The next focusIR Investor Webinar takes places on 14th May with guest speakers from Blue Whale Growth Fund, Taseko Mines, Kavango Resources and CQS Natural Resources fund. Please register here.
Romaron,
I am more cynical about the Palantir story than this article implied. Simultaneously with the Palntir effort, were other efforts, one with GE, based on Predix, and work with another AI company, more physics focussed than the statistical AI approach of Palantir. All these efforts also stimulated some grass roots initiatives, especially when the top down imposition of Palantir ruffled a few feathers. The 20,000 bbl gain is probably real, but many would claim it is split betweena number of initiatives. See https://www.osisoft.com/presentations/the-digital-transformation-journey-in-bp-upstream/ for example, to show this is composed of many parts. The real key is to empower an organisation to do things differently. Note this presentation claims a 20,000 bbls a day improvement on the Glen Lyon, nothing to do with Palantir, just better use of existing standard tools, in this case the OSI PI Historian. So if the gain from data analytics in the North SEa is 20K bopd, this presentation implies it was nothing to with Palantir, and just better use of tools that they have had long before Palantir came along. Moral of the story - technology write ups in the press do not tell the whole story.
This is a structural issue on a jacket, possibly a node failure. However to abandon the wells, they would have to fix the jacket anyway. It would be almost impossible to abandon the wells without repairing the jacket. So, as you have to repair the jacket, why then would you not restart production as planned ? This will take some time to first design, then fabricate and install a fix, but there is no choice but to fix it. Maybe 90 to 180 days, depending on the problem.
I thought the below table was interesting from Apache's results, and one indication of reasons to slow some shale activity in the Permian. In Q2, Apache could hardly give away gas production in the Permian, as it was fetching 26 cents an MCF, vs 4$ / MCF in the North Sea, though that fell 2$ in the quarter. One can see the attraction of LNG, and if the European gas price continues to fall, you can understand why XR do not want to see their arguments eroded if coal is displaced by gas solely on cost. Pity Drax has not been encouraged to also switch biomass burning to gas to save the forests, but changing to gas from coal makes sense.
For oil though the improvement in logistics costs, rduced the discount to GoM crude by 3$ a bbl.
AVERAGE REALISED OIL PRICE PER BARREL
Q2 2019 Q1 2019
Permian 56.79 50.30
MidContinent/Gulf Coast 59.90 53.45
Gulf of Mexico 63.60 58.27
North Sea 68.43 64.15
AVERAGE NATURAL GAS PRICE PER MCF
Permian .26 1.61
MidContinent/Gulf Coast 1.98 2.94
Gulf of Mexico 2.62 3.69
North Sea 3.99 6.24
Colebrooke,
But if you go back further in time, you will see he was also buying (like me) when the share price was over 100.
Cannot blame him for averaging down a bit !
2012-06-14 A. Bseisu BUY 90,000 @ 117.88p 106,092 8.82
2012-06-11 A. Bseisu BUY 564,893 @ 116.50p 658,100 8.81
2011-12-30 A. Bseisu BUY 363,285 @ 90.00p 326,957 8.74
2011-12-23 A. Bseisu BUY 1,472,092 @ 88.53p 1,303,243 8.69
2011-12-16 A. Bseisu BUY 678,168 @ 88.74p 601,806 8.51
A replacement pump (replacing a failed pump) such as at Alma Galia, is maintenance and is OPEX. It is replacing an asset that will be scrapped, so the balance sheet impact will depend whether the failed pump was fully depreciated or not. The restoration work will have no real impact on the reservoir NPV, just on the residual value of the well and its component parts such as the downhole pump, as I understand it. Hope that helps ?
The OPEX vs CAPEX issue for a workover can be complex, and relates to future value versus retoring the original value of a well. For example, a workover intended to access a new reservoir zone , seperate from that producing originally, if successful, would be CAPEX, but if it was only successful in restoring production from the original zone, it would have to be classified as OPEX. Thus there will be well workovers that are CAPEX, and other well workovers that will be OPEX, such as simply replacing an ESP pump, without changing the reservoir being accessed.
The classification can change depending on the outcome of the activity. So a MAGNUS workover can be either CAPEX or OPEX, depending whether it restores the value of the original well, or adds new future value, not realisded by the original well. The accounting principles are the same for BP or Enquest.
Romaron,
Unfortunately I have a lot of Sirius shares ... Certainly hoping my Enquest position in time can mitigate some of the loss. Happy Enquest should no longer have to worry about securing more debt, and the only risk is a complete collapse in the oil price, which would require economic changes that would threaten a number of other aspects of our lives.
Expanding Kraken without significant redesign of the FPSO is a challenge. Engineering design work appears to be starting at Enquest on how to add capacity to the FPSO for Worcester and Western Flank production without needing to add additional capacity for more hot water to power Hydraulic Submersible Pumps from the FPSO. Enquest looking at possibility of downhole electrical heating and ESP's, as having the least impact on the FPSO. Might be combined with vacuum insulated tubing to mitigate heat loss downhole. Fairly mature technology for Canadian heavy oil, but limited use offshore so far, and in different applications (to avoid wax formation, rather than produce heavy crude). ESP's will have a shorter run life, incurring OPEX for changeouts, than HSP's, but an easier and less CAPEX intensive option than expanding further the hot water treatment and pumping capacity while simultaneously producing offshore.
I think the issue is just lack of trading activity. There is just no volume here to move the market. Total volume today is less than my paltry holding. We just do not have the media exposure that Cairn , Tullow or PMO seem to attract. The only thing I can see that will move the market is when high cost debt is reduced to the point there is enough free cash flow to either buy back shares or pay a dividend. I just hope that day comes before someone buys the company at a bargain price.
Beerbull, plenty of Resrves and Resources but only 10 years classed as 2P and 2C. This distinction is very important and much misunderstood, like the poster on Hurricane the other day, comparing possible resources to 2P Reserves. For example , on Hurricane perhaps there is a lot of oil there, but the 2P Reserves are only 37 Million. bbls.
What the 10 years means , is that if Enquest drilled no more wells than in the current production plans, and did nothing to improve recovery factors, through facility changes and drilling, basically if they spent no CAPEX, they would run out of oil in 10 years. However as they say, the best place to find oil is in an oil field, and spending CAPEX on facilities and wells, moves oil that Enquest already own, from contengent resources into proven and producable oil.
Many thanks Londoner7. I was mulling this over and also coming to the conclusion they were likely to be using diesel for power generation in the absence of imported gas. I wonder what they are using to heat the roughly 100,000 bbl a day of sea water to 65 C they need for water injection and make up for lost HSP water. Why would they flare gas rather then use this in the heaters ? I will see if I can find anything out.
This is not really an Apples to Apples comparison. Hurricane are paying for a long term production test on Lancaster to validate if their reservoir modelling assumptions are correct. The in place recoverable volumes are at the moment unknown, hence the need for the early produciton test. Clair nearby has massive in place volumes, but only a very small percentage is recoverable, and that is a more conventional reservoir than Hurricane. The current OPEX per barrel is high, with the short term FPSO lease carrying about 16 K of production, vs say Kraken, with a lower long term FPSO rate covering 50 K of production. I agree timing means Hurricane got a good deal on drilling, but they have only two production wells, versus what they will need for a true development.
I am a supporter of what Hurricane have acheived on a shoestring, in an unconventional reservoir, but th ejury is still out on whether this will translate into a long term full field development, hence the need for a long term production test.
Hurricane has yet to demonstrate any economies of scale, and the current test is just a test, not sustainable production at scale.
L7,
My understanding was in September 2014, Xcite Energy, Enquest and Equinor agreed to start looking at a shared gas import system. I cannot see anything on contracts awarded yet, so I guess this is still planned, but not yet in place.
Fuel is needed both for the 62 MW of power, but also to heat the injected water and HSP water to 65 C, and at least 85,000 bbl/day of that starts as raw seawater temperature, the produced water will be a little warmer. I suspect they are using all their gas, plussome crude to meet this energy demand.
Romaron, I completely agree. If it was easy to get the engineering right, more people would be trying to do it, and we should be grateful to the Kraken project team.
On a different note, as an engineer and not a financial guy, when we get to the point we can choose where some of the FCF goes, what will drive the share price most between continuing to pay down debt, decalring a dividend, or buying back shares ? Can Enquest buy back shares without another general meeting ?
I would presume at the current market cap, of the choices of how to spend 100 Million GBP, there will be a point that buying back 100 Million of shares would have a far greater impact on share price than either continuing to pay down debt, or declare a small dividend ?
What would move the share price most ?
Romaron, I agree these problems will be solved. The problem with an FPSO like Kraken, is that everything is bespoke, and design conflicts between the designers, the constructors, the owners (Bumi) and the customer (Enquest), coupled with the fact the initial designers are dealing with an unknown in terms of the exact production profile and water cut, make the chance of minor problems happening very high. The cost of not fixing them is high, so everyone is fairly well aligned, but the solutions then require bespoke engineering design and manufacture within the window of what can be physically installed, and minimising any production outages during the change. That is why there are planned shutdowns every couple of years on every facility of this kind, when the pipes can then be purged of flammable hydrocarbons, and parts safely changed out. I am sure a lot of changes are scheduled for the planned shutdown, but not much can be changed without 12 months of planning and manufacture, and the sheer logistics of changing out heavy parts in limited spaces.
To add to this, not only is the electrical power demand at 62 MW, but the FPSO design (Not yet running at design capacity though) is for 225,000 bbls/day of power water, and 275,000 bbls/day of injection water. Hard to find exact temperature data, but the goal is to maintain reservoir temperature at 42 C, so I presume the surface water temperature aspiration is about 45 C. That is a lot of water to heat, depending on what the combined return power water and produced water temperatures arriving at the FPSO are.
Romaron, You are right. I suspect all available gas, and some crude, is used for fuel, for power and heating the HSP water and I did not appreciate, they also heat the injection water. Makes sense. See the Genesis report for Nautical. They are probabaly also additionally heating the crude further at surface to ease water / oil seperation. I suspect they are not routinely flaring any gas.
Solution
The technical work of facilities development, definition, costing and option selection was undertaken following Genesis practice and with cooperation from suppliers of specialist equipment. The selected concept was three drill centres tied back to an FPSO. Downhole hydraulic submersible pumps (HSPs) were selected as the artificial lift mechanism, powered by hot water, with hot water injection for reservoir pressure support. The open loop hot water hydraulic system created a water-phase continuous production stream at an elevated temperature to overcome many of the problems of high viscosity oil production. The penalty was a high water loading on the FPSO, resulting in very large separators and water treatment systems, but alleviated oil/water separation and gas disengagement issues. Also, cold restart problems were minor as provision was made to circulate the hot water before opening the wells. Heat and power demands were high and majorly influenced the topsides and subsea facilities.
The subsea and riser design requirements were also onerous with an extensive network of lines, all insulated to retain heat, operating at high temperature. Material selection and stress issues were overcome and the use of riser base manifolds kept the number of risers to a manageable level for the turret selected.