Member Info for Fernan10

CALCULATION OF FREE CASH FLOW

Interest payments (including US$ 57 million of interest on the Kraken FPSO leasing): US$ 192 million

Interest on Credit Facility calculated taking into account an average debt balance for the year of US$ 681 million (balance of US$ 785 million for Jan-March, US$ 680 million for April-September, and US$ 580 million for Oct-Dic).

Kraken FPSO payments (repayment of principal, without interest): US$ 100 million (see balance sheet)

Malaysian taxes (at a 38% corporate income tax rate): US$ 29 million

Payment of vendor debt for the acquisition of 25% of Magnus: US$ 15 million

Alma Galia. Cost recovery provision: US$ 9 million

CAPEX: Total CAPEX for the year of US$ 275 million, less CAPEX for the 75% of Magnus of US$ 30 million.

Taking into account CAPEX for 100% of Magnus of 31,7 million pounds, see page 202 of Magnus 75% acquisition prospectus.

CAPEX for Core business: (US$ 275 million – US$ 30 million for 75% of Magnus): US$ 245 million

Free cash flow for “core business” (excluding 75% of Magnus): 601 – 192 – 100 – 29 – 15 -9 – 245: US$ 11 million

Regards

Fernan

Here are my numbers for the “core business” (excluding 75% of Magnus)

CALCULATION OF EBITDA

Production: 54.000 bopd (similar to 2018)

Avg Brent: US$ 63/b

Average selling price: US$ 56,86 (equals to 90% of Brent, in line with historic levels, and the discount being basically a consecuence of the way the Malaysian Production Sharing Agreement works)

OPEX: Total OPEX of US$ 600 million less OPEX for 75% of Magnus of around US$ 72 million

Taking into account OPEX for 100% of Magnus of 74,6 million pounds, see page 202 of Magnus 75% acquisition prospectus.

OPEX for core business: US$ 600 million – US$ 72 million. Equals to U$ 528 million. Its´s equivalent to US$ 26,81/b

G&A: US$ 0,5/b

SUBTOTAL: (56,86 - 26,81 – 0,5) X 54.000 bopd X 365: US$ 583 million

Results from hedging (three way collar): US$ 18 million (3,6 million barrel X (US$ 68/b – US$ 63/b))

EBITDA: US$ 601 million

Good morning.
If you are interested, I can post my spreadsheet for everyone here to review the numbers.
I need a reliable website to publish the file.
The last one I use (upload.io) is now infected with virus.

Regards

Fernan

Hi E121.

You asked me about my other investments

I´m only invested in the O&G E&P sector

PMO is my biggest holding. I think you are invested here too, so no need to provide a detail

Apart from PMO, 3 years ago I started buying Eco Atlantic Oil & Gas in the Toronto Stock Exchange. It´s also trading in London (ticker: ECO). It´s a small exploration company with a 15% interest in an exploration block in Guyana, in association with Tullow and Total. This block is nearby the Starbroek block, where Exxon has discovered 5 billion barrels of oil so far (not including the 2 most recent discoveries announced yesterday). According to seismic, one of the discoveries (Hammerhead) seems to extend into Eco Atlantic´s block. Exxon is planning to appraise that discovery next April. It´s possible for ECO to bag a few million barrels of contingent resources without drilling a single well.

ECO and their partners will commence their own drilling programme in May/June this year. ECO is fully funded to drill at least 3 wells.

This is a 4 bagger from my initial investment, but I think it still has a lot of running room. With each Exxon discovery, share price keeps going up.

Other share that I think has a lot of potential is Lansdowne Oil & Gas (LOGP). It has a 10% interest in the Barryroe oil discovery offshore Ireland. Next summer a chinese consortium will carry an extensive drilling and testing programme, worth a few hundred million dollars. LOGP is carried for the full programme. If this is a success, it could be another multibagger. I expect the share price will start going up when we get closer to the beginning of the drilling and testing programme.

Regards

Fernan

Guyana: ExxonMobil's latest discoveries offshore Guyana could be some of the largest made to date - Westwood Global Energy

In response to the new discoveries announced by ExxonMobil offshore Guyana, Dr Keith Myers, President, Research at Westwood Global Energy Group, said:

'The two new discoveries announced in Guyana today could be some of the largest made to date. Tilapia is reported to have 93m of net oil pay, which is the highest reported so far in any exploration or appraisal well in the Stabroek licence. Haimara found gas condensate close to the Suriname border. This, together with the recent Pluma discovery, defines a gas prone area of the Liza fairway. Guyana now looks as though it could have a gas export business to add to its oil and Stabroek looks like it is one of the most prolific deep water blocks ever licensed.’

https://www.energy-pedia.com/news/guyana/exxonmobils-latest-discoveries-offshore-guyana-could-be-some-of-the-largest-made-to-date---westwood-global-energy-175842

I think there are better options on the market to take advantage of an eventual spike in oil prices.

So I decided to sell my position and move on.

I know that there is bunch of very clever people here that thinks different. So there is a chance I could be wrong in my assessment. If this is the case, I will try to learn from my mistakes. Time will tell.

This is an excellent board. I´ve learnt a lot here. So thanks all of you guys/ladies for the info and analysis posted here.

Good luck

Fernan

Good morning.

Here are my comments on last operational update:

Production: in last December update, management informed that production growth will come basically from the acquisition of 75% of Magnus. So, production from the rest of the portfolio will remain basically at the same levels of last year during 2019

OPEX: substantially higher on a per barrel basis. I suspect this is the reason why management decided to provide a guidance for OPEX as an absolute number instead of a per barrel cost.

CAPEX: US$ 275 million for the year, including US$ 100 million of CAPEX deferrals from past periods. Connecting the dots, ENQ will have to spend US$ 175 million on CAPEX, only to arrest the declines and keep production flat. Not a reassuring thing in my opinion.

Kraken: no solution in sight for the FPSO issues. It seems that 30.000 to 35.000 bopd is the “new normal” here.

I run my numbers in that scenario of flat production, higher OPEX, higher CAPEX and no expected solution for Kraken.

Assumptions used in the model are the following:

Average Brent for the year: US$ 63/b

Production

Core business: 54.000 bopd (similar to 2018)

Magnus (100%): 14.967 bopd (according to Magnus prospectus). I know that production from Magnus last December was substantially higher, but average for last year was more in line with my projections. In any case, any increased production from the 75% of Magnus will have to be shared with BP, so it will not make such a big difference.

Net production: 65.225 bopd (within the range provided by management).

Applying these assumptions, together with the info from last operational update, I have free cash flow for the year of only US$ 125 million, almost all of it generated by the 75% of Magnus.

For the “core business” (excluding the 75% of Magnus) free cash flow is close to 0 (cero).

Given the unsolved issues on Kraken, and the huge amount of CAPEX required only to keep production flat, I can´t see where substantial production growth will come from in future years. I really don´t have any visibility on sources or chances of future production growth.

In addition to that, absent higher oil prices, Free cash flow generation won´t allow an accelerated repayment of debt. Past operational issues and underperformance at Alma-Galia, Scolthy/Crathes and Kraken are not precisely reassuring about the future.

All hopes here seem to rely on substantially higher oil prices (to improve Free Cash Flow generation) or another Magnus-type acquisition (to provide for future production growth).

I have to confess that I was surprised to read some posts here talking about a dividend.

I had bought a few thousand shares, in the hope that the acquisition of 75% of Magnus will deliver substantial free cash flow and debt reduction. But I lost my hope. For me, the risk-reward equation doesn´t sound good here anymore. A combination of flat production and lower Free Cash Flow has killed my investment thesis here.

Thanks Pelle

Regards

Fernan

Hi L3. Please provide a link

Thanks

Fernan

It´s difficult to know Squif.

They talked more of a number of days at reduced production rates (due to the mechanical issues), rather than a lot of days with a complete production shutdown.

Currently they are at reduced rates again, due to the issue with the pipe that needs a weld replacement.

At least they are keeping the production guidance for the year

Regards

Fernan

They told me that were not completely shutdown for an entire 2 week period. They shutdown for a few days, and were running at reduced rates for some time also.

I have the repply in writing, but in the past they asked me not to copy and paste.

Regards

Fernan

Good evening.

I asked IR about AK perfomance issues, and their impact on already provided production guidance for the year.

The most importants items of the repply are the following:

*All mechanical issues have either already been fixed, or identify to be promptly fixed. As there is some redundancy in the system, issues still to be solved are not affecting production.

* Production rates had returned strongly following the fixes but just a day or so ago they found a pipe that needed a weld replaced so have had reduced rates again.

* current production guidance for the year takes into account some of such risks and therefore is not changed

Regards

Fernan

hi Pelle/chilting.

A few months ago, I reviewed OPEC monthly reports for the period 2008-2018.

I found something that really surprised me: for the 10 year period, non-OPEC (ex US shale) oil production growth was 0 (CERO!!). All those projects offshore Brasil, onshore russia, canadian oil sands, etc, etc, that were developed for the last 10 years, only served to keep global production (exclusing OPEC and US shale) flat.

Without US shale oil production growth since 2010, I´m sure oil price would be triple digits now.

This is the reason why I closely follow the evolution of this sector

Regards

Fernan

Very interesting comments from Schlumberger´s CEO in their recent Earnings Conference Call:

"It is also worth noting that with the continued growth in U.S. shale production, an increasing percentage of the new wells drilled are being consumed to offset the steep decline from the existing production base. The third party analysis shows that in 2018, this number was 54% of total CapEx and is expected to increase to 75% in 2021, clearly demonstrating the unavoidable treadmill effect of shale oil production."

"Add to this, the emerging challenges of production per well as infield drilling creates interference between parent and child wells, as drilling steadily steps out from the core Tier 1 acreage and as the growth in lateral length and proppant per stage is starting to plateau, we could be facing a more moderate growth in U.S. shale production in the coming years than what the most optimistic views have been suggesting."

https://seekingalpha.com/article/4234288-schlumberger-limited-slb-ceo-paal-kibsgaard-q4-2018-results-earnings-call-transcript?part=single

Good morning.I´m not sure the numbers from these analysts are reliable.For example, they calculated Annual Revenues as a product of (Annual production) X (Brents price).But, in the case of ENQ, this is not the case. Due the effect of the Malaysian production sharing contract and adjustments to the price that ENQ receives in the North Sea, the average selling price for ENQ has been historically equivalent to aprox. 90% of Brent.With annual production of 23 million barrels, and a projected average Brent of US$ 60/b, a 10% discount on the selling price makes a US$ 138 million difference in revenues and free cash flow.The treatment of the annual payments to the lessor of the Kraken FPSO (amortization + interest) in their financial model is not clear either. We know that those payments are not part of OPEX. We are talking of about US$ 157 million annual payments here.On the other hand, if the implied US$ 250 million of CAPEX taken into account by them was informed by company´s managment, then this number will be higher than the US$ 180 million that I considered in my financial modelRegardsFernan

Good morning

Last week, the analyst at RBC expressed her worry about a potential reserves downgrade at Kraken, as a consequence of the lower production anticipated for 2019.

On the other hand, management said the following in last operational update: “With well testing now complete at all 11 producing wells, the Group is incorporating the information gathered from these tests into its plans to optimise production and maximise reserves from the significant volume of oil in place.”

In addition to that, management mencioned the existence of short term drilling opportunities in the western flank of the field

So, the analyst and company´s management seem to live in 2 different worlds regarding the amount of Kraken reserves, the first one waiting for a potential downgrade and the latter considering the chance of an increase.

The background for management´s goal to “maximise reserves from the significant volume of oil in place” is the following:

In November 2013 presentation, the company calculated Kraken gross reserves as follows (pages 34/35 of the presentation):

Oil in place: 421 mmbo
Recovery factor (RF): 35% (North: 30%. Central: 45%. South: 33%)
Oil to be produced: 147 mmbo
Oil to be used as fuel in the FPSO: 10 mmbo
Gross reserves: 137 mmbo (97 mmbo net to ENQ)

Management also showed that, for heavy oil fields with similar viscosity, the Recovery factor could be higher than 60%. (see graph in the page 34 of the presentation)

So, from last operational update, it seems that management is using the info for all recently drilled wells to calculate if it´s feasible to increase the recovery factor for the field.

A 10% increase in the RF, for example, will add 42 mmbo gross, (30 mmbo net to ENQ).

It will be up to the third party reserves evaluator to consider all this info and come up with a revised number in March.

Regards

Fernan

You are right Pelle.

They said that the amount owed at Dec 31 was US$ 66 million (note 22 to 2017 FS) and then they said that US$ 27 million was repaid during 1H 2018 (note 18 to 1H 2018 FS).

So they were owing US$ 39 million at July 1, 2018.

Regards

Fernan

Hi Squif.

How do you know that? any link?

Regards

Fernan

Squif:

yes, the treatment of the payments to BP in relation with the acquisition of MAgnus could make a difference between my calculations and Moodys´.

In my spreadsheet, at Brent: US$ 65/b, I have the following payments to BP in 2019 regarding the Magnus transaction:

Repayment of vendor loan (for the initial 25% acquisition): US$ 15 million
Repayment of vendor loan (for the 75% acquisition): US$ 20 million
Interest on vendor loan for the 75% acquisition: US$ 7,5 million
Payment of BP´s 50% share of the cash flow from the 75% acquisition: US$ 18,3 million

Total amount to be paid to BP: US$ 60,8 million

If Moodys considered the total amount owed to BP at the beginning of the year as part of their "adjusted debt", then those payments should not be considered as negative items of Free Cash flow, in my oppinion.

Regarding the payments to the leasor of the AK FPSO, there are 2 kind of payments:

- amortization of principal: aprox US$ 100 million per year
- interest on principal: US$ 57 million per year

Maybe Moodys considered the amount originally owed to the leasor of the FPSO as part of their "adjusted debt" and then, the repayment of such debt is not included within Free Cash Flow

In the case of PMO, those 2 payments are considered as part of operating cost.

So, at Production = 65 bopd and Brent= 65, the reconciliation of Free cash flows is as follows:

FCF according to my Excel spreadsheet: 268
repayment of debt to the leasor of AK FPSO: 100
Repayment of debts with BP regarding Magnus: 61

Adjusted free cash flow: 429

This number is in line with Moodys calculations

Regards

Fernan

Regards

Fernan

Hi Squif

At 65 boepd and Brent: US$ 65/b, I have:

EBITDA: US$ 880 million
Free cash flow: US$ 268 million

One big difference with Moodys regarding Free cash flow could be the treatment of the repayment of debt with the leasor of the Kraken FPSO (roughly US$ 100 million per year).

In my oppinion, since those payments reduce the amount of cash available to repay Financial debt, they should be included as a negative item of Free Cash flow for the year.

As a comparison, in the case of PMO, those payments are considered as part of the operating cost (see today´s press release from PMO).

Regards

Fernan