Member Info for londoner7

Voiceofreason1, good spot.

A $300m bond replacement sounded right to me, alongside an RBL. Let's see how the issuance plays out.

From Moody;s
"London, October 10, 2022 -- Moody's Investors Service ("Moody's") has today placed on review with direction uncertain EnQuest plc (EnQuest)'s B3 corporate family rating (CFR), B3-PD probability of default rating (PDR) and the Caa1 rating assigned to the backed senior unsecured high yield notes due 2023. Concurrently, Moody's has also assigned a B3 rating to the proposed backed senior unsecured bond issuance due 2027. The outlook has changed to ratings under review from stable.

EnQuest seeks to fully refinance its outstanding senior unsecured notes due October 2023 through a combination of new senior unsecured notes, drawings under its Reserve Base Lending facility (RBL) and available cash balances. Moody's review will focus on the timely and successful completion of the planned transaction, after which the CFR could be upgraded to B2 and the PDR to B2-PD. On the other hand, failure to timely address the upcoming bond maturities could lead to a downgrade of EnQuest's ratings because of heightened refinancing risk."

"The company will have access to an amended and restated $500 million RBL (including $75 million letter of credit-sublimit) which is projected to be largely drawn at closing. The RBL contains a net leverage covenant (set at 3.5x) and a liquidity covenant testing the company's sufficiency of funds for the next 24 months. Moody's expects EnQuest to retain sufficient headroom under both covenants."

I wonder if there is a hedging requirement?

Good to see the shareholders winning out over the CNE board. The proposed tie up with TLW looked a poor deal for CNE shareholders.

Perhaps the CNE non-execs fulfilled their duties, though I see the CNE executives still manged to get their snouts in the trough. I guess that was always going to be a consideration to get an alternative deal through - evidence of the ongoing mismatch between board execs and shareholders.

I never expected the award from India to materialise, so I saw it as a bonus when it finally happened. But CNE had previously announced that they had funding in place to support their NS producing assets and finance development in Senegal, so any award would be returned to shareholders in its entirety. Prospects looked good, unfortunately:

Strike 1 – the decision to exit their North Sea assets and enter Egypt.

Strike 2 – only c50% of Indian Award was returned to shareholders – looks like Tullow shareholders will get the balance

Strike 3 – the agreed merger (by management if not shareholders) with Tullow.

I had been reducing my holding in CNE since the decision to sell NS and enter Egypt, but on strike 3 I sold out completely.

Once out I rarely go back, but I viewed the recent interim results presentation. I was struck by slide 9 which listed the contingent considerations resulting from recent M&A. It prompted me to consider where CNE would be now but for recent management decisions.

Strong cashflows from Catcher and Kraken.
In 2019 CNE had $373m of cash flow from these assets @ a Brent average of $64.
In 2021 CNE received $306m in cash flow from the UK disinvestment and earned contingent consideration of $77m, which Waldorf paid this year.
Waldorf, with their interest back dated to Jan 2020, had fully repaid the cost of acquisition by end 2021.
In 2022 Waldorf has production of c.16K boepd priced at $100. That’s $580m in revenue and c$300m after operating costs and a 25% windfall tax. Leaving c$200m in cash flows after an expected $100m contingent payment to CNE.

Asset 1, Management 0

Senegal development 63% complete with first oil due in 2023.
By my estimate at the time (I don’t recall the detail) CNE sold out at a loss on their investment. A possible $100m contingent in 2023 might get them to breakeven.
Woodside took up pre-emptive rights to acquire the sale (c36% WI) and now have an 83% working interest in the Senegal development. Transactions were dealt in a $60 oil environment – I guess that’s where CNE expected prices to remain. Over the first year of production Woodside may see cash flows above breakeven ($41) of 36K boepd * $60 poo * 365 = $788m from their pre-emptive purchase from CNE.

Asset 1, Management 0

I have investments in the assets, Catcher, Kraken and Senegal. The CNE management I leave to others!

It’s good to hear institution investors speaking out against the Tullow merger, but I wonder how much visibility they will have of the current discussions on ‘alternatives’. Management will decide under cover of confidentiality agreements. Will their decision be in the interests of CNE shareholders? I hope the non-execs take their duties seriously.

I’m not familiar with Tullow, so I don't have a view on their assets or management, but I wish CNE investors well in the outcome. I’ll be watching from the side-lines.

Reflecting on the recent HBR and Ithaca updates I was struck by how low their realised gas price was in H1 compared to the 'month ahead' prices we often see reported on the news.

I suspect the company's realised prices are more reflective of 'day ahead' pricing and perhaps includes some smoothing, say last 5 day average - I'm guessing now.

I estimated the 'month ahead' pricing to be c.230p average in H1, but HBR stated a realised price of 176p, which is more reflective of the 'day ahead' price data I've seen.

The relevance to Enquest is that it prompted me to look back at a post here a couple of weeks back and make a correction.

I said, "Breaking down the 2021 numbers my estimate for gas is that Enquest sold 1,398 boepd (c3% of reported production) @ $86 boe, for $44m.

For 2022 using 1,400 boepd and a price of 250p/therm for H1 and 400p/therm for H2 (pick your own numbers). This leads to c$50m in H1 and c80m in H2."

Using HBR's 176p/therm I now see H1 gas revenues (excluding 3rd party purchases) at c.$32m.

* The debt ratio is NET debt to EBITDA and AB has mentioned a target of x0.5 but I don't recall any August target. I can see bond debt up to $500m in alignment with the 0.5x target. In practice gross debt may be a combination of bonds and RBL drawdown, assuming an RBL is still in operation after restructuring. In any event c.$150m of bond debt is in place out to 2027.

But what is the current EBITDA? The latest update implies $880m. Is that H1x2 or H1 plus 2021 H2, i.e. rolling 12 months. But EBITDA isn't my focus. I want to see bond restructuring complete, thereby easing market concerns on debt and substantial FCF, which is what's left after CapEx, Decom, law suits and other stuff is deducted from EBITDA.

Another $35m to ease any ongoing credit discussion.

Is Enquest delaying Kraken shutdown? The latest update was unclear.

"The Group continues to assess optimisation opportunities for the planned shutdown scheduled in the third quarter of 2022."

My read-on Hugo Rifkind’s article: the mistake has been avoiding the boggling costs of offshore wind and nuclear. His conclusion: build it now, build it all.

The backbench conservatives he refers to represent a wing of the party which will die out over time – the sooner the better!

A key message I took from Rifkind’s article is that there are always arguments, financial or otherwise, not to progress to a decision on long term projects, and politicians, given their short lives on the front line, have been able to duck those decisions.

When I hear Ed Miliband barking on about the current energy crisis, I wonder what he was doing as Secretary of State for Energy and Climate Change between 2008 and 2010. It seems not much.

The only positive I take from the article, “Rush to drill for more oil in the North Sea” is that at least ‘government’ is talking to the oil companies, people that can make a difference near term and longer term. Let’s see what comes of it.

Today, Ithaca Energy released their interim results. Ithaca is a private company but I follow their updates because there’s good read across to my North Sea investments.

Several items caught my attention but the most topical is the Energy Profits Levy. Ithaca had no complaints about its objective, terms or implications.

The CFO presented some maths relating to the EPL allowance which surprised me, but he will know more about such detail than I. Given the Capex schedule already in place he expects Ithaca to be paying about one third of the 25% levy in the near term and none in 2024-2025.

Like Harbour last week, Ithaca said that they don’t currently see any change in their Capex plans out to 2025, which would utilise more of the EPL allowance. However, I’d guess over time there’ll be a tweak here or there. I’d imagine a key factor in future assessments will depend on the outcome of the next general election.

Understandably, Enquest’s recent focus has been on debt repayment and restructure. Aside from continued infill on Magnus and in Malaysia and new drills on Kraken in 2023 we know little about Enquest’s CapEx plans out to 2025. Perhaps we’ll hear more next week. but my expectation is for a significant update after the bond restructuring.

It was refreshing to hear the Ithaca CEO answering questions in a free and easy manner. Quite the change from the guarded responses we get from Enquest in Q&A. Ithaca are looking at a possible market launch in 2022 and I’ll be looking them over.

What does Jude Lagan, Managing Director - Breedon Cement see that prompts him to add to his holding?

Breedon's share price can't withstand market forces but nice to know (I assume) that Jude Lagan sees good operational performance within Breedon.

Short termism at its worst. Big Covid bill to fund so let’s pay for it with an increase in corporation tax from 19% to 25% while incentivising business investment, aiding growth. Another proposal that no doubt looked good in the briefing papers.

The background to this is that the business argument for reducing CT to 19% was that it would encourage business investment. It seems the tax saving largely went to exec bonus and shareholders will little additional investment. Sunak’s solution – a policy with greater focus on the desired outcome. Not a bad idea in principle, except it was implemented in haste over a very short time frame in a period when supply chains were already tight. A bad idea in practice.

I invest in a company which has great scope for capital investment, and I latched onto the benefits of the 130% STD straight away. However, it only applied to investment decisions made after the March budget day it was announced and run for only two tax years. 'My' company announced an additional £30m (above £140m planned) in Capex in direct response to the 130% STD but couldn’t spend it in the first year and are still struggling to get the kit. (Incidentally, the allowance will knock 3% of this year’s CT bill.)

No doubt briefed on the implementation issues Sunak was talking of extending the STD beyond April 2023. We’ll know soon if he gets the chance.

However, it appears Truss is the front runner. I hear her plan is to cancel the CT rise to 25% - lovely jubbly!

I also hear that there are public concerns with the level of energy bills, which are growing so deafening that little else may be heard. In such an environment bold action will be needed and Truss strikes me as a lady that enjoys a bold response. Whether she can implement the required policy action is more open to question.

The current price of UK gas is c. $400 boe and the futures has it at >$600 boe in Dec. There is no way that poorer households will be paying £3,500 p.a rising to £6,000 in the spring. That demands a political response. There’ll be some financial wizardry, but I believe a key action of interest to this board will be an action to increase North Sea oil and gas production, perhaps with focus on gas.

That action could come in many forms, but it would be surprising if there wasn’t a net benefit to companies operating in the North Sea. Of course, this assumes that Truss can implement the necessary policy action – in her favour is the public focus on those energy bills. (I’m in favour of higher bills across the spectrum to incentivise a reduction in demand and a NS policy response.)

Another possibility is that a black swan poops on the Truss government before Christmas. The socialists gain power and BG gets his additional windfall tax. Having heard the oil industries claim that the 91% allowance doesn’t incentivise new investment he’ll probably scrub that too.

Place your bets.

romaron, the 130% super-tax deductible is a red herring as far as oil companies are concerned, but why should that stop a politician.

The invitation of the oil execs to the audit was largely for political show – note the attendance of the sidekick from an ESG NGO to help steer the theatre. BG was setting the ground for larger windfall tax demands and CL was reinforcing the green message of energy transition now – she had her clipped video feed capturing her ‘moment’ out on twitter within minutes. The oil execs can only try to get through it as best they can, but in that environment, they’ll never match an experienced politician. I thought they did a good job apart from Cook’s blunder suggesting HBR doesn’t have the skill set for aspects of the transition. Something she tried to put right on CCS last Thursday.

Of course, BG’s comments on tax were ambiguous but that wasn’t the forum for clarification. That will come with follow up written answers to the full select committee. (One obvious response is around the differences between the UK and Norway on tax implementation. Norway front loads their support at the exploration stage with higher taxation at the production phase – the merits of Norway’s route seem obvious in hindsight)

I haven’t heard any oil companies talk of the 130% STD, but they weren’t Sunak's intended target. The short implementation period is a big disadvantage to the oil sector. I might follow-up on the STD later.

In yesterday's call Cook made her views on the Energy Levy very clear and I thought she expressed the real world challenge of utilising any allowance in the short term very well. I'm sure Sunak's briefing paper was less reflective of those real world challenges. Of particular note were her comments around a three year schedule of anticipated CapEx spending, including the Talbot field in the NS. While these were all put in place ahead of the Energy Levy, they will still benefit from associated allowances. On a very rough calculation I estimate a gross additional 25% tax on profits in 2022 due to the Levy would be c.440m, so netting off $300m net suggests a $140m allowance benefit. As I say, very rough estimates, but one has to start somewhere. However, I expect the final 2022 outcome to be higher - it's all about the gas!

I'm hoping for a similar level of Levy guidance from Enquest on the 6th Sept. However, based of recent comment from AB I expect him to be more engaged with the prospect of new works to take advantage of the Levy allowance. I've commented on this before - it may be too soon to be specific today but I do expect some indications at the finals next March.

That said, they are also prospects in Malaysia. I'd guess Breesay is a post 2025 spend. (I know the Kraken FPSO has been put foreward as supporting infrastructure for Bressay but I'm coming round to the view it puts too many eggs in the Kraken basket)

But before any significant additional spending I'm sure AB is laser focussed on getting the debt level down to c$500m gross.

It was interesting to see the trading update on H1 ahead of the interim results. Not normal practice. I've also noticed some indecision around the 6th Sept date. On, then expected in Sept, then back to the 6th. The good cash flows, with the prospects of more to come, will have increased Enquest's credit options, and whatever the final outcome I'd be surprised if it isn't taken positively by the markets. If the restructure trigger isn't pulled on the 6th I'm happy to wait a few more months.

I was struck by the UK gas pricing achieved by HBR, 176p in H1, against what I roughly gauge was a 210p futures average. In a post last week I said I wanted to see what Price HBR had achieved in H1. Given the summer UK gas market and the higher demand from Europe I think I have a handle on the reasons for the price discrepancy.

However given the current sky high pricing this discrepancy is little more than noise. It matters at 200p but less so at 600p.

Banburyboy, you touch on two points: the hedge pricing and ‘satisfying’ hedges.

Hedges are financial instruments which operate independently of the marketing/sale of produced oil and gas. The hedges will typically be at monthly intervals through the period, sized against anticipated production volumes and credit requirements. During H2 HBR has 12.45 mll boe gas hedged at an average of 50.6p/therm. If the difference between the current gas contract and hedge price is 500-50= 450p/therm, this equates to c $300 boe. If the H2 hedging is spread equally through the period, then a contract loss is paid each month for c.2m * $300 = $600m. The CEO explained why HBR needs a substantial cash balance each month ($844m end June) to close these contracts. Of course, the cash flows back later in the month from production sales at the high gas prices.

To be clear, HBR could speculate on pricing and close contracts early but that would be a very unusual action for an oil company. (Market expectations will be captured in an adjustment to the premium – the bet would be against the market)

To the second point, hedge pricing. I’d already done the maths on the hedging earlier today. The maths is easy, so I’ll skip through the steps.

The numbers we need are in the interim data. 42% of H1 production was UK gas – 42%*211K*182 = 16.13 million boe.
Backing out the H2 hedging 12.45m @ 50.6p) from the FY hedging 25.4m @46p, leaves 12.95m @ 41.6p hedges utilised in H1.

Here I conducted a check on my process. Using 176p on unhedged (16.13m-12.95m) and the hedges results in a realised 67.8p. HBR quote 69p, so I’m happy with my process.

If we assume same again (H1) gas production in H2 (16.13m) then unhedged UK gas production is 16.13-12.45 = 3.68m. However, HBR has guided to higher gas production in H2. I’m working with +7% over H1. That would be ((1.07*16.13)-12.43) = 4.83m un-hedged UK gas in H2.

I think that answers your question.

* HBR has supplied a useful FCF sensitivity formula, but that assumes a specific level of production. (This will include some sort of ‘fiddle factor’ for international gas). Given the very high gas price and the relatively low % of unhedged production a relatively small change in UK gas production would have a significant impact on FCF – up or down (note the impact of the 7% change above). Watch production numbers from NSTA. HBR will be laser focused on maximising UK gas production at current gas prices. I think I heard Tolmont is currently producing 42K gross – a good start!

Guys, your interpretation of slide 19 is wrong.

Consider the footnote, " FCF is free cash flow after capex, tax and before shareholder distributions (dividends and buybacks) and assumes FY 2022 oil and gas prices average $100/bbl and 200p/therm respectively"

The sensitivity is based on the average over the full year. Also, consider HBR posted 176p for the UK gas market price in H1 - slide 16.

The results are great and the gains from the current gas price will be very significant if the price holds. Just not of the order you are calculating.

Hi Banburyboy, my holding is more modest with about 5% of my portfolio invested in HBR. I don’t monitor their operational detail closely. The main case for my investment is a personal hedge that gas prices will remain elevated for several years and as HBR’s current low-priced gas hedges unwind cash flows will grow appreciably. HBR has a sufficiently diverse portfolio of assets that I’m relaxed about any adverse impact resulting from a significant problem with any individual field. Almost a buy and forget holding, but I still look closely at any trading updates.

Also, I don’t follow this board closely, but I found your post interesting with what I think is good coverage of key aspects of the upcoming interims. My views:

1 – I guess you mean ‘net debt reduction’ will be impacted by the items you list. Free cash flow is utilised to pay down debt, pay dividends, buy backs and reinvest in the business. In Q2 the dividend payment was $100m, with the 2nd $100m due to be paid out in H2.
2- I agree. I don’t know the CapEx schedule but clearly Q1 was light and Q2 is likely to be substantially higher.
3- I agree – I expect Q2 production and pricing to be similar to Q1. The utilisation of oil hedging in Q1 seemed representative for the full year, but there could be some change in weighting in Q2.
4 – I link this with 3.
5 – I haven’t checked your numbers, but I don’t understand your comment ‘With guided production reduction overall revenue could be static’. (I’m assuming you are now referring to the rest of 2022 rather than just Q2, otherwise it seems to me you are repeating points 3&4). Q1 actual was 215boepd and guidance is 195-210boepd. Guided reduction is small but what I find interesting is the narrow range on guidance. Either their guidance is poor quality, or they have great confidence in the reliability and predictability of their operations. Time will tell. However, these factors are significantly outweighed by the increase in revenues from the recent rise in the spot gas price – if it holds. Even with 2022 gas largely hedged the impact of 400p/therm against say 200p/therm on unhedged volumes in H2 is huge.

A key number I’ll be looking for in the interims is the realised price pre and post gas hedges to determine just how sensitive HBR is to the spot gas price. That will help me to quantify ‘huge’.

I’ll also be looking for guidance on full year and longer-term impacts from the windfall tax.

Finally, I believe their debt agreements will require additional hedges. Those numbers will be interesting.

* As I post I see BH has replied to your points too. I note he has picked out the div cost and includes stuff that is beyond my knowledge of HBR so I’ve nothing to add. Though, I agree that cash payments on the windfall tax are for next year.

externaltothebox, the numbers I present are my estimates of cash flows from gas production, but I qualified them with operating costs solely attributed to oil production. Also, I should add that BP receives 37.5% of free cash flows from Magnus.

The numbers don't strictly represent gas free cash flows to Enquest. They are a construct to get me to an overall estimate of free cash flow for 2022 - oil and gas combined, with BP getting 37.5% of the Magnus contribution.

mrc, thanks for the clarification on Magnus fuel – diesel not an option.

Kraken power plant is also split between two generators. Yes, the generators typically burn diesel. But given the production of c800 boepd of gas and no gas export option, it is a waste not to use gas fuel if there’s the option. IR have told me that gas volumes are insufficient to fully support production – my interpretation is that no gas fuel is used.

I’m sure the NSTA monitor the situation and would insist that gas is used as fuel rather than flared if that’s possible.

externltothebox, you can extract gas production numbers from NSTA data – several posters here log the data and post excellent spreadsheets. Your 5% number for gas production is a reasonable estimate.

But most of Enquest’s produced gas comes from Magnus and a substantial part of that is used to fuel the facility. As you note there is also gas ‘passing through’ Magnus. This is gas contracted to be injected into the field but now not fully utilised and therefore passed through the export pipe for sale. There has been discussion here on any benefit to Enquest from these ‘passing’ volumes, but my conclusion is that it is effectively neutral. Gas volume sales account for 15% of total volume sales in 2021, so c10% of total sales represents contracted purchased volumes into Magnus)

As an investor, my interest is in the net cash flows resulting from gas. In 2021 subtracting the contracted cost of purchased gas from gas revenues leaves a net gain of $44m. I apportion total operating costs to oil production, so in my cash flow calculation the benefit from gas was simply $44m.

Breaking down the 2021 numbers my estimate for gas is that Enquest sold 1,398 boepd (c3% of reported production) @ $86 boe, for $44m.

For 2022 using 1,400 boepd and a price of 250p/therm for H1 and 400p/therm for H2 (pick your own numbers). This leads to c$50m in H1 and c80m in H2. A gain of c$85m over 2021, and a useful contribution to the c$250m expected loss on oil hedges in 2022.

An unknown is the degree to which Magnus gas fuel can be substituted by diesel, but I’d guess the impact is small in the bigger picture. Next month’s interim report will reveal the H1 cash contribution from gas, which can be easily extrapolated into H2.

From a Reuters report:

"Most analysts agree a bid for OZ would have to be sweeter.

"It's going to have to be much sweeter," Peter O'Connor, mining and metals analyst at Shaw and Partners, said.

"We think the price per share will have to be in the range of lower to mid thirties if BHP wants to get this done."

O'Connor, however, said that BHP was likely to maintain discipline and not overpay. The miner has in the past upset investors with a costly push into U.S. shale that led to billions of dollars in writedowns."

Upset?

F&*B Livid!

In 2019 I had an opportunity to ask the BHP chairman a question. I asked if the board had any party animals, because the mining sector is reaching a point in the cycle when the party animals come out to play and love to throw around shareholders cash.

I then reeled off a list of failed or expensive BHP M&A blunders over the last ten years. The chairman didn't seem familiar with some of them and looked down to a BHP employee sitting in front on me who nodded in agreement with the details I presented.

The chairman's reply was along the lines of better financial discipline and a new capital investment structure. I wasn't listening. My purpose was to get a message into the minds of management that many of their predecessors had convinced themselves, this time it will be different. It rarely is!

It isn't the Oz or Norant scale M&A deals that concern me. BHP has shown that they can walk away from the smaller 'bolt ons', if the price isn't right. But if they do overpay it isn't going to significantly impact the company. It's the bigger deals that a CEO or Chairman latches onto and like rabbits caught in the headlights 'it's their moment to shine'. When they get run over, they exit stage left with $millions in their back pocket, while the next incumbent gets the juicy well paid job of clearing up the damage.

The shareholders are left on life support.

At stages in the mining cycle share buy backs are a better option for shareholders than expensive M&A. I prefer to see BHP develop the many organic opportunities they already have, including a fast track of Jansen.

Ukbbbb, that is good news – current relief from the bankers ‘thumbscrews’ – thanks for posting.

I’ve had good communications with IR. Amongst various companies I contact Enquest is amongst the best, but I have learnt they are precise in their language.

The first paragraph is clear. In my comments I was precise in using the term “net entitlement production”. I was aware the Malaysian PSC terms and BP’s Magnus entitlement would exclude those barrels from the hedging requirement.

It’s the second paragraph that I find interesting, and from your closing comment I think you see the subtlety too. I’ll repeat the paragraph here:

“The RBL is scheduled to be repaid by the end of June 2023 (October 2023 is the effective date of maturity of the facility if we don’t refinance the high yield bond), and we are significantly ahead of that schedule, so our hedging requirements in 2023 are reduced given that we are only dealing with half a year.”

A key part is, “if we don’t refinance the high yield bond”.

It was this point in the reference document, “If Bond refinancing has occurred, the 12-month requirement drops to 50%”, that lead to me thinking the hedging requirement was more open ended. You correctly interpreted the hedging requirement ending Oct 2023.

The hedging requirement may come back into play under the RBL, but hopefully Enquest will be able to revise the terms if they decide to stay with the facility beyond next Oct.

A good dialogue.

Thanks, L7

Hi ukbbbbb, my reference is page 295

https://www.enquest.com/fileadmin/content/Golden_Eagle/Golden_Eagle_-_Combined_Circular_and_Prospectus_dated_30_June_2021__Final_.pdf