Member Info for londoner7

Walter479, you raise interesting points and ultimately the detail of any restrictions will be captured in the prospectus. But I don't expect the new financing to be particularly restrictive. Near term drilling plans were mentioned at the recent update - this year, near term well interventions, 2022 drills in Malaysia (both licenses) , I think I heard Magnus drill too, 2023 drills at Kraken. Eagle farmed out, and 4 wells at Golden Eagle close to completion. I think that covers capital expenditure ahead of repayment in 2023, so those costs can be presented to the bankers. As I said I detected a revised hedging strategy in comments by JS which seems reasonable given the short period before repayment. Of course we need oil to stay at $60 or better so lets hope we don't see any more black swans events soon, but who knows.

I was interested to see ENQ in the frame for the BP Andrews assets. I like that - leave the gas fields to someone else. This implies that JS has capacity for additional spending in his c$750m guidance, which was my expectation and posted here. I think it should be spent to enhance cash flows into and ahead of the 2023 restructure, which should lead to higher production numbers too - perhaps another '7' handle.

If what I described as a c$400m 'war chest' isn't spent, then it sits in the bank while 7% is paid on the bonds. I believe there is a route to early bond repayment but I doubt that is in JS's current plans.

continued

Hedging and the ‘last mile’
I understand the hedging process and toss the numbers around in my head, but I make no allowance for them in my calculations. It is an insurance policy on oil price volatility, which sometimes results in a profit and sometimes doesn’t. The only point I’d make is that comments by JS on the recent call suggested to me that we should expect a higher level of hedging as part of conditions to the new RCF.

It should be clear to you that I adopt an 20/80 rule (focus on the 20% of items that account for 80% of impact). With this in mind I want to return to the Kraken premium, which you seem set on but I maintain has little overall consequence in a cash flow calculation. If I follow your sheet correctly your average oil price is $3.6 higher due to a Kraken premium. If I put that into my calculation (pre-GE) it’s an additional $55m. Not something I’d want to miss, so why do I?

Check out latest results page 69 for a summary of average realised oil prices.

Average realised oil price, excluding hedging (M/Q) $41.6. (Gas is included in the blended price)

EIA has average Brent oil at $41.69 (2020).
McDaniel & Associates Consultants has $41.75 (2020)

I don’t see a Kraken premium to trouble my calculations.

All the best,
londoner7

Hi Tarmak, there are parts of the detail of the loan I didn’t understand, but your number c$23m interest is the same as mine. However, I simply took last years $33m and knocked $10m off as it seemed about right. I also have a $7m interest payment to BP because JS mentioned a $10m payment in 2020. I don’t understand what it is – seems too high for interest on the Vendor loan – so just used $7m for this year.

The point I’m making is that I see some of these items ‘in the weeds’ with little impact on the bigger picture so take a rough measure. I have 10 expenditure items with very similar values to yours and all are fixed except the BP profit share which I have linked into my calculation of the revenue number.

Revenue is the big number at the ‘top of the page’, it has the greatest impact on the resulting FCF so that’s the one I focus on.

Essentially, it is production volume x oil price with a deduction factor for ‘stuff’ – gas, Malaysian profit share, and bits I don’t know about, but I capture in the deduction factor. In 2020 I used 96.2%, which I determined from the 2019 accounts. This year I’m going with 95.9% determined from the 2020 accounts.

If I use my Champagne winning 2021 Brent average forecast of $64.4, mid-point 49K production and a factor of 95.9% I get a revenue number of $1.105m, and a resulting reduction in net debt of $368m. (When I came to this board in 2019 I saw comment on a deduction factor c95% so this method isn’t original.)

This is based on current assets. On GE there were two camps on the tax treatment of 2021 cash flows to the date of completion. I‘m in the camp that says cash flows in this period are subject to Suncor taxation. During the discussion I posted a calculation for full 2021 cash flow of $133m at $55 oil. (More recently I posted my calculation for Magnus PS, so my numbers are out there).

On GE I didn’t account for the costs of wells, but with Brent >$55 I guessing one will balance out the other and the interest charge on net debt for GE will be <$10m so not fussed there either.

Eagle, Gadwall and Mallard
My record here isn’t a good one. When G&M went off production, I speculated it might be a precursor to Eagle activity. When Eagle was farmed out, I speculated G&M might be high-cost elements on the GKA hub. Turns out it was a faulty cable and the G&M fields will be brought back into production later this year. Looks like GKA is a keeper. I think it was Therapist who highlighted 3rd party activity in the area, and licence 32 resulted in a prospective area for ENQ so perhaps there’s life in the old girl yet!

to be continued

"something like $1,280m (net debt) + £222m (cash) = c$1,500m for the year end amount subject to interest"

Oopps, that looks wrong. I've done the same as you and included the bonds again.

In addition to PIK the interest charge is on the remaining gross debt, which is the amount owing on the RCF , Oz loan etc.

Hi Tarmak,

Impressive detail. Three items caught my eye: interest charges, Kraken premium and GE drilling costs.

Interest charges
You have PIK as $70m, so it appears to me you are double counting the interest on the bonds under 'Finance 1' and 'Finance 2' sums. You've assessed interest on a net debt item but I think the gross debt item (excluding bonds) is the one you should use, something like $1,280m (net debt) + £222m (cash) = c$1,500m for the year end amount subject to interest. I see you've then split this into two periods H1 & H2, which is reasonable.

Kraken Premium
I've no doubt that Kraken attracts a premium over Brent but I question trying to capture it in cash flow calculations. If you look at the realised oil price Enquest quote in their reports you'll find it's very close to the average for Brent. Which begs the question, why not just use a Brent average in your calculations? My guess is that other oil is sold at a discount to Brent and it all sort of balances out over the year. At least it has for the last 3 years. I don't know why 2021 should be different.

GE Drilling costs
Interesting to see you've added a cost item c$37m for the drilling. I referred to this in a recent post. I suspect the cost will effectively be paid for by Enquest from the 2021 cash flows but how do you get to $37m?

Thanks Therapist,

You're still beating me to the draw on OGA.

My own take:

The latest update from ENQ covered the Jan-Feb period so not much news, but there are some interesting points.

Kraken
33,723 bopd Jan-Feb reported by ENQ and OGA data indicates this is equally split between Jan and Feb. Recent tanker movements suggest a slightly lower production number will be reported for Mar.
An interesting part of the OGA data is that water injection is down significantly, and also, I’d missed this in the Dec data. We know that oil production volumes react to water injection with a significant delay of 1-2 months, perhaps more. This would explain why the Dec production number held up in spite of lower water injection during the month, and why there is an impact into Mar in spite of the reported fixes. The numbers suggest the riser problem is on an injector well, but the timing is interesting. Kraken guidance for 2021 of 30K-35K bopd was provided 4th Feb, when the riser problems were already known so that guidance looks solid.

Magnus
OGA data indicates the system failures impacted Jan but were more significant through Feb. ENQ reported fix by end Feb with well enhancements, so the Magnus March number should be solid (less impacted by reduction in water injection).

Golden Eagle
In the latest report ENQ said 3 of the 4 in fill wells are complete and producing. According to OGA data oil production from the Golden Eagle fields increased by 2Kbopd between Dec and Jan to 10,240 bopd (net), which bodes well for the guided 10K boepd for 2021 There will be an element of surge production in the new wells but considering the timing of the drilling this initial production may be from only the first two wells.

All looks good for the new acquisition, but I’d guess the capital cost of this drilling will come out of 2021 cash flows, something I hadn’t considered in my earlier calculations. Also, I noted AB mentioned an $8 OPEx on GE for 2021 when it was guided at $5 at the time of the acquisition.

romaron, you raise an interesting point.

As you note, the 'shares' vested last Sept but having exercised them they are now in play for the OO. But I'm unsure what to read into the timing. Have they been exercised now with the OO in mind, or is the tax year a factor? The new tax year starts next week, but the transfer is to a charity so I don't how that fits either.

It will be interesting to see if JS exercises his ahead of the OO. Though I struggle to know what to read into it, other than if it's after the 6th April, but ahead of any OO announcement then that might indicate OO news soon. Anyone see a flaw in that logic?

Got to love the variety of performance metrics. Most sectors just go for a simple EPS but obviously that metric doesn't work so well in the oil sector. Given the common reliance on the oil price an assessment against peers is most closely aligned with shareholder interests, so I wonder why the allocation isn't greater than 30% of the total award. In the event ENQ awarded themselves 7th position against peers for 11% from the possible 30%, equal to approx. 450K share for AB.

Metrics like Reserves and net debt offer a counterbalance, e.g. AB can buy more reserves (GE), which also increases the production number, but that impacts the net debt number. I'd guess too many moving parts for the award allocations to be a factor in investment decisions. Could it be a factor in hedging decisions?

Do you think JS has a worksheet labelled 'my 2019 awards' which gates his decisions? Oh, what a wicked mind I have!

Tom8080, your method is sound but your calculation is wrong

"=15,000bdp*($60 average brent - $14 opex) - $40m in capex = $251m*75% *50% = $94m payment to BP in cash for the cash flow sharing element."

Try this:
((15,000 x (60-14) x 365)/1,000,000) - 40 = $211.8m x 75% x 50% = $79.4m profit share to BP.

But I think your CapEx deduction for 2021 is too high.

Let's go back to the 2020 numbers, using 14,709bopd (oil only), $30m CapEx for wells and c25% of guided $50m license maintenance CapEx:

((14,709 x (41.6-15) x 366)/1,000,000) - (30+12.5) = $100.7m x 75% x 50% = $37.8m profit share to BP.

The reported BP profit share was $41m. Gas sales on c2Kboepd (gross) could account for the $3.2m difference.

In 2021 there's no well CapEx but there is still the c25% x $50m license CapEx = $12.5m. Add c$4m for gas sales.

Tom8080, I agree with your comments on the need for a margin of safety and the risk of operating in a cyclical industry, but that's the business we're in. In the case of ENQ, AB founded the company in 2010 and in spite of his earlier experience took risks that didn't pay off. I wasn't in ENQ at the time or familiar with the business so don't know the justification. But I feel more comfortable today that AB has learnt from his Kraken and Alma experiences and interesting to hear his recent comment on the attraction of short cycle assets. He will not be developing another Kraken anytime soon.

The world is awash with experienced geologists and barriers to entry in the oil business are low. Most of the listed O&G companies are rubbish or lucky. As an investor timing in the cycle matters and expanding on the slide romanon presented helps me to maintain a level of investment focus. I write long notes to myself to clarify my thoughts in a style that I can make public - it helps keep myself on message. I don't post most of them but the latest was directed to romaron in response to an interesting post.

It's an open forum. Readers can self edit, and respond as they wish.

In conclusion, I can accept the $30 break-even swing between Kraken and Catcher presented in slide 11. I speak to the relative numbers rather than the absolute numbers. Importantly, my numbers highlight the impact on an oil project of early cash flows.

* This is not to denigrate the current value of Kraken or it’s future potential, but to accept the project’s failing in outcomes compared to expectations, due to lower production and oil price. Hopefully, lessons learnt on heavy oil extraction will benefit a possible Bressay tie-in to the Kraken FPSO c2024/5. Much to play for here, particularly if Equinor withdraw and Enquest pick up their 115MMboe 2C for the contracted $15m. But right now, just an option – stuff happens!

Late 2019 I posted my assessment of the costings of Kraken development versus the acquisition of the Magnus assets. I haven’t looked back to the post but as I recall I was making the positive case for Magnus against a Kraken development I didn’t expect to ever make a return on project costs at then $65 oil. Not to say that Kraken isn’t an excellent asset to have in the current portfolio but to make the point it would never have been developed at $65 oil.

Pelle has presented some numbers and rather than tweak them one way or the other I want to highlight the impact of early cash flows on project costs.

Ahead of first oil at Kraken, expectations were for 55K bopd (gross) at plateau in 2018. In the event 2018 production was only 30,300 bopd, so I’ll use the higher 2019 production of 35,700 bopd to present a fairer picture.

Project costs came in below sanction projections due to the 2014 oil collapse and were presented in 2018 finals as $2.3B gross (close to Pelle’s number).

For 2019, I’m using average realised oil price of $65 and production cost of $18 per bbl (including lease) taken from Cairn report.

Based on these numbers, expected first full year cash flow (2018) at $100 oil:

55,000 x (100-18) x 365 = $1.65B, leaves 2.3-1.65+0.16(interest) = $0.81B owing on project cost

Actual first full year cash flow (2019) at $65 oil:

35,700 x (65-18) x 365 = $0.612B, leaves 2.3-0.612+0.28 (2 years interest) = $1.97B owing on project cost.

It’s clear to see the initial impact of lower production, lower oil price and a one-year project delay on anticipated project returns. A difference of $1.16B on returns over one year. (For completeness I’ll add the 2017-18 production cash flows c$700m, so c$1.27B (gross to field) owing on Kraken project end 2019.

Contrast with Catcher. $1.6B ‘full cycle CapEx’. 50K boepd at sanction, 67.2K boepd achieved in 2019, 93% oil, gas exported. For simplicity I’ll only use oil, 62,500 bopd. Ramp up was on project schedule to 2019 plateau. Incidentally, sanction CapEx costs were similar to Kraken, (1.6B/70%)/90MM = $25.

Expected first full year Catcher cash flow (2019) at $100 oil:

(50,000 x 93%) x (100-18) x 365 = $1.39B, leaves 1.6-1.39+0.11 (interest) = $0.32B owing on project cost.

Actual first full year cash flow (2019) at $65 oil:

62,500 x (65-18) x 365 = $1.07B, leaves 1.6-1.07+0.11 (interest) = $0.64B owing on project cost.

15MM of oil had been produced prior to 2019, which allowed PMO to declare that Catcher had covered project costs during 2019. (The gas sales helped too. But I don’t think PMO included future decom costs in the declaration)

(A key difference between the two projects is that Catcher is expected to enter an earlier field decline with COP in about 7 years, whereas Kraken was given a 25-year life at sanction.)

I wouldn’t bet my life on the accuracy of my numbers, happy to be corrected, but I’d guess they are close enough.

TBC

romaron, an odd pack of slides. I expected them to lead to a justification of Art’s expectations for near term oil prices, but they finish with a couple of slides on the recent problems in Texas, so I don’t understand their purpose. A couple of interesting slides amongst them anyway. I reviewed each carefully and thought #4 on comparative inventory was interesting but has a significant background element that was either missed or ignored. I don’t get Art’s focus on what seems to me a relatively small difference between EIA forecasts on US production and his own (#9), given the level of supply adjustments possible within OPEC. Incidentally, in their latest STEO update EIA reduced their 2021 forecast by 0.1mm to reflect the problems in Texas, and increased their 2022 forecast, “EIA’s current forecast for U.S. crude oil production in 2022 is 0.5 million b/d higher than in last month’s STEO because of higher expected crude oil prices.”

The EIA see the guys in the big hats humming their favourite song, “Drill baby drill” – still finding their voice but give them time and a favourable oil price.

However, you introduced the slide pack with questions on slide #11, so I’ll focus on that slide.

$100 oil in 2007 was brief, but it’s return in 2011 and indications that price level might be around for a while brought prospects into development that were marginal significantly below $100 oil. The heavy oil in Kraken was one such prospect.

First, I’ve no doubt that the list refers to our beloved Kraken ‘field’, and not the Kraken oil company. Evidenced by the reference to Catcher, not Premier oil.

Kraken is in the list because it represents a field at the top end on costs. Interesting to see Ithaca’s Stella field up their too. I was invested in Ithaca at the time of the Stella development and know that subsequent production fell a long way short of expectations. That knowledge and Catcher’s lower position in the list leads me to believe that the slides’s originators have done their homework and the list reflects the actual numbers achieved rather than project projections. In that sense I think it’s a very informative guide to the pricing across regions, field types and time of development – note the inclusion of Buzzard and Jubilee, both deep-water oil fields developed just ahead of the first visit to $100 oil. An excellent slide!

You highlight, shale at $57. To my eye I see Bakken listed at c$57 and Permian c$47, but like Kraken these are historical costs, or costs to-date. Like a <$30 all in cost extension of Kraken’s Western Flank, I’d guess there are lower cost shale development opportunities too.

Finally, is Kraken a $90 breakeven development?

At sanction, referring to the 2013 CMD presentation, I see $23 CapEx ($3.2B/137MM, before finance costs), $20 OpEx (including work overs), $10 FPSO lease costs, for a total $53 before finance costs.

At $100 oil, I guess Enquest a saw decent margin in 2013. But then, you know, stuff happens

Wow, that deserves a response!

Magee-1 and Mt Kitty-1 had gas shows, but neither was commercial – not that you would know it from Friday’s RNS.

“Despite being technically successful, both wells suffered from poor reservoir quality. Magee 1 produced gas from a very thin (4.5 m) fine-grained sandstone (inferred as Heavitree Formation by Wakelin King, 1994) overlying crystalline basement, while Mount Kitty 1 lacked any subsalt sandstone, producing gas from fractured and weathered crystalline basement. Drilling of a third subsalt exploration well, Dukas 1, was suspended at the time of writing.” (PW Haines and HJ Allen – GSWA 2020)

Mosman stated as an exploration company in New Zealand and Australia. Having idled E145 for several years and failed to find a JV, JB now sees an opportunity to grab US$2m and he’s taken it. Highly dilutive to the US interests, but that’s another story, and probably not foremost in JB’s mind at the moment.

These boards attract all sorts. Some to hype and mug the mugs. Others like Wolfie and Cheapskater looking at both sides of a potential investment and posting as they see it rather than to their own advantage. Rare on these boards. If you are looking to invest here I suggest you spend a hour reading back on their posting history. You can safely ignore everything else.

Looks like the board has lost Cheapskater. You should try to hang onto Wolfie.

EP145 is high-risk exploration. Ask the guys who drilled Magee and Mt Kitty.

Couple of posts asking good questions, I hope this helps.

The following three items are taken from the ‘outlook’ slide in today’s presentation:
Priority now on CEMEX integration and synergy delivery
Remain focused on further reducing debt
Will pursue opportunities to grow and develop

There are others, which are important, but these are the focus items for me.

The items are self-explanatory, but they all boil down to maximising free cash flows in a sustainable, safe and environmentally responsible manner. I don’t want to get into what this means in practice, but the opening sections of Breedon’s annual report expands of how this is achieved.

Breedon have guided to £70m of capital expenditure in 2021, some £10m higher than might be expected, with the additional expenditure directed towards Cemex assets to raise their margins towards the those achieved elsewhere in the group. This isn’t a single step transition but a series of targeted activities and expenditures which are likely to extend over at least a couple of years. I’d expect the ‘super deduction allowance’ to accelerate this process.

Investing capital in organic growth and development generally produces the biggest bang per buck! The management skill is identifying which process or asset offers the best return on investment. Due to a lack of investment prior to acquisition, Cemex is an obvious target. Fast-growing markets say ROI or the Midlands with HS2 activity are other targets.

An attraction for me as an investor is that I believe Breedon has a large portfolio of assets, operational and some currently idle, ripe for investment. Investable projects will be weighted by potential return on investment, but the key resultant company metric is ‘margin’ - free cash flow in proportion to sales.

The CFO (CEO from 1st April) clarified the point when he stated his intension of returning the business to historic (pre-Covid) margins. This statement threw me because I saw 2020 H2 margins close to historic levels but digging deeper I see this is largely due in 2020 to reduced transport cost or improved delivery efficiency (Trencherpilot, any views on this?) and same again admin (head office) costs. Cost of sales increased significantly by 4.5% from c60% to c65% - these are the costs of extracting material and formulating or packaging the material for the end market/customer. The costs of transporting the finished material are an additional c18% of revenue.

Reducing the ‘cost of sales’ margin will be Breedon’s challenge for 2021.

Most of today’s call revolved around analysts attempts to get a measure on the 2021 margin but the CFO wasn’t giving much away. That response might be behind today’s lack lustre share price reaction to what are very good 2020 results.

Next months AGM statement should include Q1 revenue, but alas we'll need to wait till the interims for the margin number.

Worth 30 mins of your time if you're invested.

Confident presentation showing the strength of the business, balance sheet and cash flows. I particularly liked the new initiatives which should generate £4m synergies this year leading to an 'ambition' of 7.5% operating margin in 2023. A holding I built up last year and now happy to leave to play out over the next few years.

AA2020, thanks for your posts. Your assessment broadly aligns with mine, but I'd just add a couple of points.

I'm an investor in CNE and ENQ (weighted more towards ENQ) so I have a particular interest in the sale of the NS assets.

You point to the earn out volumes as representative of the declines at Catcher and Kraken, but if you work the numbers you'll see that CNE's expectations of $80m @ $60 and $125m @ $65, don't fit. In 2021 the minimum is c15.5K, but CNE has already guided to 16-19K for this year. I believe Catcher is about one year ahead of Kraken on the decline curve and taking a mid point 17.5K for 2021 production and using a 20% p.a. decline I've tabulated yearly returns that come close to matching CNE's expectations on additional payments through to 2025.

The point I struggled with, as did some of the analysists, is why sell? It isn't as if CNE need the cash. But, every trade should offer attractions to the buyer and seller, and neither is forced in this situation. My take is that by 2024 the NS assets will be producing below 10Kbopd, which is below the scale CNE is seeking. The numbers look good for the buyer: by end 2025 at $65 oil I see them c$280m ahead on the deal, but Catcher is then close to decom and there will be CapEx decisions on Kraken - a Bressay development enters the picture and I suspect CNE have looked ahead and decided against it. The net cash payments (@$65 oil) equate to the FCF that would accrue to CNE through 2021 and 2022. I guess CNE are satisfied with that to close out their Catcher and Kraken future cash flows and liabilities.

This is a big switch in CNE's asset mix and analysts may be struggling to get their heads around it. I look forward to the detail but if 50K is achieved by 2024, even with two thirds gas, the <10K bopd that the NS assets are expected to be producing in 2024 will pale in significance and there's still c$40m to come from them post 2022.

In an FT comment the Investec analyst said the NS sale price was c30% above their valuation (my maths), so bodes well for valuations of ENQ and PMO holdings.

Perhaps a win, win, all round.

L3Trader, you asked about LTA.

I'd be surprised if your pensions provider couldn't provide you with a spreadsheet or some other guidance on likely impact.

But the operation of the LTA is straightforward so easy enough to produce your own spreadsheet. This has the benefit of allowing you to play out various scenarios around, contributions, draw downs and performance expectations, with a view to eliminating or at least minimizing the impact, which is 55% of capital above the LTA or 25% on income before your marginal tax rate is applied - ouch!

The final LTA assessment is made at 75. The further you are away from 75 the more time there is for investment performance to take you over the LTA. I'd urge everyone to at least understand the possible impact sooner rather than later.

The biggest challenge is anticipating changes in government policy. The latest, in the recent budget, was to freeze the LTA for at least the next 5 years.

Breedon are an obvious beneficiary of yesterday's news.

Depreciation in 2020 is likely c£66m, of which half equates to required maintenance CapEx. A roundabout away of looking at it but that's how I remember it presented a couple of years ago.

In a normal 2020 CapEx would likely have been c£60m. At the half way stage £16m was spent, just covering maintenance needs, though I'm sure the pace would have picked up in the second half. My point is that there'll be some carry over of CapEx into 2021. I don't know how the April 2021 startup of the 2 year 'super deduction' is defined, but I'm sure the CFO will be looking at any short deferments necessary and bringing forward some of the longer term CapEx.

The 'cherry on the top' is the expected CapEx on the newly acquired Cemex sites. A headline from the case for acquisition was , short payback on investment in high-return capital projects. The cost of those investments will now come with a 25p in the £ reduction on the tax bill.

Yes, 25% corporation tax on the horizon, but as Paul Johnson of IFS said yesterday, bringing at end to super deduction at the same time as the increase in corporation tax would be a large headwind to investment from 2023. Something might give!

It sounds to me a bit like 'help to buy'. Once these incentives are introduced they are hard to withdraw.

But if this boom to investment achieves the productivity growth the economy has lacked since 2008, then why terminate it in 2023 if the net benefit to the treasury is positive.

Therapist. what's the significance of 15%?

Hi romaron,

When did you last see me predicting short term movements in anything? I don't because I'm rubbish at it.

But I'd hate to be the party pooper so I've have a crack. I'll take the market's current price as the average for 2021 but I'll knock off a decimal point for you, $64.4.