Member Info for Fernan10

I would like to see the company getting rid of this obligation and preserving the cash to invest in Guyana.

That´s what I would do if I were the sole owner of ECO.

Regards

Fernan

Some people here say that the upcoming well in Namibia will be cost free to ECO.

I don´t think it´s the case.

Here is what the last MD&A report states (page 8):

"The Tullow Agreement was amended on February 1, 2017 (the “Tullow Amended Farmout
Agreement”). Pursuant to the Company’s farmout agreement with Tullow Namibia as amended on
February 1, 2017 (the “Tullow Amended Farmout Agreement”) if Tullow Namibia elects to proceed
into the second renewal exploration period or commits to drill an exploration well on the Cooper License
before such time, Tullow will acquire from the Company and Azinam an additional 15%working interest
in the Cooper License and become the Operator of the Cooper License. In addition, subject to a minimum
contribution of US $2.25 million by the Company, Tullow Namibia will carry the Company in respect of
the Company’s share of any drill costs in relation to the first exploration well (if proposed and drilled by
Tullow) up to a total well cost of US $35 million. In addition, Tullow Namibia will reimburse the Company
for 17.14% of all past costs incurred and paid for by the Company in respect of the Cooper License (save
for any costs already reimbursed, paid or carried by AziNam or Tullow Namibia)."

The reimbursement of past costs to ECO will not be significant in my oppinion. So, in case Tullow decides to proceed with drilling a well, ECO will have to contribute a minimum of US$ 2,25 million, less 17,14% of all past costs incurred by the company.

Comments?

Regards

Fernan

Cormorant-1 Exploration well in PEL 37 Offshore Namibia Result

 Target Submarine Fan sequence thicker than expected intersected close to
predicted depth

 Well at Total Depth (TD) and preparing for abandonment

 No accumulated hydrocarbons

 Gas shows indicate an active source system

 Further significant potential for the play

Pancontinental Oil and Gas NL (ASX: PCL, “Pancontinental”) advises that the Cormorant1
exploration well in PEL 37 offshore Namibia has reached a total measured depth of
3,855m and is to be plugged and abandoned as a dry hole.

The well has been efficiently drilled by operator Tullow Oil, reaching total depth on 21
September 2018, materially quicker than prognosed.

The Early Cretaceous age Cormorant Submarine Fan target was encountered close to the
predicted depth but no accumulated hydrocarbons were found. The Fan contained
approximately 50m thickness of interbedded sands and claystones that were water-wet

Wet gas signatures, indicative of oil, were first encountered in the overlying shale section
and persisted throughout the target interval, indicating that there has been significant
hydrocarbon generation in the area. Important geological data has been gained from this
well, providing valuable insights into the prospectivity of the Aptian-Cenomanian
turbidite fans that are still valid exploration plays with very large oil resource potential
in Pancontinental’s acreage both in PEL 37 and, further south, in PEL 87 (Pancontinental
75%).

Cormorant-1 is the first modern well to penetrate this stratigraphic section in PEL 37,
(covering some 17,000Km2), and the Joint Venture is in the early stages of analysing the
results. The analysis will assist the geological understanding, and the associated
discovery probability, of other prospects and leads in PEL 37, some of which have
significantly larger resource potential than Cormorant.

The well data supports the presence of at least one active source rock system, with
encouraging implications for the range of play types mapped in the block, and in PEL 87.
Pancontinental Oil & Gas NL owns two thirds of Pancontinental Namibia Pty Ltd, which
holds a 30% participating interest in PEL 37, giving it a 20% effective interest in PEL 37.

The participants in Cormorant-1 areTullow
Namibia Limited (Operator) 35.00%
Pancontinental Namibia Pty Ltd 30.00% *
ONGC Videsh Limited 30.00%
Paragon Oil & Gas (Pty) Ltd 5.00%

* Ownership of Pancontinental Namibia Pty Ltd:
Pancontinental Oil & Gas NL 66.67%
Africa Energy Corp. 33.33%

From the article:

"acceleration in base decline will eventually lead to the decay in the pace of production additions."

This is the reason why some analysts think that US shale growth will come to a halt in a few years´ time.

Regards

Fernan

In simple terms, US shale completed 1.276 wells in July 2018.

At an average initial production of 500 bopd (typical of wells in the Permian), we have that the first 1.000 wells completed during the month were to offset the 500.000 bopd monthly base decline.

Net growth came from the remaining 276 wells
276 wells X 500 bopd= monthly growth of 138.000 bopd, for an annualized growth rate of 1,6 million bopd

As time passes, the total number of wells needed just to offset base decline will only growth.

Regards

Fernan

Very interesting article on US shale base decline:

"Significant expansion of shale activity in the Permian Basin and other U.S. Liquid plays comes at the cost of accelerated base decline. Base decline shows how quickly oil production falls in the first month if no new completions are turned-in-line. In pre-unconventional oil era (2006-2009), U.S. Land oil base decline was observed at 50-60 thousand bpd. As of 2H 2018, U.S. Land needs to add more than 500 thousand bpd of new oil monthly just to keep production flat. U.S. oil production exhibits all-time high YoY growth of 1.6 million bpd as of June 2018, but acceleration in base decline will eventually lead to the decay in the pace of production additions. Material increase in shale investments is needed in 2019 to maintain YoY growth above 1 million bpd through the end of 2019."

https://www.rystadenergy.com/newsevents/news/press-releases/Accelerated-base-decline-in-the-U.S.-Land/

From Oilprice.com:

"Bullish outlook affects hedging. As the oil market outlook takes on an increasingly bullish tone, oil companies have pared back their use of hedging, hoping to gain exposure to higher prices. Meanwhile, major consumers, such as airlines, have boosted their hedging to protect themselves from the risk of higher prices. The reshuffling of the hedging mix is affecting the oil futures curve. “The major story for oil right now is not $80 a barrel, but what’s happening at the back end of the forward curve,” Thibaut Remoundos, co-founder of Commodities Trading Corporation, told the FT. “Hedging by oil producers in Brent-linked contracts is dropping off in expectation of higher prices in the future, while major consumers like airlines have been rushing to buy for the same reason. You would need to go back to 2007 to see this level of hedging from consumers.”

Good morning.

Wouldn´t it be better for shareholders to spin off Enquest´s equity in Magnus into a separate company ("Magnus PLC")?

In simple terms, if Magnus´s 37,5% interest has a NPV of around US$ 500 million (after the repayment of the US$ 100 million debt outstanding to BP), then the whole 62,5% interest should have a NPV of around US$ 800 million (much more than ENQ´s current market cap).

Such spin off will give the market more visibility about the real value of the project.

Of course, in such a case, ENQ will remain the operator of the field, and will invoice "Magnus PLC" for incurred costs of operation, plus a reasonable fee.

Two issues to consider in such a spin off:

1.ENQ lenders´consent:
It´s necessary to remember that the acquisition of Magnus (January of 2017) was done after the conditions of current debt (facility + bonds) where agreed (during the last debt restructuring in October of 2016). So I don´t know if they have the right to oppose to the spin off.

2. Accumulated tax losses.
Part of the Magnus NPV depends on the existence of substantial accumulated tax losses. In the country I live, the tax law considers the spin off as a "business reorganization", and allows for the transfer of such tax losses to the new entity, in a proportion of total accumulated losses of Enquest PLC. I don´t know what the english tax law states in relation to that. Off course, Enquest´s lenders could oppose to the transference of such tax losses, but I don´t know if they have the right to do so.

Comments?

Thanks in advance

Fernan

Hi MO.
do you have any idea how much revenue ENQ will collect in the future from the following assets:

Sullom Voe Terminal ("SVT") (15.1%)
Ninian Pipeline System (18.0%)
Northern Leg Gas Pipeline (t41.9%)

Thanks in advance

Fernan

You´re welcomed, E121.

In my projections, I didn´t include the future revenue from tariffs for the use by third parties of the infraestructure included in the deal.

Enquest´s IR accepted that this is a "complex" deal, and that my questions were similar to those of other investors.

Regards

Fernan

Add to that the cash flow from the 25% already acquired (less the corresponding outstanding loan with BP) and Enquest could get aprox. US$ 200 million of net cash flow from Magnus in 2019.

Regards

Fernan

Goor 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

Comments?

Regards

Fernan

Regards

Fernan

Hi MO.

I can now understand Barclays analysts when they talk about an "overly complicated" business.

Later in the day I will try to read and understand you post (I suspect I will need some time for that). Thanks

Regards

Fernan

Regarding the repayment of the vendor loan, the prospectus for the acquisition states the following (page 182):

"US$100 MM from the agreed and adjusted purchase price will be paid in cash at
the time of deal closing (assumed to be year-end 2018).

􀁸 BP finances the remaining part of the agreed and adjusted purchase price through
a non-recourse loan under a loan agreement subject to a cap of US$500 MM. The
repayment is made from 75% of the Magnus asset cash flows with 100% availability
in year 1, 50% availability from year 2 to year 5 and thereafter the availability is set
to 100%. The target term of the loan is 5 years with an annual interest of 7.5% on
the outstanding loan amount."

Any interpretation about what "availability" means in this context? does it mean that not all the cash flow from Magnus will be "available" to repay the vendor loan, and then, part of the amortiztion will be witheld until a future date?

I think this is important to forecast any potential liquidity issues in 2019. Enquest needs to repay US$ 275 million of the facility, in addition to the remaining balance of the Mercuria loan and the new OZ ring-fenced loan on Kraken. The financial situation looks to be tight. If there is some leniency in the repayment of the vendor loan on Magnus, every little helps.

During the conference call, JS said the following:

"Once we have received our $100 million cash upfront back, then going forward, then, let's say, this is over $20 million a year for 5 years to BP. Then that comes out first. And then after that, then that's the profit share between us and BP."

I understand from my previous post that the reimbursement to Enquest of the US$ 100 million to be paid at the time of completing the deal comes after the repayment of the vendor loan. But JS is suggesting otherwise here.

Again, if the reimbursement to Enquest comes before the repayment of the vendor loan, it also helps with the cash flow projected for next year.

So, in summary, I have two doubts here:

1. what is the amortization schedule of the vendor loan?
2. does the reimbursement of the US$ 100 milllion to be paid by Enquest come before or after the repayment of the vendor loan?

Comments?

Regards

Fernan

Some interesting excerpts from the CPR on Magnus

The total hydrocarbon initially in place has been assessed by EnQuest as including
1,877 MMBbl of STOIIP, of which 1,496 MMBbl were in the Magnus Sandstone Member,
and 381 MMBbl in the Lower Kimmeridge Clay Member, with some additional volume in
localised reservoirs in the Brent Group. GCA has confirmed the general validity of the static
model from which these volumes are derived as part of this study.

Field peak production rate was about 195 Mbopd, which had declined to about 16.6 Mbopd
by June, 2018 (Figure 4). Cumulative production to 30th June, 2018 was 930 MMBbl of oil
and 810 Bscf gas, with a water cut of 89%. GCA estimates that produced gas represents
approximately 685 Bscf of indigenous solution gas, with the remainder being recycled
injected gas from other sources. The recovery factor to date is therefore around 49%.

Magnus is a mature producing oilfield that has been largely swept by both water and
gas. Any new development wells will be expected to encounter high water cuts and/or
GORs. The field has been producing at over 85% water cut since about 2003
(Figure 4) and, with effective reservoir management, wells can be expected to recover
significant amounts of oil at increasingly high water cuts.

EnQuest’s development plans for the field are based on drilling new wells and recompleting
existing wells to target areas that will have already been partially swept. There is some risk
in this philosophy in that the success of any new wells will depend on the degree that the
reservoir has been swept and the initial oil rates. The Reserves attributed to new locations
have been estimated largely on the basis of analogy with offset wells and this is considered
a reasonable process to establish Reserves. However it is anticipated that more detailed
reservoir analysis underway will provide additional technical support prior to finalising
precise well trajectories, and commencing drilling in 2019.

Table 5: Mid Case Oil Recovery from 1st July 2018 to end 2030
Project Oil Recovery to 2030
(MMBbl)
Base 46.7
M62z 1.7
M63 4.6
2018 Wellwork 1.0
Voidage Management 2.6
Canute LKCF 4.1
Central Area T10/T11 2.0
Total 62.5
Note:
1. Volumes shown here are produced volumes; sales volumes will be 5% lower due to shrinkage.

Production forecast in page 173 of the report

Regards

Fernan

I´ve been a critic of AB for his repeated failures and breach of promises in Alma Galia, Scolthy Crathes and Kraken. But now it seems he got a great deal at Magnus.

Fernan

I´m surprised so see that the US$ 100 million payment by Enquest to BP will be repaid out of the cash flows to be generated by the project. For BP to accept this, they should have a lot of confidence in Enquest´s capabilities to improve the performance of the asset.

just my oppinion

Fernan

Hi E121.

The way the deal is structured, after the repayment of the vendor loan to BP (in 2019) and the recovery of the US$ 100 million initial investment by Enquest (in 2020), Enquest is buying 37,5% of the free cash flow generated by the project (after CAPEX) for free.

This in addition to the acquisition of the initial 25% stake in the project, for free also.

Regards

Fernan

Conclusions:

1.Debt to BP expected to be reduced by approximately US$ 100 million by Dec 31, 2018

2.Interest rateapplicable on the vendor loan of 7,5% per annum

3. Maximum amount to be received by BP under the profit sharing agreement is: US$ 600 million/ (1- tax rate). At a tax rate of 40%, it is equivalent to US$ 1 billion (gross)

4. There is nothing about the right of Enquest to defer the payment of the vendor loan in annual installments.

5. After BP has recovered the value of the vendor loan from the cash flow generated by the project, Enquest has the right to recover the US$ 100 million payment to BP on completion of the deal.

Comments

Fernan

Each Net Cashflow Gain is applied as follows:

(a) first, to pay BPCO any outstanding amount of principal, interest (including incremental interest),
costs or other amounts, then outstanding and due under the Loan Agreement to which BPCO is
entitled to be paid pursuant to STWD (the “Loan Repayment Amount”) (but excluding
incremental interest);

(b) next, to reimburse EnQuest Heather up to an amount equal to any outstanding “Positive
Consideration Reimbursement Amount”, being the sum of: (i) the amount actually paid by
EnQuest Heather to BPEOC as partial consideration for the 75 per cent. Interests at completion
under the Magnus Call Option Deed (excluding any amounts drawn down by EHL under the Loan
Agreement at or immediately prior to completion) (the “Positive Consideration Amount”); plus
(ii) the amount of any Loan Prepayment Amounts received by BPEOC on or before the relevant
date; minus (iii) the amount of any Paid Buyer Claim Settlement Amounts received by EnQuest
Heather; minus (iv) any amounts already reimbursed to EnQuest Heather in respect of Positive
Consideration Reimbursement Amounts, together with interest at rate of 10 per cent. per annum
applied to the resulting amount;