Member Info for SEA7

thanks bhads

anyone know them....

On the 5 June 2018 the Company entered in an agreement with Ace Capital Group Ltd (“Ace”), to engage Ace as subscription agent to the Company for the purposes of raising capital for the Company.

The Company entered into an engagement letter with Orion Securities Norway (“OSN”) on 4 June 2018 pursuant to which OSN is retained as subscription agent to the Company for the purposes of raising capital for the Company.

true, this also from the prospectus.

Pursuant to a broker agreement dated 14 December 2017 (amended 22 January 2018), Daniel Stewart
& Company Plc (Daniel Stewart) were engaged by the Company for the purposes of acting as the
Company’s Lead Broker in connection with a placing to raise up to £10 million by way of an issue of
new Common Shares.

.............

Does the £2m raised recently account for 1/5th of that amount and it would indicate that there are plans for more.

wonder which workovers these were....

from the prospectus.....................Two workovers are considered to be unsuccessful

If fully successful, the workover of 12 wells in 2018 could increase production by up to 40STB/d, achieving
a field production rate of up to 780STB/d by the end of the 2018 financial year.

An additional increase in production up to the Company’s goal of 1,000 STB/d could be achieved from the
resizing or resetting of EPS’s and purchase additional equipment. That case has not been reflected in the
economics analysis in this Document. On that basis, the field oil production rate will exceed 1.5 times the
average 2015 rate in late 2018, ensuring that the Company will retain its rights under the REDPSA.

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Based on the above extract, they are expecting around 220STB/d from the ESP programme.

That is true, I have other investments, whereby you do not hear from them from one rns to the next, apart from the odd presentation.

https://twitter.com/zenithenergyltd?lang=en

Tweet of the removal of ESP from M63.

They carried out digital log analysis on a number of wells across the field to get a feel for the quality of the results that can be obtained from the older GIS logs.

One example of the benefit of this was M58, where several, potential hydrocarbon bearing uphole zones were identified. These zones will be examined during the future drilling operation and could result in major new uphole plays throughout these fields.

They also state that since the signing of the REDPSA stable rates of production have increased by about 25STB/d. The stable rate back in 2016 was about 276 STB/d if I recal. So, 300STB/d is about right.

MOC-1 has 14.8m net pay, average porosity of 11% over the pay zone and 32% water saturation.

They are talking about MOC-1 in the Horizontal drilling section of the cpr. They talk of the first well in the drilling program to be drilled vertically to capture as much technical reservoir information as possible, including cores and a modern suite of open hole logs. Once reservoir and fluids are understood the driling and completion programme can be designed to minimise reservoir damage and maximise the well results.

another extract from cpr...

The drilling programme will be undertaken with caution as there will be a learning curve from each new experience. Wells will be logged open hole, with a carefully designed programme. Current water contacts will be detected from the well logs and may lead to altered plans.

...............

Whilst it may seem to us that nothing is happening apart from share price destruction, when you read the cpr, it paints a very different story of some of the ongoing work being undertaken.

The gathering system and central facilites were shown as being expected to be taking
2,517 STB/d in 2020, however, this figure is shown as 1,768 STB/d In the 2018 CPR.

Upgrades to the system were expected in 2020, whereas they now state upgrades taking place in 2018 and 2020.

Production is expected to be at 14,845 STB/d by 2033 instead of 13,693 STB/d in the 2016 CPR. So an upwards revision here.

They state in the 2016 cpr that they were producing approximately 300 STB/d from 64 wells, whereas in 2018, they state approximately 298 STB/d from 47 wells.

This does mean that 17 wells are gone, saving $510k per year on well costs.

Approximate production is down 2 barrels per day, according to this, so all the mediocre production from the abandoned wells, has been taken up by the improvements
made in the other wells, that have had work done on them.

It would appear that all that is really happening at this stage is a maintenance of production levels around existing levels and the focus on zardab.

I note in the updated cpr, they state that fixed field operating costs are $1.95m per annum, whereas the 2016 CPR states $1m per annum.

per month well costs are estimated at $2,500 per well, down from $3000 in 2016
variable costs have reduced from $10 stb down to $2.25 STB.

The first fixed field costs were on the historical data and a multi year budget provided by zenith, the updated one, is based on historical data and an expense spreadsheet provided by Zenith.

It would appear that zenith seriously underestimated the annual fixed costs, over priced the monthly well costs and seriously over estimated variable costs.

What does the data tell us, that despite their errors, they are quoting about the same overall amount, as in 2016, just with different figures for the same items.

They should only have shame if they are not genuinely making an effort.

from the interims....

The Company’scash flows from its Azerbaijan and Italian operations will be needed in the near term to finance the operations and repay vendor loans. Zenith’s principal source of funds will therefore remain the issuance of equity. The Company’s ability to raise future capital through equity is subject to uncertainty and the inability to raise such capital may have an adverse impact on the Company’s ability to continue as a going concern.

I always knew they would be raising sooner or later and knew that if they wanted to go beyond the rolling 12 month limits for equity issuance on a main market listed stock they would need a propectus, as they need to get as ready as they can for the main drilling stages of this operation. The workovers are important, however, they are just stage 1.

They need to get some decent production going, to be able to start looking at some serious reserves based lending for the much larger drilling program and seimic surveys.

If they cannot get past 1.5 times the 2015 production level by Oct 2019, then Socar has the right to terminate the agreement and zenith could be off the site. It is unlikely as they should be able to be beyond that figure sooner rather than later, however, as long as they can demonstrate that they are working the fields, then it is unlikely to be triggered in the event that they did not get past that figure.

I have been busy the last couple of days and not been near a screen during trading hours, however, I decided not to go near the primary bid offering and plan to see if I can soak up a bit of stock in the market.

Cannot say I am overly impressed with the price and timing of the raise, as they should have done this when it was at 10-12p a while back and I was somewhat surprised they didn't. It would seem they expected to be in a better position to raise and not at this level.

The expiry date of 3 October 2019 is considered reasonable to achieve the minimum production required by the RESPSA, as the Company plans between 2018 and 2020 to workover a total of 38 existing wells which are currently inactive or produce at low rates to bring rates up to as much as 40STB/d per well, using improved technology, non damaging fluids and optimised treatments. It is expected that 12 wells will be worked over in 2018, 15 wells in 2019 and 11 in 2020. If fully successful, the workover of 12 wells in 2018 could increase production by up to 40STB/d, achieving a field production rate of up to 780STB/d by the end of the 2018 financial year.

Pursuant to the terms of the REDPSA, Zenith Aran and SOA prepared and submitted a rehabilitation and production programme to achieve an average daily crude oil production from the Contract Rehabilitation Area of 1.5 times the average daily production rate in 2015, for at least 90 consecutive days, by no later than two years following SOCAR’s approval of the programme. SOCAR approved the programme on 3 October 2017. The 2015 average daily production was approximately 310 STB/d and accordingly the new target will be at least 465 STB/d.

They have until 3rd October 2019 to achieve that rate.

which I am reading and just posted a few highlights for those that haven't seen it yet

The prospectus for the placing.. https://www.zenithenergy.ca/wp-content/uploads/2018/06/20347-Project-Nobel-Prospectus-Clean.pdf

average daily production January 2017 281 February 2017 280 March 2017 271 April 2017 275 May 2017 266 June 2017 269 July 2017 266 August 2017 262 September 2017 253 October 2017 267 November 2017 279 December 2017 283 January 2018 249 February 2018 258 March 2018 277

The Company has undertaken nine well workovers between the effective date of the REDPSA in August 2016 and March 2017. The workover on C21 (Jafarli field) was relatively successful, returning the well to production at 10 STB/d. One other workover on M66 (Muradkhanli Volcanic) was partially successful, increasing production from 1.5 STB/d to 3.0 STB/d. Five other workovers are in progress or are waiting for equipment for finishing or milling. Two workovers are considered to be unsuccessful. As experience is gained, it is anticipated that the degree of success will increase. Electro submersible pumps (ESPs) have been resized and/or set deeper in 10 wells with a total production increase of 88 STB/d. One workover rig is active at present. One new workover rig has been purchased and is scheduled to be operational in June 2018. Additional equipment may be purchased or contracted as required to optimise field redevelopment. the historical performance of each well including peak rates, cumulative oil and water production, and recent performance has been studied to identify wells that are likely to have successful workovers. The results of previous workovers have been noted. Although most wells flow to surface, the installation of ESPs was generally very beneficial and is expected to form part of most future workovers. It is predicted that the field oil production rate will exceed 1.5 times the average 2015 rate in late 2018, ensuring that the Company will retain its rights under the REDPSA