase in FCF for the remaining business.

In summary, it's $190 mill FCF at $63/bbl and $310 mill at $70/bbl for 2019. The big unknown is where Kraken will land and that'll determine how much FCF would vary for 2019. Magnus was 30 kbopd in 2018 and if that can be upped to 35 kbopd average in 2019, we could add 3 kbopd to this part of the business. At that level, FCF at $70/bbl is closer to $385 mill. So, we do have a good deal riding on Kraken.

Do let me know if there are other cash flow elements I could add into the mix.

GLA...We'll get there soon.

You're right on that count, Pelle. If it was a straight swap without consideration for any further upside, then yes, ENQ could've sold forward swaps and would've realised $80 certainly. So, we can't definitely sell Magnus production through forward swaps - that's contractual in the SPA. However, much of the other production could've been sold, I suppose.

Kraken - I'm not 100% sure how that would work with swaps - i.e. could they find a counter-party that could take the other side of the trade when it's not a straight link to Brent, and as a consequence how could they arrive at a forward price.

That's not necessarily right, BJ. You could take out a put at $72 when the spot price is circa $4 or $5 higher than the put strike piece and not pay a lot of put premium. My take is that they've has taken on this put when the spot price was closer to the mid 70s or a bit higher. But, given the price given is the average for H2 2019, It is indeed possible or even likely that some of them were taken out when Brent was in the 80s.

Your post doesn't male sense, KO. Don't be a blind fanboy/fangirl as I don't see what point you're trying to make.

Of course, it's down to timing and making an assessment of price direction when someone presses the hedge trigger. ENQ hedged when oil was in the mid 70s in August/September. Could they hedged when oil moved into the 80s and stayed there for a few weeks, of course. This point was discussed and I said to MO that the forward curve for the entire 2019 year was in the 80s and they could've taken on a hedge collar between 75 (floor) and say 85 to 87 (ceiling). When this was done for Q1 when Brent was in the mid 70s, why on earth could it not be done when Brent was in the 80s?

I know of a few oil shalers that hedged portion of production when WTI was in the mid 70s, just at the same time Brent was in the mid 80s. What's your point then?

The headlines were net 4 rigs added, but the internals are what really matters. There were 7 oil rigs added, but there were 8 additions in CA and Alaska and they're the traditional vertical rigs. Permian lost another 3 rigs, whilst a Oklahoma shale basin lost 2. The shalers are slowly but surely pulling back.

EIA was indicating an average of 12.5 mmbbls this year and that would mean hitting 13 mmbbls + towards the end of the year. That may only happen if WTI exceeds and stays over 60 for a while though. I predict that with a near 5% WTI drop this week, more rigs would get pulled next week.

GLA..

Evening Romaron,

I don't agree that Shale on a whole is operating at a loss at these levels. There are large pockets of shale belts which can generate plenty FCF, let only profits, even with in the 40s. For example, the Midland and Delaware basis are prolific producers and account for most of the growth in Shale production in the US. Many, if not most wells there have low cash break even in the teens and will generate FCF in the 30s. Both Chevron and Occidental have already confirmed that this is the case with them broadly. Occidental has stated that they'll actually cut drilling budget 10% for 2019 (from $5 billion to $4.5 billion), but still be able to maintain production at 2018 levels. They've also stated that if WTI gets to 60 or higher, they'll increase drilling budgets to back over 2018 levels.

OK, OXY is a huge player in that part of the world and is in a class of it's own like Chevron, but the smaller/mid sized players will certainly struggle with WTI at these levels, as they can't generate the needed FCF and will be forced to cut capex this year. Many of these companies are reporting in the next few weeks and I'll check and see how their capex is trending and what that would mean for 2019 production as per their forecasts.

It's true that circa 30-40% or so of US refineries can't process light crude that comes out of the shale fields and they'll probably need to mix it with some of the heavier grades that they import. Yes, it's true that Gasoline price is the most visible oil price indicator to the general populace and this is the only real benchmark that Numpty really focuses on. With gasoline inventories at multi-year highs in the US for this time of the year and this glut may likely increase with more shale oil being extracted, gas prices may not go up as much in the US, even if Brent goes up more. We're already seeing this happen in the last 2 months. The US refiners are the ones who're suffering as a result, but they've had it so good in the past few years that a little pain may not hurt. Upside of this trend (if it continues) is Numbskull may not focus much on Brent prices and the WTI-brent differentials will continue to widen, IMO. I won't be surprised to see them exceed $10 in the near future.

And I agree that demand concerns are more of an issue for oil at this time. China trade wars and Brexit are playing their part in keeping Brent price bottled up, but once we get clarity on one or both in the next few weeks, it could move meaningfully in either direction. I'm obviously in the bullish camp.

Best

WTI is a good 9 bucks lower now than this time last year, whereas Brent is about a buck lower. That is indeed revealing and is the result the OPEC cuts/Iran Waivers (non-extension) is all being priced in.

Small/mid sized shalers are cutting drilling expenditures for 2019 and I'll get a better sense when they start reporting Q4 results next week. I know many of them that I track were expecting to be generating FCF positive at the end of 2019, through more drilling and higher pricing, but now that expectation has been firmly put to rest.

We'll leave the teens soon enough - after Numpty strikes a face saving deal .. ;-)

Lol..that's the reality though. ;-) Back in December, I wasn't sure how much for 2019 was really hedged, but now we do.

They did take out an additional 2.1 mmbbls hedges for 2018 with that $56 to $68 collar, presumably in January, which isn't too bad, but was certainly a missed opportunity back in early Q4.

So, we've had WTI fall 5% this week and Brent is off circa 1.5% (as of now and this could change), but the WTI to Brent differential is now over 9 bucks. Shale prices are now below $50 and this is painful for most shale producers, with the exception of the major players. Today's rig count may not move much, but I predict a slow decline in the coming weeks to below last year's levels.