Member Info for Stevo12

History has a habit of repeating itself and this is the third time a windfall tax has been imposed on NS O&G and each previous time it was subsequently dropped.

The 75% tax has to be weighed in conjunction with the investment allowance and the Treasury have gamed this and believe the investment incentive will work. We will see very soon. I personally think it will if companies receive a contractual guarantee from UK Gov that they will be compensated if subsequent governments change the allowance.

Jan 24

I should have added that the petroleum refined in the US consists of crude oil (about 11m bad), hydrocarbon gas liquids 6.5m bpd, Biofuels etc. These all go into the refining process to produce approx 19m bpd of petroleum products including petrol, jet fuels etc consumed in US.

The key point is that the US is energy independent in that it produces enough hydrocarbon’s domestically to meet its petroleum needs, but chooses to import and export a similar quantity for refining efficiency.

Jan24

US oil production and consumption as detailed by US Energy Information agency and I attach a link to their website. I don’t know where you guys get your stats from but US has effectively been energy in dependent for last 2-3 years, although it exports and imports similar quantities for refining mix.

https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php

US produces 19m barrels per day and consumes 20m. Their consumption needs a different blend as production very sweet. In 2021 US exported 8.4m barrels per day and imported 8.5m per day.

US is effectively energy independent as it could adapt its refining (at a cost) if need to reduce exports and imports.

Megla

Thanks for the feedback. In calculating EPL I had assumed that 10% of EBITDA was from overseas activities and that 50% of UK CAP exp could attract the additional green allowance. Probably a little aggressive.

I had also assumed that Lease costs were included in the OpEx but if this in not the case - and taking a look back at 2021 financial statements I think you are right - then I agree there is a further $200m of cash outflows on lease repayments which is effectively “funding debt”reduction. I think Finance leases should be classified as debt.

I think this puts FCF in the $1.1-1.2b range after repaying $200m of lease debt. Still a healthy Chunk of cash to fund ongoing share buybacks and $200m dividend.

I watched an interview of Lord Browne yesterday (former CEO of BP) who recalled that this was the 3rd time a windfall tax has been applied to NS O&G and the worst being a 101% tax in the 1970’s. He also reflected that George Osborne had introduced a 60% windfall tax that was subsequently removed.

I would add one further point regarding the discussion on debt. HBR debt level is well below any level that benefits the share price in terms of efficient equity/debt ratios.

A further reduction in debt should have a £ for £ benefit in increasing market cap, where as buybacks will have a much more significant impact on share price (in theory!) due to our high cost of capital compared to interest costs (our bonds trade at a little over 5%).

My expectation is that we will see a material overseas acquisition this year of producing fields for ($1-2b) and we will end the year with $2b of debt and a 200m increase in reserves with close to 300k BPD production.

Rookie

HBR have given their first round of guidance for 2023 namely
1. Production 185-200k BPD - a 7% decline on prior year if you take the midpoint
2. Operating costs per barrel $16
3. CAPEX of £900m of which $750m UK, ABEX $0.2b

To introduce a degree of conservatism, the below working is based on realised O&G prices 10% lower than 2022 (oil at $70 per barrel, Gas st 75p per therm). Using the above results as follows

Revenue $4.5b, Opex $1.13b, Cap ex $0.9b, ABEX $0.2b, EPL $0.5b, Other taxes £0.3b, Interest $.1b. = $1.4b of FCF to fund buybacks, dividends and further debt reduction

For every $10 increase or decrease in O&G prices FCF increases/decreases by $450m.

If you have used a model that generates a different FCF then please share. I would hope that HBR gives a 2023 FCF forecast with the 2022 year end results.

Nitro

It is not EIG shares but the previous investors in EIG who were allocated shares last year. EIG continue to hold their 120m shares and the 2m shares can be sold anytime up until 9 March via a share sales plan. Also this is just £6m ish of shares over a month and wont move the dial.

Megla

The rule of thumb metric for NS oil investment is that for each £1,000 invested a return of £200 per year over field life of 15 years needed to justify risk. I will use this as a core metric to illustrate the pre and post EPL impact.

Pre EPL the investment allowance (per £1,000) was a £450 contribution to capital cost via a tax reduction and the NS operator gets to keep £120 of profit per annum (after 40% tax). So in summary the NS operator contributes £550 to capital costs and receives a £120 per annum return (annual return of 22%).

Post EPL the NS operator contributes £88 to development costs and retains £50 per annum per year of profit (annual return of 57%). The above comparison is post utilisation of historical tax losses which is 2024 for HBR and will be early for some operators such as Serica and later for other such as Enquest.

Risk profile also decreases as NS operator has only £88 of capital at risk and in the event of a failed project such as Solan, the loss is minimised and effectively the State bears the vast majority of loss.

In a period of Oil price decline, the downside risk is reduced as firstly the NS operator does not need to borrow to fund development and secondly for HBR a $10 fall in Oil/gas price per barrel results in $0.75b reduction in profit/FCF. Accordingly a $35reduction in oil below the averaged realised price in 2022 (to about $40 per barrel for an extended period) would result in an EBITA/ taxable profit for HArbour of approx $1.3b and a tax bill of $1b post EPL. An ongoing capital programme of $1b a year to maintain production levels generates an investment allowance of $920m and effectively no tax to pay and a small $200m FCF with no debt to repay.

The risk of Change in Labour policy post the next general election can be removed if Government provides a contractual guarantee on a field by field basis to compensate the operator for any subsequent change in tax policy. This has been put in place since 2013 for decommissioning costs and works well to provide certainty. This would only apply for fields approved prior to next General Election but it would at least allow NS to move forward for next couple of years.

Appreciate these are my personal views and other options very much welcomed.

Supuser

I cannot see the further details in the 2022 results will have any impact on the share price. Her have already announced all the key metrics for 2022 and the market is inherently forward looking.

I do however believe the market could respond positively or negatively to more detailed 2023 forward guidance and strategy for NS and overseas investment. I personally believe we will see at some point in 2023 (probably Q1 or Q2) an oil price below current levels driven by a lower level of global growth before a multi year higher for longer oil price.

I am fascinated to see how NS O&G sector react to the new tax regime in the medium term and how they compare the risk and return of overseas investment to NS. It is easy to say invest overseas but this comes with a whole set of different risks. If you could rely on Labour not to amend the current tax policy (which I recognise you cannot), the new EPL regime could be considered to be a more attractive regime than the previous one to stimulate investment and improves the return on capital while reducing risk to the operator. Happy to share the maths behind my logic but clearly O&G execs are probably looking more at Labour policy than current tax regime.

I know one of the advisors to the treasury who helped shape the new tax regime and they genuinely believed it would drive increased investment in NS. Equally Liz Truss thought the Spring budget would land well!!!

The treasury are currently working on a new NS O&G tax regime and will report in Q4 of this year. The brief is that this policy is for post 2028, but in reality it will be the start of a debate which will totally depend on whether Labour values energy security and tax revenues above an undeliverable green agenda. Until they are in power we will not know. However history shows us when a party comes into power and ideology clashes with reality - reality normally wins.

Has anyone compared the Mexican tax rules with the UK. What percentage of the profit do we get to keep? And what contribution do we get from government towards the capital cost of developing field?

I am not sure whether there have been recent changes in Mexico, but there used to be several layers of tax. A royalty on revenue, a share of operating profit as offered in the bidding process, 30% tax on remaking profit and 10% withholding tax on dividends paid to foreign companies.

I suspect that we will keep far less than 25% of profits in Mexico and get very little contribution to capital costs. Very few countries have a reasonable tax policies to O&G other than the US.

The UK has gone from a high risk, high return O&G sector to low risk, low return.. Actually the returns on capital for UK tax paying oilers has improved under the new regime if the investment allowance is not amended until 2028 (which I accept Labour would change overnight). However this can be solved if Tories want to progress discovered but undeveloped fields.

Kign

That is my understanding as well. Harbour funds 100% of the capital cost of developing Tuna and recovers capital cost, operating costs, together with a margin from oil/gas sales once production commences. The Indonesian government keeps the balance and it is going to be interesting to see in the next full update what the commercial arrangement is with Indonesia and whether we keep more than 25% of total profits.

I am not aware of any other country which makes such a generous contribution to capital cost of new O&G developments (to offset the high tax take). Norways pays 95% towards the cost of new field development costs but spreads contribution (via reduced tax payments) over first 5 years of production rather than on a cash spent basis.

I did not intend to be a cheer leader for investing in North Sea and I am not on Jeremy Hunt’s payroll so will stop banging the drum.

Cheers all

Baysil

The reason I have raised this issue for debate is that I don’t think the North Sea is necessarily dead under the current government and existing EPL tax policy and wanted to test my thinking.. NS has moved from a high capital cost, high risk, high return environment to a low capital cost, low risk, low return environment.

The argument I was seeking to explore is that operators (who are profitable and tax paying with existing producing fields) now have to contribute very little capital for a new field development, but as a quid pro quo the the post tax FCF are much reduced. However their return on capital may actually be higher. Under the previous tax regime an operator would have to fund $800m of a $1.5b field through bank debt, now it is $129m - an 85% reduction in upfront capital requirements. Yes they would also receive $250 pa of FCF rather than $100m pa under the $60 oil scenario.

However I recognise that labour has stated it will pull the plug on “investment loophole”. this is actually the uplift from 75% to 91.4% and not the entire investment allowance. Accordingly I fully accept that you would not invest unless you had a commercial guarantee from current government that operators will get compensation for any tax changes by following government (as we have with decom expenses) or wait until Labour is in office to see their policy.

I fully agree that war chest should be spent overseas on diversification, but equally many of the overseas tax regimes are pretty unattractive and operators get very little support for original capital expenditure. On Tuna for example, Harbour will get zero cash contribution for capital costs and will have to 100% fund the development costs and recover from production revenues. It is easy to say invest overseas but need to find the right second hub - not sure I would want that in waters being contested by China as they seek to expand their influence in South China Seas.

Ultimately the truth will out over the next couple of months when Rosebank and Cambo are either approved or mothballed.

Continuing the debate on whether North Sea is uninvestable, can I run my thinking by you all and would appreciate perspectives and challenge.

If HArbour had an opportunity to develop a 100m barrel field with 10 year life at a cost of $1.5b over 3 years, with operating costs of $20 per barrel once productions starts. All I think are reasonable assumption.

Under the current EPL tax rules, cash cost to harbour of the capital spend would be £129m (once tax losses are fully utilised in 2023) or $1.29 per 2P reserves. Oil prices of $60 per barrel would result in post tax cash flows per year of $100m per annum (10 per barrel) and $1b over the 10 years for a $129m net capital cost. Oil prices at $80 per barrel would result in $150m per annum or 10 month payback and $1.5b of project cash flows.

Even in the most unlikely oil price scenarios of oil at $40 per barrel from say 2026 for 10 years and tax rate remained at 75%, the annual cash flows from project would still be $50m per year and 2.5 year payback.

I appreciate the above analysis assumes

(1) 91.4% allowance is available and that Labour has undertaken to reduce it to 75% which introduces a key uncertainty (this can be overcome if current Gov wants to kickstart a number of projects).

(2) HBR makes a UK taxable profit of $500m per year during the development phase (oil prices above $30 per barrel) - an almost unthinkable downside.

SO the million $ question, If you get gov guarantees on the availability of the investment allowance, why would you not develop discovered UK fields such as Cambo, Rosebank, Bressay etc. when the capital cost per 2P reserves is so low and has reduced from $8.25 per barrel pre EPL to $1.29 per barrel of 2P reserves post EPL. What am I missing??

I also accept that this would only apply to discovered fields and so does not really encourage new exploration.

Baylis

I would appreciate you thoughts on the potential value of NS O&G reserves in the post EPL environment and possible deal prices if there is further consolidation (offloading of reserves by O&G majors). It looked like values were in the $10-12 per barrel of 2P reserves pre EPL - is that now $5-6 per barrel?

Using an oil price of $80 per barrel and operating costs of $20 per barrel would result in $15 per barrel of FCF. DIscounting at 15% would average about $9 per barrel before Decomm expenditure. A post tax decomm liability of $2.5 per barrel of reserves points to about $6.5. For Norway reserves it would be slightly less and it looks like HArbour and Shell could not agree to likely long run gas prices.

Looking at level of shorting it remains relatively low at 2.6%, with the majority taken out just ahead of November budget statement. Little surprised they have not cashed in yet,

HArbour have been clear that they expect to have a debt level of 1.5xs EBITDa across the cycle and while post EPL this ratio needs to change to something closer to 0.75xs EBITA (currently $3b). Accordingly I am expecting major overseas spend over next 2-3 years and the question is whether these acquisitions will be value accretive (harbour have a good track record of buying cheap and extracting value) . The lowest risk way of creating shareholder value at low share prices is share buybacks and even in US where O&G taxes have not changed, the O&G industry is prioritising buybacks ahead of investing in expanding production.

Kign

I have a much larger investment in HBR (similar to my holdings in BP, SHell and Total) and a smaller investment in Enquest and Serica.

I think Enq has more upside potential purely because of its leverage. Equally it is higher risk and more downside risk. This is clearly reflected in the yields on respective bonds. I have split my investment in Enquest between bonds and shares. I did the same on Premier and did very well on Bonds and lost my shirt on shares.

Baysil

I am far too long for my own good. However I am also realistic and try to make informed decisions based on facts and probabilities as opposed to uniformed expectations.

My expectations and the reason that I remain invested is as follows:

1. On a macro basis the world is simply not investing enough in O&G and we are currently only replacing 25-35% of oil extracted. While I am highly supportive of renewables as part of the energy solution, O&G will be needed for may decades and I don’t believe we will see peak demand for several more years and then O&G plateauing as renewables service the ever increasing demand for energy to improve lifestyles. O&G will remain at elevated prices for next decade at least

2. Harbour existing business is generating at least 10p per share per month in net cash generation (£90m per month) which over a year should translate to share being £4-4.20 by 31 December 23. I would expect that share buybacks continue at $100m per quarter with another $500m of debt repayment. I think we will have this confirmed at next update.

3. The only significant downside risk I see in the short term is a recession in 2023 which temporarily drives down O&G demand and rices. This will only be a temporary impact and the medium and long term trend is an increasing O&G price

4. There a number of potential positive drivers of price. A floor under the price for EPL, investment allowance guarantee, significant acquisition.

In summary, I am happy with a 20% growth per year over next 3-5 years. I am frustrated that UK gov have basically stollen 1/2 of the market cap of Harbour and it will just take longer and than I hoped to hit my £6 expectation.

We will have a definitive position once 2022 annual report is published. The interims statements highlighted tax losses carried forward at 30 June 2022 were valued at $1b after utilising $250m in first 1/2 year. So probably in the region of $750m of value at the year end - this is the cash value and not the gross loss and £750m equates to losses on $1.9m at 40%.

Accordingly looks like HBR have used about 1/2 of the losses inherited by end of 2022 and will likely be fully utilised in 2023 if O&G prices stay high.

Rookie

Given EPL has effectively reduced EPS and post tax cash flows by 58% (without further cap ex), then a 40% reduction in equity is not too bad. If you stand back and just take in the view, EPL forecast payments by HArbour over next 6 years is $5.5b - even discounted it is more than our market cap.

I am sure we would have been £6+ without EPL by now so yes probably a 50% reduction in value of Hsrbour. Come back Liz Truss!

Tarmak

I used the interim statement for June 22 which detailed lease capital payments due with 12 months of $136.9m and amounts due after 12 months of $403.4m. These are the capital repayments and exclude the associated interest payments.

The amounts of lease payments to be made within 12 months (ie 2023) at 31 December 2022 may have moved slightly from June 22, but any change should be immaterial. I am not sure whether you have included lease interest in your interest costs.