Member Info for Stevo12

Auson

Apologies for typo. I meant Enquest’s loan note yield would fall to the same as Harbour’s on merger (approx 6%). The yield on Harbour’s debt is determined by the debt market as is Enquest’s which is currently yielding over 10%.

Enquest can not force the loan note holders to sell. The 2027 9% listed loan notes are currently selling at 91p and would increase in value to say 130-140p following acquisition by Harbour or other acquirer with better credit risk. Accordingly Harbour would have to pay a significant premium over the $600m of nominal value of loan notes to redeem them.

The RBL could be repaid at any point.

Apologies typo. Enquest NS entitlement 30k BPD and Malaysia 4k BPD giving total net entitlement of 34k BPD

Kraken

Enquest production entitlement is 34k bps from NS after adjusting for BP’s 37.5% entitlement to Magnus production and 4k BPD from Malaysia after PSC. Total Enquest net entitlement 34k per day compared to harbour 190k BPD net entitlement (5.6 times higher). It is the market cap which is 6.6 times higher.

Auson

Harbour loan notes do not mature until 2027. If Harbour acquired Enquest the improved credit rating would result in the yield of the loan notes (currently 10%) reducing to closer to 6% (harbours debt cost) and the market value of the loan notes would increase. Accordingly loan note holders would not agree to redemption unless a significant premium about nominal value was offered.

Sekforde

Agree that there are real synergies to unlock from a merger with Harbour. However could you share your thinking on the potential share for share ratio given harbours market cap is 6.6xs that of Enquest. Also their production is approx 6 times higher with almost no debt and Opex $10 per barrel lower than Enq.

Unfortunately the benefit of lower interest due to Harbours credit rating would not materialise until 2027 when the various loan notes mature. The acceleration of the tax losses would be principal benefit of merger.

Realistically if Harbour want Enquest they could probably gain control at 22-25p per share.

Dumbly

I do not believe there has been a change and EPL was always payable on sale of producing fields - i just did not realised it. It was however narrated in recent tax update by stating that if the sale is part of a repurposing for CCS then EPL is not chargeable on asset sale.

As noted previously this can i believe be avoided by selling the legal entity which holds the field but this would not be possible if the legal entity owned multiple fields and the intent was only to sell one.

Nice to have some good news and a much better FCF than I was expecting. I had modelled an increase in debt at 31 October, from 30 June, of approx $40m, as compared to an actual reduction of $6m. The improvement is principally a result of lower Opex ($25m) and lower EPL payment ($15m). We should now see net debt at year end of approx $40=50m lower than at 30 June as opposed to flat. Good news indeed and hopefully the reduction in Opex is real as opposed to pushing costs into 2024.

Production was a little lower than i expected for Sept and October but cash flow strong with high oil price.

I was hoping but not expecting some statement on shareholder return timelines, but nothing new i am afraid.

Not sure why, but Kraken is not included in the paper!

Romero

Have a read of following report. There are 5 heavy oil fields producing today with Captain being the most recent with the highest viscosity at 88CP.

https://itportal.nstauthority.co.uk/information/papers/spe54623.pdf

Kraken

Correct.

Romaron

The review does not define how post 2028 WFT would would actually work but states that it could be a revenue rather than a profit based tax. The review states that the actual mechanism would be announced pre 2028 but would not apply to “normal” profit.

In terms of the final point in my prior message - which worries me - If Shell/ BP were to sell a producing field to ENQ for $100m they would pay $75m tax on disposal. This would likely mean less of an appetite to sell producing fields. However I think it could be avoidable if you acquired the company holding the field as opposed to the field itself. This will not always be possible if the legal entity holds multiple fields unless you buy them all.

I have had a good read through the fiscal review and my conclusions are:

1. Interesting that EPL floor price will be amended each year, presumably linked to inflation in some way. No indication about separating oil and gas prices in the floor.

2. Commitment that future WFT post 2028 will only tax the windfall and not the normal profit.

3. Some interesting points around repurposing O&G assets to CCS. Costs not allowed against EPL but will benefit from higher decommissioning allowances.

4. Very generous allowance for spend on decarbonising O&G platforms/production reconfirmed

My thoughts

1. Irrelevant unless Labour buys into the proposals.

2. O&G sectors evidence submission largely ignored

3. However my biggest concern was a reference that EPL is chargeable not only on oil production, but also on sale of producing O&G assets. Given that the tax base of O&G assets is zero (due to initial capital allowances), there will be a 75% tax on the sale proceeds of producing reserves. This is going to make sale of producing assets much more difficult and uneconomic. There are potential workarounds if the asset are in a separate legal entity but could make deals like Magnus much less viable for seller.

My understanding is that the ECT is only applicable to international investors and would not be relevant to UK domestic business such as Enquest, Harbour, Ithaca etc. However there are overseas businesses invested in NS (particularly US) who could possibly use ECT for compensation.

Romaron

Offshore wind is like the emperor’s new cloths in that it only takes one county to call it out and I would hope other would follow. The economics are becoming increasingly visible and the assumption that costs would continue to decrease have now been laid bear with the 66% increase in price guarantee to be offered to offshore wind next year.

We know the real problem is the intermittency and that you need a second, duplicate energy system to kick in when wind fails. Battery storage just does not work at an affordable level and again costs are rising not falling. Hydrogen/ Ammonia storage has energy losses of over 60% and the wind capacity would have to be double to treble that needed with gas powered as the backup.

The separation of electricity prices from gas fired power stations and renewables will increase visibility - hopefully to be announced soon. The reality of these challenges can not be ignored in the long term even if political dogma is currently standing in the way. My guess is that it will get called out in the US first but I would not be surprised if Germany does a 180 on its nuclear policy.

I can just hear the side discussions at Davos next year “how do we tell Joe Public we F*ck up”.

Romaron

It’s not the price of the offshore wind that is going to hit consumers. It’s the cost of the backup system for when the wind does not blow (be that battery, Hydrogen or Gas fired) and in the Uk that is intra-day and for periods of up to 10 days in a row. Then there is the huge investment in transmission that we will be needed to get the electricity from offshore NS to homes and businesses around the country. This will make HS2 look like building a train set. We then have balancing costs in an electricity system which need to be immediately responsive to demand.

You add all these costs together and it will result in a 2-3 fold increase in energy costs for businesses and consumers. The government might cover some of them without recharge but they are still real costs and would have to be funded through general taxation.

As a species we have progressed by replacing old technologies with new technologies that are more efficient and cheaper. We moved always from burning wood and dung because coal had a higher energy density and was cheaper, we moved from coal to oil and gas for the same reason. The only logical next step from hydrocarbons is nuclear and we simply need to make nuclear more repeatable and cheaper. Wind is a scam and offshore an even greater folly which will impoverish Britain and drive industry overseas.

I sense this is becoming more apparent to policy makers and Germany has really backed itself into a corner which will result in the demise of its industrial base.

Dumbly

1. That way the investment allowance works is that for each $100 of Capex the EPL is reduced by $46 and the core tax is reduced by $45. Accordingly due to our tax losses, Enquest will have to cash fund $54 per $100 of capex until the historic tax losses are used (not for several years and the tax losses will be increased due to the investment allowance). ENquest will have to borrow to fund B&B and interest will not be allowable against EPL. Accordingly very unlikely that Enquest could even consider B&B investment. New field development only really works for companies with small or no tax losses.

2. Buying existing producing fields is the most likely route as values have dropped because of EPL and Enquest can use its losses. Enquest will likely be looking for some form of vendor funding similar to Magnus with limited cash up front. I would be supportive of buying discounted 2P reserves, use losses and wait for EPL to be amended.

3. Unfortunately i can not see shareholder returns until debt down to $250-300m towards end of 2025 or early 2026. This is based on an $85-90 oil price. Oil at $100 average in 24 and 25 would bring this forward by 6-9 months. I am going to be interested to see whether any updated shareholder return guidance on next RNS or year end results..

I am hoping the tax review provides a much more equitable regime for all parties which means that while we still need hydrocarbon’s in the UK, we meet as much as the demand as possible from NS resources. Even the IPC and UK CCC (who are pushing for the fastest transition from hydrocarbons as possible) recognise that oil and gas will make up a minimum of 20% of Uk energy needs in 2050.

I would personally be in favour of a new UK energy entity (gov body) buying all uk produced oil and gas at a fixed, inflation linked price (similar to wind farms) which would remove volatility for consumers, remove need for hedging and move O&G to normal UK tax rates (25%). How you set the price is the question and could be based on license bids for new fields. Not sure about how you set a fair price for historic fields.

This would be easier to apply for gas than oil as the vast majority of UK gas is used by UK consumers.

However just certainty and predictability of the current regime would help. On the face of it, an environment where the operator has to fund 9% of capital costs of a new field and keeps 25% of operating profit is not wholly unattractive if it was certain.

Personally I think wind and solar are an unaffordable indulgence and will be revealed as such in due course. I just hope we have not bankrupted the UK before their inadequacy are understood. Nuclear, Geothermal and Hyrdo are the only real predictable and useable renewables and we are no where near developing these real alternatives to Hydrocarbons which will be with us for many, many decades to come.

Aimoil

We need to set realistic expectations for the November update which will probably include a net debt position at end of October. The net debt will most likely be higher than at 30 June 23 due to Golden Eagle and EPL payments of $125m. Neutral to small negative FCF for 2nd half of year looks likely and this will be the pattern going forward with EPL payments in October of each year. Subject to changes in oil price, we should see strong cash flow for Jan to June each year and neutral to negative in second half year. EPL is an effective 50% of FCF for Enquest and paid as a lump sum in October. We know the EPL payment is $75m in Oct 2023 relating to 2022 (7 months at 25%) and will likely be double in 2024.

We just need to set realistic expectations for the November update and hopefully production will have remained in the higher end of the 42-46k range. My gut feel is that without any purchases of producing fields, we will be generating $150m of FCF per year ($300m pre EPL) at $85 oil and it will take us a couple of years (24 and 25) to get debt down to target levels of $250m ish.

Generating close to 50% of our market cap in FCF per year is not to be sniffed at and should drive a meaningful appreciation in share price over 24 months.

Enquest is definitely not going bust with its debt secured until 2027. The only risk is that if oil fell and remained at sub $70 for an extended period which would require CapEx to be cut to service debt. However at this level EPL would falls way.

In reality oil would have to be in $50-60 range for an extended period to threaten ENquest’s

survival.

This feels a low level risk and would require a black swan,

I have simplified it in my mind in that for the O&G companies paying full tax, the O&G operator funds 9% of the CapEx (after tax refund) and gets to keep 25% of profit for field life and then pays 50% of Decom costs.

If labour continued with the 121% “super allowance”, I still think NS investment works for companies with no debt and paying full 75% tax. This is clearly not Enquest and so agree Bressay and Bentley unlikely to be developed in the near term.

Not quite. You pay $100 out in Capex and the government reduces your tax bill by $91.

It is the 121% Capex inflator that labour were challenging. If removed it would mean that the tax allowance would be $100 (not $121) and accordingly the tax bill would be reduced by $75 for each $100 of Capex.

If the 121% Capex inflator remains during the Rosebank Capex period, Equinors EPL and Core tax would be reduced by $4.55b and they will fund net $450m of the development costs. Assuming 60k bpd of production, $25 Opex over field life and average Oil price of $85, Enquest would generate 60,000*(85-25)*365*25% = $328m pa FCF as compared to the $450m invested - payback of less than 18 months - pretty attractive. If the 121% Capex inflator was removed by labour, Equinor would have to fund $1.25b and the pay back would be 4 years - not so attractive.

The capital value of Rosebank would be approx 5 times FCF (using BP and shells valuations) once up and running which would be approx $1.6b (assuming 75% tax continues post 2028). Accordingly I can not see a third party paying more than $250-300m for 20% stake if 75% tax continues indefinitely.