Member Info for londoner7

A simplified way to understand the EV concept is to envision purchasing an entire business.

Enterprise Value (EV) Formula and Calculation

EV=MC+Total Debt-C
where:
MC=Market capitalization; equal to the current stock price multiplied by the number of outstanding stock shares
Total debt=Equal to the sum of short-term and long-term debt
C=Cash and cash equivalents; the liquid assets of a company, but may not include marketable securities

Leases and contingent liabilities are not debt. These are balance sheet items that contribute to a calculation of net assets. Assets and the ability of the business to develop assets to provide returns to shareholders are valued by the market - the Market Capitalisation.

Hi Therapist, I have 20% gas in the Oct mix, 3,532/17,608, but the key point your post raises is the recent step up in the % of gas. Given the marginal increase from a stable period Mar-May suggests a significantly higher % of gas in the marginal increase – I calculate 42%. This ‘transition’ includes both the workovers and the new well, and I’ve heard of gas caps on new wells so time will tell if there is any longer-term change in the gas mix. Also, calculating differences between large numbers can be noisy from one measure to the next.

Perhaps the new well has simply hit upon a pocket of imported injection gas used before the change to water injection.

Something to watch.

There are three other areas that I found interesting in the NSTA data and the recent update:
1 – Oct production was a decent number the month immediately following a 24-day shutdown. While there might be a surge component there is also a delay in the production response to water injection. The Nov production number should provide a better guide to near term production performance - for better or worse.

2 - I thought the reference to increasing indigenous gas export facilities to 20MMscfd interesting and confusing. According to NSTA data Magnus was producing up to 40MMscfd in 2019. While this will be a combination of indigenous gas and recirculated imported injection gas, if it’s all coming out of the producing wells, what’s the difference with respect to the gas exporting facilities? The Magnus prospectus refers to a drop in gas used as fuel from 12MMscdf to 6MMscfd in 2024. I don’t know what allows this reduction but perhaps it’s been brought forward and is linked to the facilities upgrade.

3 – Given the change from 3 new Magnus production wells in 2022 to 1 (big boy) and talk of a supporting water injection well in 2023, leaves me wondering how many production wells we’ll see in 2023 – there is a finite number of slots, with each new well replacing an old well. This isn’t meant as a criticism of a change in plans, just an observation. Ultimately, Enquest will be managing the Magnus facility to maximise ‘returns’ which may have scope to take account of the current high gas prices. 2022 looks like a 200p/therm average for day-ahead pricing, equivalent to $140 per boe. I’m guessing 2023 will see something similar.

In 7-8 weeks, we’ll get a trading update which will provide guidance numbers for 2023 and perhaps answer my three points of interest.

There has been much speculation on the reasons US shale hasn’t responded to the increased oil price with a higher rate of drilling. I read a recent article which said that in spite of high investment returns on new drilling the returns on buybacks were greater because of the relatively low valuation on share prices. There was also the benefit to US shale producers of maintaining their ‘tier one’ assets for future drilling when the returns versus valuation metric switches. It sounded to me like one of the better arguments I’ve heard for the slow uptake on shale drilling.

While the likes of HBR do not have ‘tier one’ assets to ‘protect’ they do have a lower valuation than US shale, so perhaps a similar case can be made for buybacks.

I haven’t done the maths, but I’d guess HBR management has.

Also, I agree with comments on the appreciating value to shareholders of the $200m dividend, because of buybacks. Over time the share price will reflect the dividend yield.

In their last update Enquest said, "c.1.6 MMbbls have been hedged with an average floor price of $54/bbl and an average ceiling price of c.$73/bbl for the last two months of 2022"

Remember, these are financial instruments and may have already been closed out. The current front month often quoted here is Feb 2023, priced at c. $77 as I write.

But my understanding is that Enquest sell their production at 'dated brent', the price for delivery today, or perhaps some averaging, say the dated brent price over the last 5 days. I recall HUR quoting an offload priced on a 5-day dated brent average.

Yesterday's closing price on dated brent (Platts) was $85.5, when the Brent Front Month was $76.

Corrections:

I said, "Given the 2nd year hedging requirement under the RBL I suspect focus on reducing debt will continue, with those 75%, 50% and 25% thresholds in mind."

There isn't a 25% threshold. I'd guess Enquest are close to the 75% threshold which reduces the 2nd year hedging requirement to 25% of net entitlement production. It's the 50% threshold that might be targeted, reducing the requirement to 15%.

A minor correction on "EPL for 2023 H2", I meant 2023 H1. I was only using Tarmak's H1 numbers.

Hi Tarmak, you present several scenarios, but I don’t see the one described by IR in Pelle’s post, the key line being:

(less) Opex (excluding depreciation and interest costs)

Following the IR example and using your numbers, I get a ‘Taxable profits (pre capex)’ = 613-187-37-57 = $332m

You have capex of $46.6m resulting in an allowance against EPL of $60m.

Deducting this allowance from the taxable profits and applying the EPL results in an EPL for 2023 H2 of
(332-60) x 35% = $95m.

Then you consider the impact of an additional $50m capex in 2023 H1

This increases the capex allowance to (46.6+50) x 1.29 = $125m.

The new resultant EPL is (332-125) x 35% = $72m.

According to these sums, an additional $50m capex reduces the EPL by $23m in the year capex is spent.

There are two points I’d add:

1) We are only considering the EPL. The additional $50m capex accrues additional allowances under the standard UK tax structure which will benefit the ‘deferred tax assets’ line thereby reducing future income tax liability.

2) An additional capex of $50m would come out of distributions to shareholders or debt reduction, but let’s assume all of this $50m contributes to growth, i.e., additional barrels, whereas current capex simply maintains current production from one year to the next. If Enquest gets their sums right the $50m ‘growth’ capex increases future FCF, with the shareholder getting 65% of any increase after EPL. Enquest will be assessing the ROI of various potential investments under the EPL which will influence capex decisions. But, finally getting to my 2nd point, I think posters here have too high an expectation of the level of additional capex Enquest can spend over the near term. Enquest were $45m short of their 2022 plans, albeit there was a beneficial FX impact and $10m may be attributed to Golden Eagle expenditure delayed into 2023.

In a couple of months, we’ll get 2023 guidance on production volumes, capex, opex, and hedging.

Given the 2nd year hedging requirement under the RBL I suspect focus on reducing debt will continue, with those 75%, 50% and 25% thresholds in mind.

If I’m interpreting this discussion correctly, I think there is confusion in the use of the phrases, ‘deducted on EPL’ and ‘used to offset the EPL’.

I’m also confused by the comment ‘but can hedging losses can be used to offset EPL in the same way allowable investment would?’

On the latter point first. The ‘same way’? Referring to the IR calculation in Pelle’s post, UK capex and associated tax relief is deducted from Taxable Profit (pre-Capex), to produce a Taxable profit. EPL is then applied at the rate (25 or 35%) to taxable profit.

On the first point. Hedging losses or gains are covered by the UK revenue minus opex summation. It doesn’t matter whether you use a realised oil price in the revenue number, or the actual revenue and the hedging loss is added to opex. The point is that the hedging component is included in the computation of the EPL. In much the same way as capex and associated tax relief.

If the view is that the hedging loss can be deducted directly from the computed EPL then I believe that view is wrong. As I write this, I find it hard to believe that is a consideration, so if I’ve misunderstood, please clarify.

HBR have several $billion of hedging losses. Investors there would be delighted if those losses directly offset the EPL – the tax man would owe them money. The easiest way to consider hedging in the EPL calculation is as a component of the revenue from the realised price after hedging. To be clear, that’s hedging realised in the accounting period.

As I said, if I’ve misunderstood the discussion please clarify your point, or correct mine.

* Game about to start. I hope the Welsh team hasn't exhausted itself singing their anthem and can give England a game.

mrc, on 26th May I posted, “Combined negative impact on cash flows over the next 12 month = $71m - $96m.”

That's $43m - $58m (midpoint $50m) for 2022 period.

In hindsight I’d say a pretty good stab ahead of the interims and a better understanding of the detail on decom and finance. (Dare I say remarkable)

In an Oct post I had ‘in mind’ $75m for 2022 (I wrote 2021 but was correctly pulled up for my typo).

I refined the process of my EPL calculation and posted it here a couple of weeks later. That calculation produced the same EPL number I got using IR’s calculation posted by Pelle. I thought I was clear that I didn’t post that EPL number, only my process.

I think that covers the history of my posts on EPL. I hope it helps.

27th May - “It (Enquest) is expected to pay an extra $14 million this year and $73 million next year, Jefferies said.”

I'll work my own numbers and leave Jeffries estimates to others!

mrc, our posts passed.

Thank you for your calculation.

I haven't examined your assumptions, and don't plan to, but your results are remarkably (I like that word) close to mine!

mrc, a while back I posted my working assumption number for the EPL, which was challenged by one poster as being too high. I asked for evidence of their working, but he couldn't come up with it and referred to the Jeffries number of $14m for 2022.

In the meantime, I had a more detailed look and later posted the process of my EPL calculation - I ran a calculation based on the 2022H1 report but decided not to post the EPL charge itself. When I saw Pelle’s post, I immediately plugged in the called for data, again using the 2022H1 report. (There’s no need to estimate full year 2022 numbers. Using real numbers from the interim report gives you a good idea of the EPL’s impact)

Remarkably, both processes, which differ, gave me the same result (within $1m). I say remarkably, because although I was using the interim report both processes required some level of estimation, i.e., both data sets would have included some error.

I didn't analysis the differences between two processes, but I prefer the one from IR because it leaves the capex component till the end and clearly shows the degree to which capex would need to be increased to have a significant impact on the EPL.

In time, probably at the Feb update, Enquest will reveal their EPL for 2022. If it's close to $14m I'll feel very silly - I'm on multiples of that number.

But don't let that stop you from posting the detail of your calculation.

* Approx. 55% of the 2022 EPL is payable in Dec with the balance due in Jan 2023.

Dumbly, I’d stick with the c.$700m deferred tax asset likely to be utilised over the next 3-4 years and re-evaluate with the 2023 accounts next March.

As I’m sure you’ve determined, there are many moving parts to the composition and calculation of this asset. Not least the expected future price of oil, e.g., tax losses can only be included if there is an expectation that future profits can be realised against those losses. Therefore, potentially, as the oil price increases tax losses that were unavailable to use become available. However, on the P&L account a higher oil price can also lead to a reversal of impairments beside the more obvious increase in profits. I see the future of the GKA area being one potentially significant variable, and I don’t strictly mean this in a negative way.

I’d guess Jeffries sacked the person who forecast Enquest EPL at $14m in 2022.

is 280p/therm for tomorrow, after 150p/therm today.

This demonstrates the volatility of these prices and could easily reverse in a day. Days like today, colder and windless drive up the demand for gas. When demand increases, say due to less wind, the higher priced contracted alternatives come on stream such as biomass and interconnect supplies, but these are limited and gas is the marginal source, which can prompt spikes in the day ahead pricing like today.

In the first half of Q4 Day Ahead pricing averaged c.100p, so it would take a 2nd half averaging 300p to get to a Q4 average of 200p.

mrc, I don't have your confidence in analyst's estimates, however I did look back at a comparison of the Dec 2021 numbers to June 2022 and see a £7.6m adjustment. I also see a £1.2m adjustment in the previous 6 months but I could put that down to a move from non-current discounted provisions to current provisions. I can't say the same for the £7.6m.

If I had a significant shareholding here, I'd be asking questions of IR.

But I don't. However, I think a c.10% pullback covers the 'anomaly'.

To be honest I don't place any value on the comments or opinions put up on these boards to the valuation of PMG's prospects, or any other companies. I generally believe the market knows it. I follow the boards for facts not opinions. As I say, I believe the investment case here largely depends on the success of the GPA farm in. Too speculative for me but given the current environment I'd give it a good chance compared to much of the speculative stuff I follow - through interest rather than as an investment.

* Back to following analysts, I think you put too much weight in Jeffries estimate of Enquest WFT. I think it's a very easy calculation which, as far as I've seen, all ENQ posters have wrong on one side or the other. Something I might come back to on the Enquest board but following today's update there's other stuff I find more interesting. And yes, I recognise the possibility I might have the WFT calculation wrong too. Don't you love this stuff!

mrc, I follow this board to watch the rise of Tom Cross or will it be rise and fall of Tom Cross. Can he repeat earlier success or was he just lucky. I'm undecided but watch with interest and have a skin in the game small stake. He might yet luck out with the GPA farm out. If he does, I think the potential rewards could dwarf any financing issues.

When I saw yesterday’s update, I didn’t attach much significance to the decom being brought forward. You say, “decom costs have gone up £7m”.

Could you detail how you come to ‘up £7m”.

Hi L3Trader, when it comes to the distinctions between CapEx, Decom and their associated allowances there's a limit to the level of detail I'm confident on, so I'll pass on any examination of your numbers.

But I'll comment on some parts of your post.

I think decom commitments and associated costs were already in train for the next few years and I don't think they are activities that can be deferred to a period where there might be a better tax regime.

I agree that the level of windfall taxes applied across the board to the UK oil and gas sector is too high for the 'windfall' actually enjoyed, also it deters future investment in the North Sea, and, I'll add, increases investor risk thereby reducing share prices. Is that a double or triple whammy for investors? Given the situation I could see a case for a windfall tax but given the disparity between the windfall benefits that actually accrue, considering hedges etc, I think the 25% rate was just about acceptable to the sector, but exceptionally tough on HBR. The 40% increase to 35% is beyond the pale but driven by politics. There was always the threat of a c.35% rate or higher following the next election and share prices of the North Sea companies would continue to reflect that uncertainty. Having now increased the rate there is a case for thinking the government has cratered the argument for a much higher tax by Labour, though that leads me to my next point.

Not only is one government not beholding to the decisions of a previous government, but it is also clear that one PM and cabinet is not beholding to the decisions of a previous PM and cabinet. Those are the risks I accept as an investor in the UK. Unlike the US system I think it's almost impossible for us to mark our ballot paper in a way that leads to 'gridlock' in the UK system.

Today the politicians are lifting the 'windfall' gains of the UK oil and gas sector.
A few months back they were lifting the profits of the UK house building sector to cover deficiencies by other businesses (many non-UK that can't be touched and some that no longer exist) to cover deficiencies in building regulations and the illegal approval of materials by some suppliers.
A few years back (and it continues with a tax surcharge) they were lifting the profits of banks, though fair to say this was a situation of one robber robbing another.

I think this quote sums up these activities:
“(Why do you rob banks, Willie?) Because that's where the money is.”

Sutton denied ever having said it. "The credit belongs to some enterprising reporter who apparently felt a need to fill out his copy," wrote Sutton in his autobiography. "I can't even remember where I first read it. It just seemed to appear one day, and then it was everywhere."

Continued ...

Looking at 2). You might think that what I have written under 1) is altered by the text on pages 10-11, but I think the key part of the text is, the ‘non-cash’ reference. ‘ …. these half-year results would have included the recognition of an estimated additional one-off non-cash net deferred tax asset of $1.0 billion in respect of the EPL through to the end of 2025.’

The note is capturing the impact of the WFT on tax liabilities and assets on the balance sheet. There isn’t a cash implication.

Finally, you raise an interesting point on the cost of premium on a hedge swap, as opposed to say, a costless collar. I would expect this premium to be a normal cost of business leading to a deduction before the WFT is applied. However, without doing the numbers my gut instinct is that it has a marginal impact, but worth a look.

* The focus here has been on the running down of the 2022/23 hedges, but I agree with comments that there may be a case for capturing the current high gas futures with new hedging. E121 recently posted links to day-ahead gas pricing and historic numbers. While the gas futures pricing has remained above the often-mentioned 200p/therm reference, the day ahead pricing has not. These are the prices that HBR receive for their pipe-line gas. During the first half of Q4 I estimate the price has averaged 100p/therm. To achieve a 200p/therm average in Q4 will require prices of 300p/therm for the remained of the year. Given the volatility in these prices that’s possible. But it also reinforces the case for additional gas hedging like the latest reported at the interims. ‘Winter 2024 ZCC 200p floor vs 540p cap Last executed gas trade’.

Hi Banburyboy, I was following the calculation in your post (07:52) but I lost it at this point:

‘If market price is $100 there is a realised loss of $30 against the hedge which means tax is now only on $20 at 35% = $7 an effective saving of $12 on tax.’

Where does the £20 come from?

However, I think I get the gist of the point you are making.

1) You say, “Realised hedge losses are allowable against WT. You may say so what?”

2) And you point to the WTF reference under taxes (pg10-11) in the interim report.

Looking at 1). I think this simply means that hedging losses form part of the normal business and are not treated any differently under the WFT to treatment under the existing taxes. This distinguishes the treatment of hedge losses from the expenditures on finance and decommissioning which are not deductible under the WFT but are deductibles under the existing taxes.

I think your conclusion is correct if hedging matched production ‘Can't help thinking if it was possible to hedge the lot at $70 all the uncertainty would disappear we would know free cash flow with certainty and would only need to worry about operational issues.’. Another way of getting to it.

Let’s consider the top line, revenue, for 73m barrels of production, oil price of $100, and three situations, a) where 0% is hedged, b) where 100% is hedged and c) where 50% is hedged @$70.

a) Revenue = 73m x $100 = $7.3b
b) Revenue = 73m x $70 = $5.1b
c) Revenue = $7.3b above minus hedging loss of (73m/2) x $30 = $7.3b - $1.095b = $6.2b

For the calculation of WFT the same deductions for costs are applied. Let’s say they amount to $4b.

The post-tax profit after WFT but ignoring existing tax is, under
a) $7.3b – (($7.3b - $4b) x 35%) = $7.3b - $1.155b = $6.15b - no hedging
b) $5.1b – (($5.1b - $4b) x 35%) = $5.1b - $0.385b = $4.71b - 100% hedged @$70
c) $6.2b – (($6.2b - $4b) x 35%) = $6.2b - $0.77b = $5.4b - 50% hedged @$70

Going back to your conclusion, under b) the post-tax profit is $4.71b regardless of the price of oil, offering the certainty you refer to.

Under a) & c) the post-tax profit will be lower than under b) if the price of oil drops below $70 but is always higher at prices above $70.
At prices above $100, revenue minus costs gains will be taxed at the WFT rate of 35% but that still leaves the balance with HBR.

However, an attempt at 100% hedging brings its own risk. If actual production fails to reach or exceed the hedging obligations, then if the price moves the wrong way HBR would pay the difference.

I appreciate I may have misunderstood your point. If so, please correct me,

BHP has raised their offer from A$25 to A$28.25, with latest closing price A$26.3.

I've been an investor in BHP for many years and my read is that if OZ doesn't accept the raised offer BHP will walk.

I hope the deal goes through. I don't remember the detail but when I looked at this a few months back it seemed a good move by BHP.

This from the published statement:
;5.32 Energy Profits Levy (EPL) - From 1 January 2023, the EPL rate will rise by 10 percentage
points to 35%. The investment allowance will be reduced to 29% for all investment expenditure
(other than decarbonisation expenditure) broadly maintaining its existing cash value.
Decarbonisation expenditure will continue to qualify for the current investment allowance rate
52 Autumn Statement 2022
of 80%. The Levy will end on 31 March 2028. With these changes, the EPL is expected to raise
over £40 billion in total over the next 6 years. The government will legislate for these measures
in Autumn Finance Bill 2022, except the changes related to decarbonisation expenditure which
will be legislated for in Spring Finance Bill 2023.

Applying this to current ENQ UK CapEx c.$120m

120mx45%x25% = $13.5m
120mx29%x35% = $12.2m

As the statement says, 'broadly maintaining its existing cash value'.

32% would have maintained the cash value but I guess putting a '2' handle on the allowance negates some of the kickback on investment allowances from the opposition parties.

The 'Decarbonisation expenditure ... allowance rate of 80%' is a detail I didn't know about. Perhaps something for the future for ENQ.