Member Info for Slift

@shaml89,
"Premier wounds were self inflicted, they should not have bought Bp's assets if their financial condition was that critical, for that money they are looking to wipe out or heavily dilute share holders through rights issue and debt to equity swap.Tullow tried to do right think at wrong time by offloading Ugandan assets."
100% agree. Premier's debt had a maturity date of May 2021. There was no way Premier was going to pay c. $2b net debt within the time frame.. and even then.. they went on to acquire assets.
If i was a lender, i'd have forced them to raise the money themselves for the assets too, rather than use money that they have BORROWED off me to fund for it.

Tullow on the other hand has RBL ($1505m) debt maturity date of November 2024.
Ofcourse, they also have other debt maturity..
- $300m CB in July 2021
- $650m senior note in 2022
- $800m senior note in 2025
But Tullow is also raising cash via asset sales to fund and pay these off, opposite of PMO.

Slift.

@bransolbull,
I'm neither saying perched water or aquifer. But taking both into consideration as possible reasons for the watercut, when the toe of 7z is at 1280 m TVDSS (100m above the structural closure 1380 m TVDSS).

@Nic7760,
"If perched water it waas, should have emptied out a long time ago by now"
I don't think we can make this assumption. People are comparing the Lancaster FB to Vietnam, but this field (as per 2017 CPR) has closest analogues to Wangzhuang (China), West Puerto Chiquito (USA) and Zeit Bay (Egypt).
Personally, I'd agree that perched water in a large well reservoir should not produce the water cuts seen in 7z, especially for extended period of time. But this raises further questions.. how big is the perched water vs how big is the well reservoir?
Yes, there's data that shows that the well may be connected to more volume than expected, but read earlier post regarding bottom hole pressure, bubble point pressure and aquifer.

Now to the OWC - I don't think the CPR is wrong. THERE IS probably oil even below the 1380 m TVDSS structural closure. The CPR states this with confidence. But it seems like that in the current wells (6 and 7z), there's several scenarios:
1. This oil isn't commercially viable wih 6 or 7z (Note, the OWC for this field was obtained through the drill of well 7 and 7z is a sidetrack to the east). For example, the current fractures connected to 6 and 7z do not go beyond the structural closure.
2. The wells can produce the oil from beneath the 1380 m TVDSS structural closure, but due to limited connectivity of the fractures and the "hydrodynamic influences" experienced in FB, the rise in aquifer OWC is substanstial. I.e. it has already produced majority of the oil (that's accessible by 6 and 7z) via limited fracture connectivity from below 1380 m TVDSS, and so the aquifer for the 6 and 7z connectivity has caught up.

"My overall point remains, even with your numbers if they are true, that 7z pulls deeper than 6"
I don't think 7z can "pull deeper" than 6. If this is really aquifer water, then OWC has risen from 1380 m TVDSS (or even below that at 1653 m TVDSS) to around 1250 - 1300 m TVDSS since the start of the EPS - through the extraction of oil (and thus decrease in oil volume/pressure in the field).

What i'm trying to say is that 7z sidetrack will not be efficient or optimal solution to this.

As for HUR's material:
6 TVDSS is from slide 29 with speaker notes on the May 2015 presentation - "Devex - Enabling Geological Scale Dynamic Modelling of a Fractured Basement Reservoir using a high-Resolution Simulator - A UKCS Case Study -With speaker notes"
7z TVDSS is from Finding Petroleum's "Understanding Fractured Reservoirs & Rock" seminar, where Dr R Trice was a speaker. This isn't on HUR's website I don't think.

Slift.

and finally 4. @Nic7760 (if you're reading this and haven't filtered me already),
Just thought i'd comment on your initial post.
From your first post: "7z sits deeper than 6 and therefore has its "feet" in the water. That's why it's been sucking so much water all along. 6 is horizontal and at 1220m TVDSS, ie 160m above the OWC. 7z heel is at ~1300m TVDSS and its toe is at 1370m TVDSS, just 10m above the OWC.
So if the OWC is shallow, at ~1380m TVDSS, it should be absolutely no surprise that this well is sucking a lot of water from its toe."

Yes, this would have made sense.. that is if 7z heel was at ~1300m TVDSS and it's toe was at 1370 m TVDSS.
Well 6 is drilled to 1240 m TVDSS. I find 7z drilled to the toe (or the deepest point) at 1280 m TVDSS, but in fact the 1 km horizontal section ranges from 1210-1280 m TVDSS.
So imo, it is a surprise, considering that the toe/heel is located at OVER 100 m above the structural closure OWC. But it's not a surprise to say either 1. perched water, or 2. aquifer (or OWC) is rising due to pressure differential created by extraction of oil.

Slift.

3. Lancaster CPR (2017)
As mentioned above, this CPR has been written using Hurricane's findings.
Quote from CPR: "Our estimates of resources and value are based on the data set available to, and provided by Hurricane. We have accepted, without independent verification, the accuracy and completeness of these data"
Having said that, the documents and reports provided to the CPR isn't basic. They have been provided with technical documents from FEED, FDS, Basis of Design, FDP and Financial model etc.
I don't see this CPR being wrong based on the information provided.

I think my biggest question from this CPR report is relating to the bubble point pressure. The CPR indicates that the length for maintaining BHP above bubble point pressure is dependent on the extent of reservoir and may be partially or completely compensated for by the existence of an aquifer (and it's strength) within the field.
Looking back at that those charts in the edison report and 2020 CMD, the chart indicating the decrease in gradient of the BHP.. COULD be due to this aquifer support which is also providing the wells with a higher water cut. At least on the positive - if this is the case, then at least the BHP won't go below the bubble point pressure in "the next few months" as stated by some on this board.

Based on the Eclipse simulation model for the EPS in the CPR, gas production is 342.5 scf/barrel. For the current 2P reserves of 37.3 mboe, this would be c.2.2 mboe of gas. So if there's a downgrade due to gas reinjection "production enhancement option" --> then this would be -2.2 mboe to reserves.
Also, just for note - at current production of 17k bopd, the gas production is c. 1,000 boe/d gas. The AM's flaring consent is 2400 boe/d gas.

So opinions/questions to be answered:
- Is the bubble point going to be a problem, or will the aquifer/connectivity of the fractures support the BHP?
- Haven't been following Lincoln, but why will the OGA not allow tie back of Lincoln Crestal to AM?

2. Estimations by CPR
A lot of people on here have been asking "how can all these experts be wrong?".
The answer is, they are not. RPS have done these CPR reports many times over for multiple big clients. So the CPR (2017) at the time was not wrong based on findings by Hurricane. This was the previous model or "project" used to classify Lancaster reserves and resources prior to development of the EPS.
The competent people conducting the CPR have used the SPE PRMS (which IS applicable to unconventional reservoirs) to evaluate the reserves and resources. Hurricane are using the same SPE PRMS currently to evaluate the reserves and resources and I can bet you that the competent people are more competent at evaluating and estimating these reserves and resources than the technical committee.
The CP will confirm Hurricane's findings in the next report (scheduled early 2021), i.e. Rubber stamping Hurricane's technical committee's findings if all correct. This new report will include the "new model" or project for the EPS.

This new report will estimate the reserves and resources based on the following that is PROVIDED by Hurricane to the CP:
- Shallower OWC (applicable for resources, and to reserves if applicable)
- Enhanced production options (applicable for reserves only)
- Any other model changes/findings (i.e. volume of the production field)

So, opinions/questions to be answered:
- Should Hurricane use RPS Energy? - Benefits allow for comparison between old model and new model. If using another consulting company, allows for comparison between the two consulting services.
- Will OWC affect Lancaster EPS Reserves?
- The downgrade of resources is SOLELY based on the "OWC". So for "conservatism", how much of a downgrade will this be?

Also, I don't think OWC should even be as a reference point for FB reservoir (as this is variable - see above regarding PRMS unconventional reservoirs). But for resources/reserves estimation, IT CAN be used.

I have now FULLY read the Lancaster CPR.

Some points for discussion.

1. SPE Petroleum Resource Management System (PRMS)
The CPR completed by RPS for the reserves and resources is based on the SPE Petroleum Resource Management System (PRMS). This probably means nothing to most, but here's a presentation which goes through each aspect of the SPE (society of petroleum engineers) system:
https://www.spe.org/industry/docs/PRMS-Process-2007.pdf
I think slide 17 is particularly of note here, which goes through "unconventional resources".
It indicates that in unconventional resources --> there are likely to be much higher "In-Place Volumes". This is mainly because these unconventional reservoirs exist in larger areas and most likely are not affected by hydrodynamic influences such as buoyancy of oil on water. (i.e. Fractured basement - Lancaster)

For those that want to get into it, there's a 139 page document which goes through it all - namely the "Society of Petroleum Engineers' Guidelines for the Evaluation of Petroleum Reserves and Resources", the same guidelines that Hurricane are currently using for their technical review:
https://www.spe.org/industry/docs/Guidelines-Evaluation-Reserves-Resources-2001.pdf
Page 29 here is particularly interesting regarding "Gas Re-Injection". The document refers to re-injection of gas as an "enhanced oil recovery process". Note RNS dated 6th August where Hurricane refers to "production enhancement options for Lancaster currently under evaluation".
Also note that page 29 refers to field reserves in terms of gas - i.e. If this gas is reinjected and never produced/sold following reinjection, then it should not be included in the reserves. Or in other words, you could have a downgrade in reserves because of this gas not being produced. The Guideline says "In the case of miscible injection or other enhanced recovery processes, due allowance needs to be made for any gas not available for eventual recovery as a result of losses associated with the efficiencies inherent in the corresponding process."

One more interesting point that i'm sure most are aware of, "reserves" are commercially recoverable quantities, and therefore also depend on oil price in some way for development. i.e. If oil price is deemed so low that oil cannot be commercially recovered, it can not stay as "reserves" but will need to be downgraded to "resources". This also depends on the forward curve, but this does not apply to Hurricane I don't think. So just information for those oil investors.

So, opinions/questions to be answered:
- Is this what caused the downgrade in reserves? or will this contribute to an additional downgrade in reserves (if Hurricane are still evaluating this as an enhancement option)?

shaml89,
"Go through their update on 12 March , but here it is "2020 free cash flow forecast of $50-$75 million at $50/bbl; free cash flow breakeven of c.$45/bbl""
This is prior to additional cost saving measures. Brent price of $45/barrel breakeven was only for Q1.
Following the "Business Update" in April, the Brent price breakeven was lowered to $35/barrel after cost cutting measures saving a total of c. $85m.
- $50m CAPEX reduction
- $35m decommissioning cost reduction

The current breakeven for H2 is a Brent price of $38/barrel.

Slift.

Q1 "true breakeven" price per barrel: $52.2/barrel, i.e. total costs for Q1 @75k barrels = $356.3m
Q2 "true breakeven" price per barrel: $48.2/barrel, i.e. total costs for Q2 @75k barrels = $329.0m
Q3 "true breakeven" price per barrel: $49.4/barrel, i.e. total costs for Q3 @75k barrels = $337.2m
Q4 "true breakeven" price per barrel: $49.4/barrel, i.e. total costs for Q4 @75k barrels =$337.2m

The forecasted total (planned) cost to Tullow for 2020 is c. $1359.7m

First half realised oil price and production: $52/barrel, 95%@77.7k average. i.e Revenue for H1 = $698.6m
(95% because working interest production, i.e. non-cash royalties etc.)

For Second Half --> Assuming $45/barrel (and hence realised oil price at $52.2/barrel) and 95%@75k bopd production:
Forecasted Revenue for H2 = $676.9m

That gives FCF for YE20: circa. +$15.8m
THAT'S NOT INCLUDING ANY UPSIDE in either oil price or production (note: Q2 production was 79.6k bopd).
Or in otherwords, gives Tullow plenty more room to make mistakes from now and end of year.

I'm not worried. There are concerns (Uganda sale, Ntomme-9 well, etc.). But these are just concerns that will be confirmed at the september update. So unless someone has any more information, the recent decline in share price is just speculation.
Even if Uganda doesn't complete before RBL, Tullow will pass RBL at the end of September.

So rather than saying "$3b debt" (it's actually $3255m) or that TLW will face the same fate as PMO, provide some analysis for your claims.

Slift.

"Eco Atlantic"
Lol, how's Osprey?

If you had £400k, what would you buy?
- 6.9m hurricane shares
- A decent 4 bedroom detached house in the suburbs
- A Mclaren P15/Lambo Aventador or similar that's worth £400k
- 40,000 eat out to help out meals @ £20 each
- 160,000 pints at wetherspoons
- 4 years travelling the world living a lavish lifestyle at approx £2,000/week
- 8 x £50k Rolex watches
- Other (state)

I know what you'd buy Tommy393 lol :')

"I think then sky is the limit here for the much unloved and IMHO undervalued HUR SP."
Yeah.. no.

I don't think we will see 40p again soon, or at least not until HUR fixes problems and oil price rises to $80+/barrel.
So every longterm holder should take this great opportunity to average down if possible.

ALL IMO.
Slift.

Tony,

Surprised you favour farmdown of Guyana and keeping Suriname..

Personally, I favour keeping Guyana and farming down Suriname. Here's my opinion:
Orinduik is derisked with Jethro/Joe oil finds. The JV partners are targetting cretaceous drills which will be c. $30m in total per well. At 60% stake, this would be around $18m/well. Not too bad considering that Orinduik has been derisked and there over 5b+ prospective resources in this block. Not only that there are a couple prospects within this block with excess of 700 mmboe (both in Cretaceous).

Block 47 in Suriname is a block that is being watched by majors. An oil find here will derisk the surrounding licenses. I think this block is also very prospective in comparison to Tullow's other Suriname blocks.
The Goliathsberg Voltsberg North wildcat drill is promising. Hitting oil here would be a huge turn around for Tullow.

Tullow is targetting two geological targets here (similar to Kwaskwasi-1 in Apache's block) with a c. 35% chance of success. The problem is it's going to be c. $55m for this drill.
At 50% stake, that will be a c. $27-30m cost to Tullow to drill this well.

Obviously best to keep both at current stakes.. But with Tullow's financial situation and with depressed oil prices, it won't be pretty for this drill to come up dry.

Slift.

Contribution and your opinions!

Do you think Tullow should farm down their Suriname Block 47 and Guyana Orinduik blocks?
And should Tullow hold onto a slice of Kenya?

"It tells you everything you need to know about a company when one has to rely upon eye witness accounts of flaring of on a BB to indicate that production has resumed rather than a formal statement from the company itself."

Actually, the company did make a formal statement. You can't blame the company for your inability to read.

I'm happy that they haven't released any further RNS' and I hope that they don't release any more RNS' until the technical review or the interims.

Slift.

WHERE'S CANARYWHARFY? :')

Tim,
"Might be wrong here but thought it was not being revised as a first call of action?"
The refinance/revision of terms under the RBL is not required AT THIS STAGE if Uganda sale goes through. Also, this refinance and revision when debt is at $3255m is quite difficult and the creditors may not approve. This was why the corporate credit rating was downgraded in March.

Tullow will need to refinance/revise/extend the terms in late 2021 or early 2022 following the $1b portfolio management (which will likely all be used to pay off debt).

"But be assured that the reserves are still there."
*Resources :)

cluelesstim,

Yes, exactly as you say. Reserves are identified (or evaluated) depending on life of well and production. The reason for reclassification of reserves into resources is due to faster than expected decline of productivity of the wells.
The actual reason could be a lot of things. I.e. decrease in well pressure, increase in watercut, etc. I don't think Tullow has stated why the wells were declining faster than expected? But someone can correct me there.

But depending on the reason, there are multiple ways to increase the productivity and hence convert the resources back into reserves. This could be to drill new wells that have high productivity index, water injection into currently producing reservoirs (to increase well pressure), installing ESPs to wells etc.

As for the mechanical issues regarding 2019 wells, yet again Tullow did not specify. But be assured that the reserves are still there.

Regarding RBL arrangement:
Yes, RBL does bi-annual redetermination. At each redetermination, the RBL facility evaluates Tullow on a liquidity forecast test (September) as well as a net debt to EBITDAX gearing ratio (March).
Also, as of this year, Tullow is required to reduce the liquidity headroom available (and/or repay debt if no headroom) on a 6 monthly basis.
Liquidity headroom = undrawn debt facilities still available for Tullow to withdraw.

In March, Tullow has already reduced liquidity headroom by $211m (This is the September 2020 liquidity reduction but Tullow reduced early to show confidence).
In June, Tullow has already reduced liquidity headroom by a further $211m (This is the March 2021 liquidity reduction but Tullow reduced early to show confidence).

The problem is, Tullow has c. $472m liquidity headroom remaining as at 30th June. So sooner or later, they are going to have to start paying $211m debt as opposed to liquidty reduction.
This is why Tullow needs to "refinancing or restructure" the RBL. Best option would be to extend the maturity of the facility from 2024 to 202X and reducing the 6 monthly debt reduction from $211m to something that Tullow can achieve.

It get's complicated when you consider that Tullow has to repay this debt, aswell as pass the liquidity and gearing tests.

I have a hunch that the $1b portfolio management was initiated by the RBL facility. On completion, I'm sure that the RBL facility will be on Tullow's side.

ALL IMO.
Slift.

Yes, but I think individuals (harryyoung) are going to be dumping this stock when they hear of this "loss" being mentioned again in the H1 results.
haha :')

One thing i'm not certain of is how the market will react to:
- Losses due to impairments
- Negative cashflow in H1 due to extensive CAPEX
- Any other surprises Tullow wants to throw in