Member Info for londoner7

Agree, might sneak in with a '6' handle. Worth noting this is a quarterly dividend.

Correction to 3rd line:

2024 EBITDAX EBITDAX/boe

(2024 numbers)

Kign, my model is a bit above HBR's $1bn FCF guidance.

The key input is EBITDA/boe, which I estimated from the interims and the latest update.

2023 EBITDAX EBITDAX/boe

FY $4.1bn 258Kboe 43.5

H1 $1.21bn 159Kboe 41.8

H2 $2.89bn 358.4 44.4 4 months Wintershall

$49.6 est. for the combination, a rough assessment based on weighting over the last 4 months.

(incidentally, the combined assets produced 501Kboepd in Q4)

Using $49.6/boe and production / Capex guidance my model has FCF $1.11bn.

HBR's guidance to FCF 1bn is based on Brent oil an European gas prices, which leads to $53 EBITDAX/boe. Using this figure in my model I get FCF $1.24bn.

I back tested my model on Aker BP's 2023 numbers and was almost bang on the actual FCF of $1,939m. Frankly, this is not the level of accuracy I'd expect so an element of luck involved, but it gives me confidence in my model. The challenge with HBR is that it involves a mix of tax jurisdictions. The EPL being the biggest challenge made more difficult to estimate due to what I think of as an 'EPL tailing effect' which impacts operators with falling UK production. Unless this is compensated by higher pricing an EPL charge based on one year is paid from lower operating cash flows the following year which negatively impacts FCF. (A good reason for the likes of Serica and Ithaca to maintain or increase their UK production.)

But my model falls down on the HBR's price sensitivity numbers, capturing only 60% of HBR's quoted $115m impact.

* Incidentally, Aker BP had $71 EBITDAX/boe over that last 4 reported quarters which goes a long way to explaining the its higher valuation versus HBR.

"There is a 2025 expiry of a EUR1B senior notes in Q3'25, is this the reason why FCF is lower than expected?"

No.

In the absence of M&A, FCF is used to pay the dividend, buyback shares or pay down debt.

Whether you use a sheet of A4 or a spreadsheet, given the guidance, you should be able to make an estimate of Harbour's FCF. If your intuition++ leads you to say, higher or lower pricing versus guidance then that's applying your own fudge factor.

If you don't understand the process for an estimation of FCF, but rather follow broker estimates, and given the range of these estimates, if think you'd be better off investing in funds or ETFs rather than individual stocks.

"The headline value of the transaction is $84 million and, net of interim period cash flows, the consideration to be paid by EnQuest on completion is expected to equal c. $35 million."

My interpretation is that the business generated $54m FCF in 2024. In the absence of any other information I'd look for same again in 2025. On net 5.3Kboepd that equates to $28/boe net back, which feels about right.

Silverlight, you say, " all you need to know is that there is 90bn worth of gases in the ground."

Mosman just bailed from EP-145 in Australia with similar scale gas resources for AU$400K when their book value on EP-145 was AU$1.5m. Over AU$1m loss on book value.

What does Mosman know that you don't?

PompeyM,

Nice speech, I hope you found it supportive to your current position.

Last summer you were ramping HEX. On the 4th of August you posted, “Hex all the way for me. Gex are light years off, and imo there'll be lots of dilution and warrant exercing, usual aim tactics.”

On the 8th of Aug you posted on the HEX board, “I hold he1 and gex also. Tempting to close them and buy more here because of rns imminence. Just don't want to miss out on gex having a possible gallop too, think I must have been dreaming but think I saw a gex broker note for GBP132??!!

That’s quite a switch within 4 days, so I’d conclude that you don’t do your own research but follow broker notes, dreams, and have a fear of missing out.

By 12th of Aug (4 days invested) you seem to be losing your nerve with this post on GEX, “Should currently be MC £111m and 124p. Any drop an excellent buying opportunity. Buy the dips.”

Today, at a share price of 6p you post, “There has been a truly horrible group of posters on here that no company deserves, especially one that's determined to uphold all statutory requirements and is a true believer in its mission evidenced by its high level of bod investment.”

I’m struggling to find evidence of this ‘high level of bod investment’. Can you help me find it?

An increase in the Hussar resource was nailed on. The prospectus had 6,358,848 shares going to CSS and 6,500,000 going to the directors on a >10% increase from a previous estimate. It was always going to happen. It seems GEX were caught out when they increased the land area for the structure from 300Km2 to 350Km2, without the associated change to the Environmental Impact Report. DEMIRS did their job in spotting the error.

I'm surprised the adjustment should take 60 days. The cynic in me now expects further delays to take a 'drill result' beyond the directors lock-in period.

And No, I'm not a shareholder here and never will be. I recognised this enterprise for what it is when an IPO was first attempted in 2019. An analyst presented the 'blue sky' opportunity, then refused to take questions on the basis of some conflict of interest. I interpreted his exit as using his 'get out of jail free' card.

“AU$400K, is that it?”

I’m afraid so. On the books for AU$1,500K, and sold for AU$400K.

Just one month ago MNMS said this about EP-145, “Seismic acquisition is scheduled for early 2025.” However, over Xmas I ran cash flow numbers, which indicated MNMS didn’t have the funding for EP-145 seismic costing c. AU2m. I also noticed that seismic didn’t get a mention in the flurry of updates late December. Something was up, today we know why.

Also, having raised £1.5m in May 21 for,

• The acquisition of seismic in September/October 2021 aimed at defining a drilling prospect.

• The processing and interpretation of seismic data November/December 2021.

• Planning and long lead items for drilling.

a second placing for a similar amount would have been a tough sell. It looks like this realisation by the BOD has prompted today’s sale of EP-145.

What now?

A.C. said today, "This transaction, once completed, restores Mosman to being fully funded for all exploration commitments in the next 12 months, and with funding available for discretionary exploration activities."

What exploration commitments does Mosman have over the next 12 months? As far as I can tell there aren’t any.

From RNS last June:

Vecta - “The consideration for the 10% WI is US$500,000, to be paid in instalments of US$50,000 per month for 10 months. This is expected to be funded from a combination of existing cash and proceeds from the realisation of oil and gas assets (which may include the sale of existing projects). There is no obligation on Mosman to fund the exploration wells, however if Mosman does not, it would lose its interest in that prospect area (Area of Mutual Interest or "AMI").”

(In July 2024 an additional 10% WI was acquired through the issue of Mosman shares.)

From July RNS: “Mosman intends to fund its 20% share of the five exploration wells, estimated to cost cUS$259,000 per well (gross) which equates to US$ 52,000 net cost to Mosman for its 20% share. Mosman's drilling costs for five wells is cUS$259,000”

I assume US$259,000 is the discretionary exploration activities A.C referenced today. The timeline for Vecta drilling is solely in Vecta's control - subject to funding.

My conclusion is that a placing will be required in 2025 to fund any further exploration activities.

Papegoja,

Enquest's oil is essentially sold at offload, or daily via a pipe.

My understanding is that offloads are allocated according to share. In the case of Kraken (70.5% holding), Enquest will have sold c.9 off last year's 13 offloads (c. 500Kbo). I don't know if Enquest market their product themselves or use 3rd parties like Shell or BP. Kraken oil is typically priced at a premium to Dated Brent (spot market). The the price for Brent, commonly quoted, is a front month contract. Note the recent offload which was destined for transfer at Orkney but subsequently shuttled to Rotterdam, which suggests flexibility in taking last minute pricing. We don't know if this was an Enquest offload or the other field partner's.

Similarly for Golden Eagle, c. 600Kbo offloads are sold by Enquest according to their share in the field. On acquisition it was typically 1-2 per quarter but less now given the field decline.

GKA is piped ashore and priced daily.

Magnus is piped to storage at Sullon Voe, before tanker offload. From conversations with IR I believe Enquest has some flexibility in the timing of these offloads.

But, in the round production is sold at pricing regularly throughout the year, and I find that applying an average Brent price (front month contract) works. In a recent post I used $82, rather than the $81 average for 2024, because the bulk of production was made in H1 at $83.6. Therefore, I weighted the price slightly - a minor adjustment worth c. $12m on revenue.

A key variable in my model is the % of headline production that is actually 'crude oil sold'. I've repeated this frequently over the years but I don't think anyone has ever queried me on it. I still see posts with Revenue = headline production x Brent, which exaggerates the actual revenue number.

My comments are based on my recollections of oil pricing detailed in a prospectus from a few years back.

oct23 mentioned hedging. In case you don't know, these are financial instruments which operate independently of actual production volumes.

Hi Stevo12, thanks for your response.

No doubt credit terms will affect the timing of cash payments, but I can only go with the guidance released, and my understanding is that cash Capex in 2024 is expected to be $250m.

However, you'll remember the late adjustment to the final 2023 Opex and Capex numbers which were positive for 2023 FCF. Perhaps we'll see the same again in the next month's trading update for 2024.

Ps. I'd add $35m to my 2024 FCF number if I understood why the additional $50m spend on capex only reduces FCF in 2024 by $15m.

Hi Tarmak, as always, great detail in you production figures, though I wonder if the guidance numbers and an estimate of Malaysia's contribution would suffice. But the question I have is, why do you base your FCF forecast for 2024 on 2020 numbers?

I'd missed the Nov trading update, so just updated my model. Excuse me if I've missed something but I don't see how you account for the additional $50m CapEx for 2024 in your numbers. (Just to add. I don't understand this comment from the update, "As a result, 2024 capital expenditure is expected to total c.$250 million, with a net reduction in 2024 free cashflow of c.$15 million." I can understand extra spend on CapEx reducing the 2025 tax liability, but 2024?)

Your new metric shows $85m FCF in 2024 from assets with, I assume, a further $58m from the Bressay deal. (I don't see any adjustment for the $40m positive working capital, which I assume will unwind in 2024.)

The Jeffries numbers are interesting. (Thanks ZippyFrood). The $454m 2024 year end number has $27m net FCF, and after a-$58m Bressay and +$40m working capital adjustments, points to $9m FCF in 2024 from operating assets. For 2025 they guide to $115m FCF, and after deducting your estimate of lease savings ($49m in 2025) point to $66m FCF from operating assets in 2025.

Of course, this ignores any M&A activity which we should assume will be positive.

To my numbers:

On 6/3/24 Stevo12 initiated a good discussion on forecasts for 2024 FCF. He came in with $50m, and based on his numbers my model had $16m - as I posted at the time. Sekforde forecast $196m FCF (after $146m adjustments to Stevo12's number).

Today, I've made the following adjustments to the inputs to my model:

Oil price, $82 was $80.

Production, 40,500 boepd was 43,000 boepd.

CapEx, $250m was $200m.

Crude oil sales, 80% of reported boepd, was 86%. (This metric is key to my model and the step down was triggered by the 78% reported in the H1 numbers. This may be a temporary anomaly, but I'm only coming back up to 80% until I see the final results) I add a nominal net gas contribution based on the previous years net $ number, +$45m from last year. Though this might increase in 2023 with the additional Selgi gas.

My result is a -$146m FCF from producing assets. This is $155m short of the Jeffries number and I forward to finding out why when the final results are released.

My guess is it will be the crude oil sales metric, the net EPL payment, which I have at $135m after the Bressay asset dealings, the BP profit share which I have at $67m, or a jump in the $ gain from gas sales. I'd expect a big miss on all of them to get to $155m.

* I second your comment on Steelwatch1's posts on the Kraken offloads.

Hi PompeyM, what is the connection between Mt Winter and Central Petroleum?

Dai2belts, that's old news. This is from my notes which shows a history of failed attempts to progress these wells.

CTP trading update - “Central Petroleum (ASX:CTP) has decided to change its planned 2010 drilling programme to enable the company to prioritise its pursuit of oil targets in the Amadeus Basin and maximise the opportunity of short term cash flows, rather than the longer term and more capital intensive Helium/gas targets.

The current inability of Oil and Gas Exploration Ltd (previously He Nuclear Ltd) (OGE) to pay 50% of the funding needed for the Magee 2 drilling programme has also contributed to the decision.

OGE owes approximately $1 million in unpaid cash calls for both the Magee and the Mt Kitty joint ventures”

Within the Amadeus Basin CP’s focus turned to the Dukas-1 well for conventional gas, working Santos as operator. (The pressure and rig issues during drilling are well known here). Santos lost a % of their interest when they passed on a deadline to commit to return to Dukas-1.

After a 3 year delay a private company, Peak Helium, revived interest in Magee, Mt Kitty and Dukas in Feb 2022, when they agreed a JV with Central Petroleum and Santos for 3 drills in 2023. Peak is carrying the full well costs (100%) to a max (gross) $20m per well on Magee and Mt Kitty, and WI costs on Dukas.

The JV was due to close June 2022 but has been held up while Peak progresses “various approvals with the Northern Territory Government in order to facilitate completion of the remaining conditions precedent”.

Both CP and Santos have agreed to extensions almost monthly – latest 31st Jan 2023 now extended to 28th Feb 2023.

The farm out was subsequently terminated following Peak’s failure to comply with demands for payments under the agreement.

On Mt Kitty and Magee:

“Despite being technically successful, both wells suffered from poor reservoir quality. Magee 1 produced gas from a very thin (4.5 m) fine-grained sandstone (inferred as Heavitree Formation by WakelinKing, 1994) overlying crystalline basement, while Mount Kitty 1 lacked any subsalt sandstone, producing gas from fractured and weathered crystalline basement. Drilling of a third subsalt exploration well, Dukas 1, was suspended at the time of writing.” (PW Haines and HJ Allen – GSWA 2020)

Botham,

None of the 3 drills you refer to encountered commercial volumes of helium – flows stopped within days. There are several papers available on these drills for anyone that wants to do any research beyond reading posts here or on ‘X’. I referenced these papers on the MSMN chat group a few years back.

Somewhere on the Hussar permit area there may be a commercial source of helium but consider the chance of that source being at the bottom of a previous oil exploration drill. I’d say slim to zero.

The story on EP-155 is much the same – re-entering an old exploration drill.

I said, "The ENI assets should bring this down in 2025 - we should get guidance in Feb."

Looking again at the 2024 guidance slide 19, I calculate Opex on the combined production in Q4 at $20 boe. If my calculations are correct, mid-point production guidance for 2024 Q4 is 112K boepd. Both numbers could extend into 2025 Q1. Attractive cash flows, but don't forget the c. $400m tax payment paid last Oct post the Q3 numbers.

Aceofaces, 130p gas? I think you are looking at old statements.

The current (19th Nov 2024) is detailed on slide 24 of the recent update. The gas hedging looks favourable (Q1 102p per therm swaps), but not as spectacular as recent years. The non-hedged gas volumes should see better pricing compared to 2024 Q1, but this is negated by the current lower Brent price.

2024 YTD Opex is $29 boe (oil & gas). The ENI assets should bring this down in 2025 - we should get guidance in Feb.

I assume today’s RNS is the result of discussions which were noted in the H1 results.

“Seligi gas, which is produced and handled by EnQuest in exchange for a gas handling and delivery fee, represented 1,614 Boepd of year to date production. Discussions are ongoing between EnQuest and Petronas, seeking to expand on the existing foundational strategic agreement relating to Seligi gas.”

An RNS from May 2023 reported the agreement.

“This agreement is expected to increase EnQuest's gas production by around 25 mmscf per day (50 mmscfd gross), initially from associated gas, with the partnership assessing the drilling of additional gas-producing wells over time.”

Today’s RNS appears to highlight progress on advancing the drilling of gas-producing wells.

“The agreement enables the PM8E PSC parties to develop and commercialize the non-associated gas resources in the PM8E PSC contract area and, in line with expected demand, supply around 70 mmscf per day of sales gas.”

In 2024H1 Seligi gas accounted for 1,614 boepd, (c. 10 mmscf per day), through the production of associated gas resources. I interpret today’s RNS as agreement to “develop and commercialize the non-associated gas resources”, to a net 35 mmscf per day (c. 5,800 boepd Enquest share).

While there should be efficiency gains from utilising existing infrastructure, in the absence of details on commercial terms, I’m only assuming any increased volumes are paid for via additional gas handling and delivery fees. If Enquest participates in the drilling of the gas wells then I’d guess they’ll get more attractive terms, but that would require up-front Capex.