Member Info for Fernan10

Good morning.

From Moodys Rating action:

“Based on pro-forma financial statements published in the rights issue prospectus, EnQuest has a provision of $418 million immediately post closing, representing the outstanding vendor loan and BP's entitlement under the cash flow sharing arrangement discounted to present date. Moody's will treat this provision as debt.”

“However, this adjustment to debt will be partly offset by the reduction in adjusted total debt of around $270 million (net of the new $175 million Kraken financing) that Moody's expects EnQuest to effect out of free cash flow (FCF) in 2018. Higher sales volumes and realised prices (net of hedging results) combined with lower operating unit costs should lift EnQuest's EBITDA (as adjusted by Moody's) to around $760 million compared to $266 million in 2017. Moody's estimates that EnQuest will generate FCF of around $285 million in 2018, after capex of $250 million that has significantly reduced following the start-up of Kraken in June 2017. This should translate into a significant decline in leverage, with Moody's adjusted total debt to EBITDA falling to 3.8x in 2018 from 11.6x in 2017.”

E121 commented the following: “…the $270 DOESN'T include an Magnus related $100 mill vendor loan repayment out of cash flows. Moody's have clearly stated in the upgrade report that the Magnus is assumed to close on 1/1/19. So, this is a 'clean' FCF based debt reduction for ENQ in 2018, from the assets that are currently on ENQ's books.”

So, for 2018, Moodys expects an annual EBITDA of U$ 760 million and CAPEX of US$ 250 million, that presumably will translate into a debt reduction of US$ 270 million for the whole year. Let´s see if this is possible.

We know that, during 1H 2018, debt reduction was almost cero (0). Net debt went from US$ 1.991 million at the end of 2017 to US$ 1.973 million at June 30 2018. So, almost all the debt reduction projected by Moodys should take place in 2H 2018.

Moodys say that annual EBITDA should be of US$ 760 million. By deducting EBITDA of US$ 312 million in 1H 2018, they forecast EBITDA of US$ 448 million for 2H 2018

As for CAPEX, Moodys project US$ 250 million for the whole year. Subtracting US$ 125 million of CAPEX in 1H 2018, they expect CAPEX of US$ 125 million in 2H 2018

In addition to that, for 2H 2018 it´s reasonable to expect:

Debt interest payments: around US$ 100 million (including interest on the leasing of Kraken FPSO)

Kraken FPSO leasing payments: around US$ 50 million (50% of the current liability at June 30, 2018)

Malaysian taxes: US$ 10 million (estimated)

Cost recovery provision (to be paid to KUFPEC due to the underperfomance of Alma Galia): US$ 5 million (50% of the current liability at June 30, 2018)

Repayment of Magnus initial 25% acquisition price and other provisions: US$ 10 million (50% of the current liability at June 30, 2018)

Good morning

I think that, without any action (i.e., production cut) from OPEC, come Q1 2019, the market will be significantly oversupplied, in spite of the effects of the Iran sanctions and anticipated production declines in Venezuela.

The reasons for that are the following: in the last monthly report, OPEC projected the “Call on OPEC crude” (demand for its own crude, taking into account projected demand and non-OPEC supply) of 31,5 mbd (page 84).That number was calculated assuming that US crude production for August would be less than 11 mbd (page 48 of the report).

Actual US crude oil production for August was 11,346 mbd, according to EIA. Russia also exceeded production forecasts for October.

Then, I expect that, in the next report (to be released on November 13) the “Call on OPEC crude” will be around 31 mbd.

That number looks substantially lower that the 33,31 mbd produced by the group in October, according to a recent Reuters survey.

So, even if the sanctions on Iran, together will production declines in Venezuela, take, for example, 1 mbd out of the market, I expect the market to be awash in oil in Q1 2019.

Management should be buying some puts, in order to prevent that situation to affect the financial performance of the company, in my opinion.

Regards

Fernan

6. Cash flow from the acquisition of 75% of Magnus
I added that cash flow as a separate line. I calculated the amount of free cash flow from the acquisition of the remaining 75% of Magnus after Enquest´s IR department explained the details of the transaction. Here is what I already posted on the subject.
________________________

Good morning. I emailed IR in relation to the distribution of 75% of cash flow from Magnus.

They asked me not to copy and paste the answers received from them, but in essence they told me the following:

1. First call on net cash flow is the repayment of the vendor loan to BP. It´s a five year loan, with an annual interest of 7,5%. Estimated amount outstanding at the end of 2018 of aprox. US$ 100 million. Each annual payment will be equal to one fifth of the outstanding amount, plus interest

2. Second call is the reimbursement to Enquest of the US$ 100 million to be paid at completion

3. Third call is the 50:50 profit share.

So, in 2019, for example, let assume a net cash flow (after CAPEX) attributable to the 75% interest of of US$ 245 million, as per the following assumptions:

Gross production: 17.000 bopd (page 173 of the prospectus)
Oil price: US$ 70/b
Gross revenues: US$ 434 million
Gross OPEX (according to CPR): US$ 74,65 million (platform + wells) (page 179 of the prospectus)
Gross CAPEX (According to CPR): US$ 31,7 million (page 178 of the prospectus)

Gross Free cash flow: US$ 327,65 million
Net cash flow for the 75% interest: US$ 245 million

Distribution:

Repayment of vendor loan: (US$ 100 million principal)/5 + US$ 7,5 million interest): US$ 27,5 million
Reimbursement to Enquest: US$ 100 million

To be divided equally between BP and Enquest: US$ 117,5 million (BP: US$ 58,75 million; Enquest: US$ 58,75 million)

Total Enquest share in 2019 (attributable to the 75% interest to be acquired): US$ 158,75 million

7. Conclusion
I projected free cash flow for the period at US$ 372 million, with US$ 159 million provided by the acquisition of 75% of Magnus and US$ 213 million generated by the rest of the portfolio.

Net financial debt should be reduced by the same amount during the year.

Regards

Fernan

Here is my projection (I hope the link works)

https://ufile.io/isujy

Comments:

1. I projected Enquest´s free cash flow as the amount that will be generated during the year for the repayment of financial debt. For that reason, I included the repayment of “Provisions” (for example, the vendor loan with BP in relation to the acquisition of Magnus) as an expenditure that reduces the net amount available to the repayment of financial debt.
By the same criteria, the repayment of the Mercuria facility is not included within “free cash flow” for the year, as such debt is included within the total financial debt of the company.

2. oil production (not including the 75% of Magnus) is projected at 54.000 bopd (the same amount of this year). I know a lot of people in this board will consider this as very conservative. The reasons for that “low” number are the following:
- Kraken is still producing in the 30s.
- in my opinion, the few thousand additional barrels to be provided by the workovers at Alma Galia and the recent drilling activity in Malaysia will be barely enough to offset production declines in the rest of the portfolio. There are some fields in the North Sea (for example, Gadwall) were the decline rates have been around 50% per year

3. Oil price. Brent is projected at an average US$ 70/b for the year. Enquest´s North Sea production is sold at an average of 96% of Brent. Malaysian production, due to the effect of the provisions of the Production Sharing Contract, is sold at an average 65% of Brent.

4. Hedging
I assume that, in addition to the “hedging” effects of the Mercuria facility, Enquest buy puts for 5 millon barrels, at a cost of US$ 2/b, for a total cost of US$ 10 million

5 CAPEX
I assumed CAPEX of US$ 180 million, as follows:
Kraken: US$ 80 million
Rest of the portfolio: US$ 100 million
In the case of Kraken, as it was explained by some posters here, even if the activity will be substantially reduced from this year, next year will see the effect of the “Payment deferrals” on some items of CAPEX in Kraken (basically subsea infrastructure and drilling costs)

Hi MO.

When I tried to access that website, I received a virus alert.

Regards

Fernan

Hi TW.
You asked me to post my spreadsheet on Enquest´s projected free cash flow for 2019.

I have no problem to do that. But I need someone to explain to me how can I attach an Excel spreadsheet here. I´m not good at all on computer matters.

Apologies for my ignorance

Regards

Fernan

Dear E121:

I have a different view in relation to the distribution of the cash flows from 75% of Magnus in 2019.

On Sept 18, after talking with Enquest´s IR department, I posted the following:

____________________

Good morning. I emailed IR in relation to the distribution of 75% of cash flow from Magnus.

They asked me not to copy and paste the answers received from them, but in essence they told me the following:

1. First call on net cash flow is the repayment of the vendor loan to BP. It´s a five year loan, with an annual interest of 7,5%. Estimated amount outstanding at the end of 2018 of aprox. US$ 100 million. Each annual payment will be equal to one fifth of the outstanding amount, plus interest

2. Second call is the reimbursement to Enquest of the US$ 100 million to be paid at completion

3. Third call is the 50:50 profit share.

So, in 2019, for example, let assume a net cash flow (after CAPEX) attributable to the 75% interest of of US$ 245 million, as per the following assumptions:

Gross production: 17.000 bopd (page 173 of the prospectus)
Oil price: US$ 70/b
Gross revenues: US$ 434 million
Gross OPEX (according to CPR): US$ 74,65 million (platform + wells) (page 179 of the prospectus)
Gross CAPEX (According to CPR): US$ 31,7 million (page 178 of the prospectus)

Gross Free cash flow: US$ 327,65 million
Net cash flow for the 75% interest: US$ 245 million

Distribution:

Repayment of vendor loan: (US$ 100 million principal)/5 + US$ 7,5 million interest): US$ 27,5 million
Reimbursement to Enquest: US$ 100 million

To be divided equally between BP and Enquest: US$ 117,5 million (BP: US$ 58,75 million; Enquest: US$ 58,75 million)

Total Enquest share in 2019 (attributable to the 75% interest to be acquired): US$ 158,75 million

Hi Maverick.

That´s exactly what I said. ECO can only drill 2 wells in Guyana with the cash in hand + the option payment (after taking into account the cost of drilling a potential well in Namibia).

I think that if the company raises some capital (with minimal dilution to current shareholders) in order to drill 2 or 3 additional wells, it will have a positive effect on the share price (as the chance of making a discovery after drilling 4 or 5 wells will be close to 100%).

Regards

Fernan

Here is what I wrote to the CEO today:

Dir Mr Holzman:

My name is XX, and I´m writing you from XX, being a shareholder of Eco (Atlantic) Oil and Gas.

I read the research report on the company issued by Hannam & Partners on October 4.

Analyzing the proforma cash flow statement (page 35 of the report) I noticed that the projected cash balance at the end of 2020, after drilling one well in Guyana and potentially one well in Namibia, will be CAD$ 8.292.589 (equivalent to aprox. US$ 6.300.000 at current exchange rate of 1 CAD$= 0,76 US$).

This money will be barely enough to drill a second well in Guyana.

In my opinion, the best strategy going forward to add shareholder value is the following: wait for near term catalysts to substantially increase the share price (one such catalyst could be, for example, a confirmation that the Hammerhead-1 discovery extends into the Orinduik block) and then make a capital raise, in order to get the cash necessary to drill 2 or 3 more wells in Guyana.

For example, issuing 20 millon shares at an average price of US$ 0,8 per share (equivalent to CAD$: 1,05 per share) will provide the funding for 3 additional wells in Guyana, at current costs of drilling.

By doing that, the market will be shown that ECO will have the funding to drill 3 more wells (in addition to the ones that can be drilled with current cash in hand) and that, considering the chances of success on the Orinduik block, the probability of ECO finding and appraising a potential discovery will be closer to 100%.

And this perceived increase of the chance of making a discovery could be obtained, in the example provided above, by diluting existing shareholders just by 12,5% (20 millon shares to be issued, in addition to the roughly 160 millon shares outstanding).

The negative effect of this eventual dilution to current shareholders will be more than compensated by the increase in the chance of drilling success provided by the higher number of wells to be potentially drilled.

This is the path that I would like to see the company going through as a shareholder, in order to add shareholder´s value.

I would like to hear your views on the subject.

Thanks very much for you contribution to the development and success of Eco (Atlantic) Oil & Gas.

Sincerely yours

XX

https://www.investegate.co.uk/chariot-oil---gas-ld/char/prospect-s-well-result--namibia/201810110700046488D/?fe=1&utm_source=FE%20Investegate%20Alerts&utm_medium=Email&utm_content=Announcement%20Alert%20Mail&utm_campaign=Chariot%20Oil%20&%20Gas%20Ld%20Alert

Hi Itsyou.

I think ECO´s management should have made clear for everyone to know that their most likely prospect (the potential continuation of Exxon´s Hammerhead discovery in the Tertiary into Oriunduk block) is not included in the CPR.

I didn´t understand that until I read your posts.

Not making this clarification was a big mistake in my oppinion. It would be nice to see them providing some details of this prospect in a separate press release.

Thanks and keep your good work.

Fernan

Continuing with my previous post, this is what the CPR says about potential prospects in the Tertiary (page 27 of the report):

"The majority of these leads are considered analogous to the Stabroek Liza plays. There are
additional lead ideas observed on the seismic data hat are not included in this report. In particular,
it should be noted that the many Tertiary section Lead ideas could be developed in light of the
Exxon Hammerhead discovery in the near future."

Regards

Fernan

Hi Itsyou. I really appreciate your contributions here. Thanks for them.

I have a question about the recently issued CPR on Guyana, as follows:

You wrote:

“…the Tertiary potential was hardly evaluated and after the Hammerhead well we expect several Tertiary prospects to be considered by Eco."

And

“…Hammerhead-1 is in the Tertiary zone, so they are now looking at the part of Hammerhead-1 that extends onto Orinduik. This hasn't been included in the CPR as is the Tertiary zone.”

I don´t understand this. Why did the CPR focus only on prospects on the Cretaceus, when our neighbors were drilling in the Tertiary?

Do they need to issue a new CPR report, in order to consider those prospects in the Tertiary?

If they saw the Tertiary prospects on seismic (I suppose so), why didnt´t they add them to the recent report?

Thanks in advance

Fernan

Bronxville:

I know what due diligence is.

I simply asked a few technical questions that I can´t answer by myself.

Regards

Fernan

Hi ravenspass.

I posted the same questions twice on the www.iii.co.uk boar to Jimmy23 (he´s a respected oil expert, that I´ve been following for years), but the moderator haven´t approved them yet to be published.

If you don´t mind, maybe you can do me a favor and try publishing these questions to Jimmy.

Thanks in advance

Fernan

Good morning sirs.

I´m performing a due diligence before taking a decision about investing here, and I have a few questions regarding Barryroe, as follows:

1. the chinese planned to performed Drill Stem Tests in 3 out of the 4 wells to be drilled. I understand that these type of tests are for a limited period. Wouldn´t it be necessary to execute long term tests, in order to prove the perfomance of the field, and to be sure that the faults don´t affect long term production?

2. what do you think the minimum flow would be in order for the chinese to go along with the development of the project?

3. what are the most important operational risks that could prevent the project getting to FID?

Thanks in advance

Fernan

You keep doing what you are best at: posting personal attacks...

I still remember the good old days when you were all the time talking about your US$ 500 millon free cash flow "forecast" for 2018.

There are 2 things that I haven´t seen here for the last 2 years:

- a positive operational update from AB
- an intelligent post from you

Keep the good work.

Enjoy

Fernan

Hi E121.

IR told me more or less the same a few months ago, about initial flush production and later decline.

I think you are too optimistic here. I don´t expect more than 4k, based on what IR told you.

This is the reason why AB talked about production "according to expectations", instead of providing specific numbers.

People here expecting 10k per day should adjust their rosy views.

I even remember that one poster (DD) was angry with me when I expressed my discontent about management not providing exact numbers in the last conference call.

I was trying to remember the last time ENQ provided a positive operational update, but I couldn´t.

US$ 800 millon investment to produce 4k. The kuwaities should be very happy by now.

Regards

Fernan

Hi L3:

regarding the Brent futures curve for 2019, I was thinking the same today. Future prices for each and every month in 2019 are above US$ 80/b. It´s high time for management to hedge in my oppinion. I wouldn´t be surprised to see that they make some swaps deals, since swaps don´t cost a penny.

Here are Brent future prices:
https://quotes.wsj.com/futures/UK/BRENT%20CRUDE/contracts

In relation to the "spare capacity" that the saudis are supposed to have, I really doubt that they have any meaningfull amount available right now. In fact, I don´t understand the very concept of spare capacity. what is it made of? wells that are already drilled and completed, ready to be put online in a few minutes? wells that are required to be drilled before being ready to produce?

what is the point of investing millons in drilling and completing wells, only to put them aside as "spare capacity"?

In spite of supossedly being able to get to 11 or 12 millon barrels per day, the saudis have never produced more than current levels.

Just my oppinion

Fernan

Hi Matrix.

In their last conference call, Cairn Energy mencioned a 30% water cut.

This is what they said about that:

"we're [setting out] expectations of around 30% water cut, and we're about higher than that"

I understand that water cut is the amount of water produced, as a percentaje of the amount of fluids produced from the field, including oil and water (correct me please if I´m wrong).

According to this, with an oil production of, say, 35.000 bopd, water production should be around 15.000, for a total liquids production (oil + water) of 50.000 barrels per day.

But, according to the Kraken production profile presented by Enquest (see November 2013 presentation, page 48), water production was forecasted to be well in excess of oil production. For example, for a forecasted oil production of 45.000 barrels per day in the second year, water production was anticipated to be around aprox. 93.000 barrels

So, what is the real amount of water produced from the field? and what are the implications of this in terms of oil production, opex per barrel, etc.?

O woulk like to hear your comments on the subject

Thanks in advance

Fernan