Member Info for Stevo12

Nitro

I think the government are much more sensitive to gas rather than oil prices as gas drives consumers utility bills. Not sure they really care that much about oil prices as we have become used to petrol prices ranging from £1-2 per litre.

Gas now down to below pre war levels and anything in the 150p-200p per therm level (5p-7.5p per kWh) is affordable for consumers and is well below what we are currently being charged by gas distribution companies. If Russian gas is no longer the main source of European energy and is permanently replaced by US LNG, there is almost no scenario that gas returns to 50p per therm level and 100-150p per therm is now the floor price. Unfortunately Harbour has one more year (2023) of receiving a little over 40p per therm for 2/3 of its gas sales, after that our gas revenues should at least double at no additional costs. Unfortunately 75% of the profit will be abducted by our highway robbing government but increased realised gas prices will add at least another $250m net additional cash per annum after tax.

Aimoil

The fields are in Norway and not UK and wholly subject to Norwegian tax which is higher than UK at78%

Having listen to the presentation I am generally more positive towards the benefits of the deal on a number of fronts. However my key concern around relative value remains and was not directly addressed. Currently Serica on s debt free basis is valued at around $8 per barrel of reserve and Tailwind at $18. The gap was indirectly explained as being the value of tax losses which, to closed the gap, would need to be $400m (40m reserves x $10pbbl). This compares to the maximum value of losses of $470m.

I was comforted by due diligence on Platform and tax losses, also speed that losses will be utilised. The fact that the cash earned by Tailwind from announcement is retain by Serica is helpful to know but equally Serica’s net cash position will also have improved by a similar level.

Divi

As detailed in Nov operational update, harbour needed $90 pb oil and 220p/therm gas for Q4 to hit the 2-2.2b range.

Both O&G prices have soften in later part of Q4 and have fallen a little short of required levels. However it appears production has been strong so should compensate to some degree.

The $2-2.2b is a cash flow number and so much easier to hit by delaying a few creditor payments or deferring your share buy back programme for a couple of weeks! I am sure they will be in the range 2-2.2b and my bet is towards the middle.

It will be interesting to see where net debt has fallen to at 31 dec. However most interesting will be any guidance for 2023. I believe they will commit to zero net debt by year end. 2023 unless an acquisition and may give some guidance on production, operating costs and EPL which looks like it will be close to $1b per annum. Thank god for the premier losses providing relief against core tax other wise we would be close to $2.5b in tax next year with very little left to repay debt.

Kign

I think the $20-22 quoted is for OPEX and recovery of upfront capital costs - total recovery $3b+ inc $1b of cap exp

Harbour profit is on top is $773m does not seem enough over 15 years to be worth while

I may be missing something but reading the announcements it appears that HArbour can recover the $3.3b of capital and operating costs over field life and is then allowed a profit over the project life of $773m, an uplift of 23%. Total costs are estimated at $20 per barrel and on this basis we are only allowed to bill $24.6 per boe and make a margin of $4.60 a barrel

Am I reading this correctly? If I am this is a far worse deal than North Sea post EPL where we get to keep 25% of the difference between revenue per barrel and OPEX per barrel which is currently (80-15=65*25%) = $16.25 per barrel compared to $4.6 for Tuna. Also UK lets Harbour offset its capital costs against current tax liabilities and we do not have to worry about Chinese.

I truly hope I am missing something as it appears to me that the only location were O&G is treated fairly is US where the sector has much more political clout.

I would add per runs 2p reserves increases by 0.04 barrels per share post deal and production by a maximum of 0.01 barrels per share in 2023. Accordingly we are paying in real cash $126 per barrel for additional production in 2023 and $32 per barrel for additional 2p reserves.

Eps and operating cash flow solely because of tax shield.

Clearly Tailwind has been very busy during 2022 and a better deal than I first envisaged. However the fundamental concern to me is price paid. The one metric which was not on the slide was net cash per share pre and post deal. My calculations show that net cash per share post deal decreases from $1.83 per share to 57c per share, a decrease of $1.26 per share and cash flows for share increase by12c and operating cash per share by $14c. Accordingly we are paying 9-10X earning and cash flow improvement.

That is still very expensive and is highly dependent on tax utilisation.

I also do not understand the operating cost per share before and after deal. Our operating cost were $16 boe at the interim stage and projected to increase to $20 boe both before and after deal, which indicates that Tailwind has dropped from $36 boe to $20 and Serica has increased - does not sound right.

Romaron

I did a bit of digging into the source of the 9 times cheaper quote.

It was based on a comparison of the lowest price in an onshore 12 year wind contract with annual index linked price increases as compared to the highest overnight gas price in mid August when for a few minutes CFD prices went up to 950p per therm.

The fact that this quote has now become urban myth and “political truth” is scandalous and indicative of our lazy left leaning media.

I very much agree with your assertion that RBL funding is going to be much more difficult to secure at the same levels as in the past. The EPL has reduced post tax cash flows from existing reserves by 58% for those companies without carried forward tax losses and new RBLfacilities will reduce by a similar amount.

Recognise we have different opinions as to whether RBLs will be needed going forward to fund new field developments. However they will be needed to fund acquisitions of producing fields which should also have declined in value per $/ barrel of 2p reserves due to EPL.

January

I am as frustrated as anyone with the EPL which put a massive hole in my expectation for Energy stocks. However unfortunately this is now law.

However the key economics are for a profitable O&G company, the net cost for new capital projects is between 5 and 8% of the total capital cost and the company gets to keep 25% of the subsequent profit arising from the investment.

The fact that the government funding of the investment is coming from taxes the company is paying is frustrating but economically irrelevant. The taxes are payable if we don’t invest and the choices are pay the tax monies over to HMRC or divert them to fund capital projects.

The Acid test will be whether Rosebank and Cambo projects are sanction over the next few months.

Romaron

I should add that you do not pay the tax and then claim it back once you spend the capital and as such require banking funding in the interim.

The UK payment on UK tax regime enables you to forecast your capital investment and tax allowances and offset in determining your tax payments on account. Accordingly the cash from the trading profit never leaves your bank account and is available to fund capex without resorting to bank debt. Clearly this only works if your cap exp is lower than your taxable profit and I cannot see anywhere near a $1b per year cap expenditure (probably closer to $300m per year if we progressed either Bentley or Bressay.

Romaron

You are correct that the government funding 92-95% of the cost of investment only works if you an existing operator making a profit and are paying EPL. This does not work for new start ups. However Enquest is currently making over $1b EBITDA which is a reasonable proxy for taxable profit pre investment allowances and as long as oil does not drop back to Covid levels, the investment allowance will fund over 92-95% of the capital costs.

There is a slight anomaly with Enquest because of the losses carried forward that we will only get 45% of capital cost offset in year of investment and balance carried forward until we have used current losses which is probably 2025.

Of course if oil drops to $40 per barrel we will not be paying much tax at all and Enquest will likely be taken over by bond holders.However I really cannot see oil going below $75 for any sustained period with the future supply and demand imbalance, US shale not over investing and OPEC’s determination to stabilise prices at $80 plus.

The maths are pretty simple Romaron - the greats unknown is whether the investment allowance will be curtailed by next labour Government and it is probably this uncertainty which will curtail investment.

I really can’t see how Bressay and Bentley would not go ahead if the government are going to fund somewhere between 92-95% of the cost of development.

Using an example of a 100m barrel field which costs $1b to develop and generating 30k BPD at anOPEX of $25 per barrel with oil price of $75 per barrel over field life.

Pre EPL the company would have to fund $550m of the development costs (45% tax allowance on $1b capital cost) and would generate post tax cash flows of $300 per annum ($500m profit per annum at 60%). 22 month pay back

Post WFT the capital costs for the company to fund will be close to $50m with some green elements and the post tax cash flows will be $125m ($500m at 25%) per annum. 5 month pay back.

Additionally there will be no need for bank funding under the post EPL scenario. Accordingly if there is trust that the investment allowance will remain in place, then it is a financial nobrainer that Rosebank, Cambo, Bressay and Bentley to get developed. However given Labour have expressly stated that they intend to remove the “investment allowance loophole” and are highly negative to fossil fuel development “100% renewables by 2030”, a change of government will see a change of policy.

Accordingly if you can spend the money in 2023 and 2024 then go ahead, if not, you need to wait until policies of next government are clear in 2024/25.

There is currently a review on North Sea taxation ongoing by the treasury which is due to report at end of 2023. The mandate is to look at a long term sustainable and equitable way of taxing North Sea oil to maximise energy independence and protect the consumer.

The project has just started consultation with industry bodies, companies and tax advisors and is considering a number of options such as a variable tax rate depending on oil and gas prices realised. It is also looking at potentially long term contracting with O&G companies to buy oil and gas at fixed price for several years in advance which would remove the need to hedge and provide increased certainty to the industry and consumers over pricing.

I think this would be the only realistic catalyst to remove the current EPL and tax system and replace with a wholly new and well thought out approach.

Equally it could be a smoke screen so the O&G industry does not mosh too much about current 75% tax on profits that will more likely than not normalise in 2023.

The best proxy I can find for valuing Tailwind is Enquest. Enquest is principally Oil and has 3 times the annual production of Tailwind, 5 times the amount of 2p reserves, debt is about 3 times higher and Enquest operating costs are $10 per barrel lower. Enquest carried forward tax losses are also 3 times higher than Tailwinds.

What value does the market put on Enquest reserves after adjusting for debt - $6 per barrel excluding debt and $2.5 per barrel including debt. This is very similar to market value of Serica’s reserves on a per barrel basis.

We are proposing to pay $18 per barrel for Tailwinds reserves after adjusting for debt (assuming debt has not been reduced since 2021). If debt has been been fully or largely paid off in 2022 (highly unlikely as I am sure big dividends will have been taken) then valuation drops closer to $10 per barrel.

Accordingly looking at market indicators of value per barrel of reserves, this deal over values Tailwind by 2-3 times depending on debt repayments in 2022.

Should also note that 2023 oil is hedged $13 per barrel higher than 2022. 2023 gas hedges slightly lower than 2022 and about 20% of average gas prices for 2022 (40p per therm vs market p[rice of over 200p per therm).

Profit for FY2022 would have been a little over $2b higher without the gas hedges alone. We will not see much benefit in 2023 but if gas prices hold there will be bumper profits in 2024. Better oil hedges in 2023 adds $250m to bottom line

Thankfully the tax losses from premier will provide a shield against normal 40% tax in 2022 and 2023 but my calculation is that the EPL cash charge will be $900m higher in 2023 than the $200m paid in 2022. This assumes approx $800m of UK capital expenditure in 2023. Therefore if O&G prices remain at similar levels and all other things being equal, this would result in $1.3-1.5b of FCF which will be sufficient to pay down debt and fund increased dividend.

In 2024 if gas reduces 50% to 100p per therm, FCF will still benefit by $1b from increased gas revenue but as tax losses are used up our tax charge will increase by a similar amount.

Accordingly a medium term FCF of $1.3-1.5b with EPL in place. Can the government keep the EPL if gas prices fall to 100p per therm or 3.5p per KWH which is lower than pre war and oil in mid $80 pbbl. I can’t see a labour government reversing it and I doubt Tories will either.

Just to be clear $1.3b of FCF could fund £1.3 per share annual dividend or more likely a combination of increased dividend and overseas investment. Cutting back UK investment has no great benefit as UK gov funding around 95% of Cap Ex and we get to keep 25% of profit.

Other views very much welcomed.

The cost of wind energy for an offshore location has fallen from approx 12p to 7p per KWh over the last 4 years.

The cost of imported gas this week is 6.5p per KWh (a little under 200p per therm) and while gas prices did peak at approx 17p per KWh this year, it was only for as short period and have averaged a little under 200p per therm for 2022. If you looked at the average for the last 3 year the cost of imported gas has been closer to 3p per KWH.

Coal is currently 4p per KWH and oil is 5p per KWH.

All of this information is readily available and is being ignored by Labour and the press.

Hickster

If you look at the deal from a future cash flow perspective Tailwind’s cash cost per barrel if approximately $45 per barrel excluding any debt repayment (opex+admin+interest+royalty/deferred consideration). At $75 oil which looks like a reasonable medium term market expectation, this yields $30 net cash per barrel or $7.5 after tax and excluding the benefit of tax shield.

There are decommissioning costs which are approximately $2 per barrel of reserves at present which brings us to approx $5.5 per barrel. Assuming 40m barrels remaining this would have a gross undiscounted value of $220m. These cash flows will arises over the next 8 years and a discount value would be in the region of $110m. I would add to this the value of the tax shield of $240m providing a debt free acquisition price which would be value neutral to Serica of $330m or about $100m for the equity after debt.

Accordingly Serica is paying over triple the maximum value you would place on Tailwind reserves assuming long run oil prices of $75 per barrel after impact of WFT. While we have had a strong oil (and gas) price environment in 2022, I note that the super majors are all using a conservative $55-60 oil price expectation to evaluate investments.

I don’t think I have seen a worse deal in NS history. The additional WFT payable by Tailwind at $10 per barrel ($30@35%) has a major impact to deal value, not just for this transaction but for all deals to buy producing assets. While the tax environment is horrible it does incentivises the development of new fields rather than buying producing fields. Why buy an operating field for top dollar when the government will cover around 95% of cost of developing a new field?

My gut feels is that the reduction in value of Tailwind reserves as a result of WFT has not been factored in. You can say that it equally impacts Serica and Tailwind and that is true. Except that Serica has approaching £0.5b in cash and Tailwind £0.25b of debt which is not impacted by WFT.

Email address for correspondence with Mitch. info@serica-energy.com

Shakey

I calculated the cost per barrel from 2021 financial statements. operating costs were $166m (note 11 of financial statements) and total barrels sold were 5.1m (14,000 per day). This excludes depreciation of production assets which would add another $20 per barrel. Accordingly all in production costs are $52 per barrel and admin and interest a further $8 per barrel.

Royalty, deferred consideration and decommissioning adds a further $3.5 per barrel. This results in an accounting breakeven of $63.5 per barrel which must be highest in North Sea.