ESV
#I would reiterate the fact that I think the Middle East and Asia on top of that is probably the one that we expect to see the first responses.
I think it's early to call on the North Sea.
The North Sea is going to be very dependent on what next year's oil price looks like.
And where people go into the budgeting cycles.
It's still in decline at the moment in the sense that contracts coming off tender don't have immediate follow-on, although as you've seen, we are getting well-by-well extensions and things like this on a lot of the rigs.
There is a sentiment change happening in the North Sea as Brent has gone back up to 50 than where we were looking at it six months ago, but I don't think we would call and say that it's reflected in the wholesale change in activity.
We certainly see a series of key opportunities going into next year, for example, as our 120s begin to come to the end of their current contracts, we are going to keep them warm and ready to go because we see quite a few opportunities to put them back to work going into next year.
So the North Sea is not dead I any means.
I'm not sure I would say it's going to have a wholesale pickup next year or not yet.
Gulf of Mexico has actually come up a little bit in activity, but it's come off a little a very low basis, one of the first markets where we've seen a step-up and so we are seeing some early signs of jackup activity picking up in several basins at the moment, but I want to be very clear that as of yet, that's not enough to offset the global fleet coming off contract within the next quarter or two.
So I think first of all, on the two rigs that we've got in the Gulf of Mexico, I think, as I said, they're going to ---+ we see them over the next say three, four quarters working largely on short-term contracts but picking up work as it comes about on a well-by-well, or small programs.
Asia-Pacific is another area where we see a need for that type of rig so we're definitely going to be keeping the 8504 available for pickup work there, and that's a market that we will watch carefully as it develops as to whether we would relocate another rig there of that class.
Also an area that we are watching very carefully where we believe there is a need is in West Africa.
So we have, we've stacked out four of the rigs in preservation stacking now.
We're going to keep three marketed to pick up this work.
If we saw enough activity in this in-field work beginning to come, we would be prepared to proactively bring out one of the rigs from stack to address that market, and most likely relocate it out of the Gulf of Mexico.
But we do, one of the reasons we took delivery of those rigs is because we think as the jackup market begins to recover, especially around the Middle East, Asia, that these are going to be very competitive rigs and we are bidding them into projects now, some for 2017, so whilst they will go straight to stack when we take delivery of them, we are hopeful that these will be back to work within a sensible timeframe.
One other piece I just on the accounting treatment for the 140 and 141, just so you have in your models, so while we've taken delivery of the 140 and will shortly for the 141, we stopped capitalizing those rigs but we have not yet started depreciating those rigs, so you won't see the depreciation expense hit until we get a contract on those rigs and they go through their acceptance testing, so the only piece you'll see through the P&L is the small bit of OpEx that <UNK> described.
I will take, I'll just give you the first bit and then I will pass over to <UNK> for some specifics.
So at the high level as you saw what we have done is we have taken a series of actions that are going to result in annualized $50 million in savings versus where we were at the end of Q2 this year.
Now it's probably important to point out that these are not aspirational targets, this has all been enacted so we've centralized some key functions, we're moving toward a different support model for a lot of our business and what I'll point out is that this is also designed so that we have a more efficient support structure as we go through the cycle and afterwards, so these are efficiency changes to the way we run the company that we expect to gain advantage for as we come out of the cycle as well.
But, they're all enacted and the decisions around the discretionary compensation are all agreed and in place so there's nothing here that is aspirational that is yet to be done, it's all done and ready to start rolling through.
The other element I'll just say is that what we did call out in the pre-prepared statements is the fact that will have a slightly unusual Q4 contract drilling expense, CD&E, as a consequence of these one-off items that we have around preservation stacking to the floaters and then the preparation for at least four rigs getting ready for new contracts.
If you strip that out, our quarterly CD&E would be coming down and we still expect that trend to continue into January next year, so we would expect another drop-down in January and we will give you more details about what we report Q4.
And then to focus on, if you want to understand the split between G&A and CD&E, the vast majority of the savings are going to be flowing through CD&E, so if you think about who the $50 million is impacting, it's our shore-based personnel, both the corporate and the rigs support personnel, and the rig support and some of the other back-office functions will be flowing through CD&E so that is where you will see the majority of the reductions.
Yes, this is <UNK>, just to be perfectly clear, so our reported contract drilling expense guidance, on a reported basis, would be 301 to 306.
The $16 million that <UNK> was just mentioning which are partly related to startup costs, which is good news because those are contracts getting new work, is $16 million, so as <UNK> described in his prepared remarks, the adjusted contract drilling expense guidance for 4Q 2016, is $285 million to $290 million and that incorporates the $15 million of incremental cost-saving efforts that we talked about on an annualized basis in terms of actions that have already been taken.
Just give us a second, we are just gathering ---+
You are talking about on Q3.
So the majority of that was just some startup costs that hit us in Q3.
Good morning.
Okay, we're not going to get into exact bidding strategy, but if I can elevate that again a little bit, just to reiterate what we said in the pre-prepared statements.
We have decided to preservation stack a series of our rigs, based simply around our assessment of what the market demand is going to be over the next kind of 12 months or so, and therefore, reduce our market fleet.
However, we are not going to keep stacking out every rig.
What we have decided to do is run this portfolio approach where we are basically keeping a certain number of rigs by class, drill ships, semis, and jackups available in core regions, by region, by rig type.
And those rigs we will have available to market.
So a good example of this is we are going to keep the 8504 in Asia available for work.
The DS7 drill ship is going, when it finally comes off of contract, will be available and kept warm, ready to work.
And the 120 series, some of the 120 series that we have in the North Sea, for example.
And for those rigs, we are going to be bidding them to keep them active, to keep the crews active and to form a bridge through to the future.
And we will judge each project a little bit on its own merits.
And there are some single well projects that require maybe very expensive mobilizations we will choose just not to bid on because the cash flow burn on those projects just don't make it worthwhile.
It's better to keep the rig warm stacked and wait for the next project.
In places like the Gulf of Mexico, on some of the 8500's, actually we are able to string together streams of single well projects with different operators that actually can be economic for us to run the rigs, through, by putting them together because they are major mobilizations from well to well and things like this.
So it really is dependent on case-by-case, but for the rigs that we have decided that are going to be our swing capacity and are warm stacked, we are going to be bidding aggressively to keep them active.
The other one is you have to look at the counterparty risk for these single wells with customers that have difficult cash flow.
I mean, it's one thing to enter into an interesting or new contract model, it's another one to just basically take risk and gamble and we are definitely avoiding the latter.
That's correct.
So after the termination notice, we have 90 days at full rate and then it drops down to 75% of the rate.
And that's what's reflected in the guidance.
No, no, there's not a lump sum payment like we recognize in some of these other terminations.
We will receive a 75% through the duration of the original contract term after the 90 days which will get the full term.
Well, until we negotiated an upfront payment for the remainder of that cash flow stream, that's right.
And that's the only thing that could change here, is if at some stage, there was a single payment settlement, but that's not in the contract and therefore that becomes mutually negotiated agreement.
Hi, <UNK>.
Yes.
Good morning, <UNK>.
That's all part of the ongoing negotiations we have, so I'd really prefer not to go into it, only to add that if it can't stay in the current shipyard, which is one option, we have other places we can take it to, and we've gained a lot of experience now on exactly how to stack these drill ships either in warm stack or in preservation stack, and exactly what's required to be able to have them ready to go in certain timeframes and in very good condition whilst they've being stacked.
We feel very comfortable about taking the rig ourselves and warm stacking it.
And actually to be perfectly honest, one of the things that comes into the discussion here is given our liquidity position, we don't want to do anything that doesn't make financial sense, and in some cases, we can actually do this cheaper than a shipyard can do it.
It very much depends on what type of M&A you are looking at.
If you remember in the past I referred to the fact that you can simply put it into three types of buckets, there is distressed assets, then there is the smaller fleet companies of maybe four to ten rigs, some of which are getting into distress situations, and then there's the more peer group sized international companies which looks, that type of deal is more like an equity merger.
So it's not so much the bid spread ask as the individual circumstances of each of those categories.
At this stage in the cycle, on the individual assets, we have decided not to play and we are not chasing after one-off rigs at this point because to just go and acquire a rig without a contract, put it to the back of the queue behind our existing rigs, doesn't look like a viable, sensible use of our liquidity at this stage and also, it doesn't move the needle for us.
Now as we go forward through the cycle, I think we may look at these things differently depending on how the cycle unfolds, but today we're not looking at that type of, not aggressively looking at that type of opportunity.
With the medium-size or the smaller size companies, the core issue there is not so much the bid spread ask, it's the balance sheet position.
A lot of them have got very poor or very weak backlog and very, very heavily levered on the balance sheet and you just wouldn't want to take them at their current balance sheet positions, so I think we would have to see some restructuring of some of these companies which I think is likely to happen before maybe they become a bit more attractive.
It's much more individual case specific rather than just the immediate.
Equity price for a lot of these companies is not the relevant decision-making criteria.
Okay since there are no more questions I just want to thank everyone for participating on our call today.
Have a great day.
