Member Info for Fernan10

Good evening.

I understand that all countries that are in the European Union are required by the treaty to support other members in the case of territory disputes with third party countries.

After leaving the Union, the UK will not longer have that enforcement in its position in relation to the Falklands.
Argentina have already said that, once Brexit is in place, it will insist in their reclamation against the UK in the international arena. They hope that countries such as Spain or Italy could support their claim.

That in turn could influence the desire of the UK government to openly support a project that will inevitably be resisted by Argentina and likely other south american countries.

I think there is chance for the UK government to inform PMO and RKH that, even though it´s not against the project, it can not provide any funding or guarantees under the UKEF facilities.

That could jeopardize the ability of the sponsors to get banking finance, absense any involment from UKEF.

Just my oppinion

Fernan

The obvious question now is: will the chinese be willing to go ahead with the development programme in Barryroe after knowing this? the risk/reward model have substantially changed for them

Regards

Fernan

In case that, as a consecuence of thi bill, LOGP is unable to continue developing the Barryroe field, I understand that LOGP will have the right to recover all investments incurred in the project.

As a reference, the value of Intangible Assets on LOGP balance sheet at June 30, 2018 is 15.003.000 pounds (equivalent to 2,2p per share).

In a similar case, Rockhopper (RKH) has sued the Government of Italy after a legislation was passed prohibiting offshore dilling less than 12 km from the shore. At the moment the prohibiltion was enacted, RKH was developing a project that in the end have to be cancelled. RKH is trying to be compensated for past costs incurred and profit loss before a World Bank Arbitration panel. A decision is expected for Q3 this year.

I would like to know what the chinese are thinking about this bill.

Regards

Fernan

Excerpt from the draft bill:

"When making a decision on an application for a licence, undertaking
or lease under this Part, the Minister shall have regard to national and
global climate and environmental conditions, and without prejudice to
the generality of the foregoing, the Minister shall have regard to—

(a) the annual average global temperature, including annual rates of
change thereof,

(b) the monthly mean level of atmospheric carbon dioxide measured at
the Mauna Loa Observatory,

(c) the national transition objective,

(d) an approved national mitigation plan, and

(e) any national adaptation framework.

(2) The Minister shall not grant a license, undertaking or lease under this
Part, if on the date of the application for the license, undertaking or
lease, the monthly mean level of atmospheric carbon dioxide measured
at Mauna Loa Observatory exceeds 350 parts per million."

COMMENTS:

1. The petroleum license system in Ireland is comprised of:

Licences for prospecting work (pre-drilling): Licensing Option (duration varies, depending on work programme);
Petroleum Prospecting Licence (maximum 3 years);

Licences for exploration (including drilling commitments): Standard Exploration Licence (6 years); Deepwater

Exploration Licence (9 years) – no deepwater areas are currently licensed; Frontier Exploration Licence (12 years
minimum); Reserved Area Licence (which covers the extension of a discovery that lies outside the area covered by
the Petroleum Lease).

Lease Undertaking: a licence which can be converted into a Petroleum Lease in the event that a discovery is
established as being commercial

Production licences: Petroleum Lease which covers a duration commensurate with the life of the field.

Under the proposed bill, in the case of a discovery, you can not for example convert an Exploration License into a Production license if, at the moment of the required convertion, the metrics to be used for climate change are above the parameters established in the bill.

2. From Google: Carbon dioxide levels measured at NOAA's Mauna Loa Atmospheric Baseline Observatory averaged more than 410 parts per million in last April and May, the highest monthly averages ever recorded, and above the limit set in the proposed bill

Regards

Fernan

Excerpt from the draft bill:

"When making a decision on an application for a licence, undertaking
or lease under this Part, the Minister shall have regard to national and
global climate and environmental conditions, and without prejudice to
the generality of the foregoing, the Minister shall have regard to—

(a) the annual average global temperature, including annual rates of
change thereof,

(b) the monthly mean level of atmospheric carbon dioxide measured at
the Mauna Loa Observatory,

(c) the national transition objective,

(d) an approved national mitigation plan, and

(e) any national adaptation framework.

(2) The Minister shall not grant a license, undertaking or lease under this
Part, if on the date of the application for the license, undertaking or
lease, the monthly mean level of atmospheric carbon dioxide measured
at Mauna Loa Observatory exceeds 350 parts per million."

COMMENTS:

1. The petroleum license system in Ireland is comprised of:

Licences for prospecting work (pre-drilling): Licensing Option (duration varies, depending on work programme);
Petroleum Prospecting Licence (maximum 3 years);

Licences for exploration (including drilling commitments): Standard Exploration Licence (6 years); Deepwater

Exploration Licence (9 years) – no deepwater areas are currently licensed; Frontier Exploration Licence (12 years
minimum); Reserved Area Licence (which covers the extension of a discovery that lies outside the area covered by
the Petroleum Lease).

Lease Undertaking: a licence which can be converted into a Petroleum Lease in the event that a discovery is
established as being commercial

Production licences: Petroleum Lease which covers a duration commensurate with the life of the field.

Under the proposed bill, in the case of a discovery, you can not for example convert an Exploration License into a Production license if, at the moment of the required convertion, the metrics to be used for climate change are above the parameters established in the bill.

2. From Google: Carbon dioxide levels measured at NOAA's Mauna Loa Atmospheric Baseline Observatory averaged more than 410 parts per million in last April and May, the highest monthly averages ever recorded, and above the limit set in the proposed bill

Regards

Fernan

Good morning.

I read recent articles in the Irish Examiner about the proposed legislation to ban all petrolum drilling offshore Ireland.

Here they are:

https://www.irishexaminer.com/breakingnews/business/proposed-offshore-drilling-ban-legislation-criticised-ahead-of-dail-vote-913485.html

https://www.irishexaminer.com/breakingnews/business/dail-set-to-vote-on-bill-banning-oil-drilling-913201.html

what do you think are the real chances of such legislation to passed through the legislative body? and if it gets passed through it, do the executive have any power to veto it?

I was surprised that the issue was not fully discussed on this board.

In case the ban is effectively imposed, I supposed that both PVR and LOGP will have the right to being compensated for all the efforts an costs already incurred in Barryroe

Living in Sudamerica, it´s difficult for me to fully understand the risks involved here

I would like to hear your comments on the subject

Thanks in advance

Regards

Fernan

Good evening Manyana.

I read recent articles in the Irish Examiner about the proposed legislation to ban all petrolum drilling offshore Ireland.

what do you think are the real chances of such legislation to passed through the legislative body? and if it gets passed through it, do the executive have any power to veto it?

I was surprised that the issue was not fully discussed on this board.

In case the ban is effectively imposed, I supposed that both PVR and LOGP will have the right to being compensated for all the efforts an costs already incurred in Barryroe

Living in Sudamerica, it´s difficult for me to fully understand the risks involved here

I would like to hear your comments on the subject

Thanks in advance

Regards

Fernan

Hi Phoebus.

do you think is there any chance of data from Stabroek block becoming available to other operators in offshore Guyana, in order to improve their chances of success in their respective drilling campaigns? is there any legal obligation for Exxon to share this data?

I´m sure the local government is the most interested in having as many oil discoveries as possible.

Thanks in advance

Fernan

Hi Phoebus.

I read your post about the amount of resources to be drilled in this year´s drilling campaign.

Just one clarification: they are not planning to drill the Rappu lead under the Joe prospect for the time being.

See page 44 of the CPR:

"The Rappu Lead is an Upper Cretaceous age that lies underneath the Joe Prospect. This target is a broad and potentially thick target (Figure 3-26) the extent of which is shown on the seismic lines in Figure 3-27. This lead is considered a high risk target at this point therefore the current plan is to drill only the shallower Joe prospect and utilize the information from the Jethro well to reduce the risk of this deeper target."

Regards

Fernan

Hi Hitman.

Last operational update states the following:

"Cash capital expenditure was approximately $220 million; below guidance of c.$250 million primarily due to phasing from 2018 in to 2019".

It means that ENQ have deferred the payment of suppliers invoices for aprox US$ 30 million

Then, as per my previous post, maintenance capital for 2019 will be of US$ 185 million, as follows:

Total CAPEX for 2019: US$ 275 million
DC4 CAPEX (as my previous post): US$ 60 million (net to ENQ)
Invoices deferred: US$ 30 million (as per last operational update):

Maintenance capital for 2019, in order to keep production flat year on year (excluding production from the acquisition of 75% of Magnus): US$ 185 million

As I said before, I can´t see how this amount of annual maintenance capital could be reduced to US$ 100 million in future years

Regards

Fernan

regards

Fernan

Hello Hitman.

Thanks for your response. You have an interesting view on how ENQ should manage cash flows in the medium and long term. Nice that we can discuss these issues without being agressive.

I have some doubts about the US$ 100 million of deferred payments of suppliers mencioned by you.

I understand that those invoices were accounted for in 2018, as part of CAPEX for that year. Because the payment of those invoices was deferred, the amount of cash at year end was not impacted (hence net debt at the end of the year was lower than previously expected by most here).

So, in 2018, you had CAPEX of US$ 100 million that was financed by an equivalent increase in current liabilities at year end, with no effect in cash and financial net debt.

If this is the case, the US$ 275 million in CAPEX expected for 2019 is in addition to and doesn´t include the payment of those invoices.

I would like to hear other views on the subject

Regards

Fernan

Good morning.

The US$ 50 million cost per well is the average cost informed by ECO to drill in Guyana. In light of the info provided by you, it seems too high a cost for the North Sea.

But, on the other hand, I think you could not extrapolate drilling costs for the last 2 or years into the future. During the last oil debacle, drilling rates slump to less than 50% of what they used to be in the times of 100 oil. In the last few months, the market for harsh environment semi subs in the North Sea has been tightening up, and, in such a scenario, it´s razonable to expect drilling rates to raise in the future (see the following article: https://seekingalpha.com/article/4228133-offshore-drilling-end-2018-semi-subs)

But my whole point is that I can´t see how ENQ could sustain production with the levels of CAPEX bandied about here (US$ 60-75 million per year). ENQ is in the business of rejuvenating oil fields and infraestructure, and you need to spend money to do that.

For example, for 2019, ENQ provided a guidance of US$ 275 million CAPEX. Talking about CAPEX for the this year, Cairn said the following: "$25 million of development expenditure in the producing assets relates mainly to the completion of the DC4 drilling on Kraken in the early part of this year. "

Then, Kraken CAPEX for 2019 will be around US$ 85 million on a 100% basis (US$ 60 million net to ENQ).

Al these mean that, in 2019, ENQ will have CAPEX (excluding Kraken) of US$ 215 million (total CAPEX of US$ 275 million less US$ 60 million on Kraken), only to have production essentially flat year on year (excluding production added from the acquisition of 75% of Magnus).

I would say that "maintenance CAPEX" for ENQ in 2019 will be US$ 215 million. I can´t see how this number could be reduced to less than US$ 100 million in the future

Regards

Fernan

Hi Hitman.

I read what you wrote about drastically reducing the amount of CAPEX in future years, in order to improve FCF and then repay debt more quickly.

In my oppinion, the numbers you are thinking about (CAPEX in the range of US$ 50-75 million per year) are not attainable.

I would say that, given the decline rates of the older fields in the portfolio, ENQ needs to drill on average 2 wells (on a net basis) per annum, in order to add net production of around 10.000 bopd, offset those declines and keep production flat.

At a drilling cost of around US$ 50 million per well, you are talking of US$ 100 miillion per year.
Add to that the cost of facilities revamping, etc, and you will have an amount of "maintenance CAPEX" of around US$ 150 million per year

It would be interesting to know directly from management what is the amount of "maintenance CAPEX" that the company requires annually, in order to keep production flat.

I´m sure AB has already calculated this. it would be interesting to hear his estimates.

Regards

Fernan

It would be interesting to know directly from management

E121:
as I said before, I didn´t like the fact of having a respectable oil production company taking an impairment charge, due in part to a production issue that was never informed by the operator. And I didn´t change my mind on that.

But that is a completely different issue of ENQ not being obligated by their external auditors to take an impairment charge, because of the way its calculates the NVP of their oil fields.

Regards

Fernan

Hi E121.

I´m sure that JS will provide a clear explanation about the lack of an impairment charge in the 21st. No reason to panick here.

Regards

Fernan

I think you are spot on Hitman.

By including resources from the Western flank on the "Greater Kraken area" Cash Generating Unit (CGU) (see my previous post), it´s likely that the NPV of future cash flows from this business unit will still be greater than the accounting cost of the field. Then, ENQ will not be required by their external auditors to take an accounting impairment.

Regards

Fernan

Good morning.

Note 2 to ENQ´financial statements for fiscal year 2017 states how management perfom an impairment test:

"Determination of whether oil and gas assets or goodwill have suffered any impairment requires an estimation of the fair value less costs to dispose of the CGU (I think this stand for Cash Generating Unit) to which oil and gas assets and goodwill have been allocated. The calculation requires the entity to estimate the future cash flows expected to arise from the CGU using discounted cash flow models comprising asset-by-asset life of field projections using Level 3 inputs (based on IFRS 13 fair value hierarchy). Key assumptions and estimates in the impairment models relate to: commodity prices that are based on forward curve prices for the first three years and thereafter at $70/bbl inflated at 2.0% per annum from 2022; discount rates derived from the Group’s post-tax weighted average cost of capital of 10.0% (2016: 10.0%); commercial reserves and the related cost profiles. As the production and related cash flows can be estimated from EnQuest’s experience, management believes that the estimated cash flows expected to be generated over the life of each field is the appropriate basis upon which to assess goodwill and individual assets for impairment."

The external accounting firm (Price Watehourse and Coopers) informed in the report the activities executed by them in order to revise management assumptions in the impairment test of oil and gas reserves:

We carried out procedures to understand and
walk through EnQuest’s process for identifying
impairment triggers, reversal triggers and
considered management’s assessment
of indicators.
We audited management’s assessment of
impairment indicators and whether or not a
formal impairment test was required.

Where a formal impairment test was necessary,
we audited management’s assumptions and
sensitivities. This included specifically the
determination of cash generating units, cash
flow projections, oil prices, production profiles,
capital and operating expenditure, discount
rates and sensitivities used. In addition we
engaged our valuation specialists to assist us in
the audit of discount rates.

Regards

Fernan

Phoebus/Hereandnow:

thanks for your comments.

So Phoebus, you are basically saying that, because LC capital is just under the 30% threshold, they can not convert the debt into shares without crossing that threshold and being obligated to make a mandatory bid for the company.

I think this is the reason why they didn´t convert the whole amount of debt last year, and they will likely refinance it come the June 30 deadline.

Thanks very much for your clarifications

Regards

Fernan

Goor morning Phoebus.

You wrote:

" Also, I guess they can't convert anymore without having to make a mandatory bid as they are already at the 30% threshold."

I don´t know what you are talking about. Could you please elaborate or explain in layman terms?

Thanks in advance

Fernan

I´m not saying that ENQ is not respectable.

And yes, of course there could be more skeletons in the closet

Another issue: If, as a result of higher water cuts than expected, production plateau could not be higher than 40.000 bopd, then Bumi could be tempted to renegociate their tariff again. I undestand that ENQ applies the discount on the leasing rate based on the difference between potential production from the reservoir and real production. If the potential production is lower than expected, then the discount should be reduced too.

Regards

Fernan