Diamond Offshore Drilling Inc (DO) 2015 Q4 法說會逐字稿

Good morning. My name is Jackie and I will be your conference operator today. At this time, I would like to welcome everyone to the Diamond Offshore Drilling fourth-quarter 2015 earnings conference call. (Operator Instructions). I would now like to turn the conference over to Darren Daugherty, Director of Investor Relations.

Thank you, Jackie. Good morning, everyone and thank you for joining us. With me on the call today are Marc Edwards, President and Chief Executive Officer; Gary Krenek, Senior Vice President and Chief Financial Officer; and Ron Woll, Senior Vice President and Chief Commercial Officer. Following our prepared remarks this morning, we'll have a question-and-answer session.

Before we begin our remarks, I remind you that information reported on this call speaks only as of today and therefore, you are advised that time-sensitive information may no longer be accurate at the time of any replay of this call. In addition, certain statements made during this call may be forward-looking in nature. Those statements are based on our current expectations and include known and unknown risks and uncertainties, many of which we are unable to predict or control that may cause our actual results or performance to differ materially from any future results or performance expressed or implied by these statements.

These risks and uncertainties include the risk factors disclosed in our filings with the SEC, including in our 10-K and 10-Q filings. Further, we expressly disclaim any obligation to update or revise any forward-looking statements. Please refer to the disclosure regarding forward-looking statements incorporated in our press release issued earlier today and please note that the contents of our call today are covered by that disclosure. And now, I will turn the call over to Marc.

Thank you, Darren. Good morning, everyone and thank you for joining us this morning. I would like to start by highlighting some of our key achievements for the year just ended. Despite the market turmoil during 2015, we delivered record-breaking performance as it relates to both safety and uptime and our early efforts to position the Company for a protracted downturn proved fruitful in terms of reducing input costs, which fell through to the bottom line midyear. We are continuing to look at innovative ways to further reduce costs and drive efficiencies for the benefit of our clients and our shareholders. This philosophy is what led to our announcement this morning of the industry's first subsea pressure-controlled by the hour construct. I'll share more on that in a few moments.

But, first, let me continue with some commentary around our financial performance. For the fourth quarter, we continued to produce solid underlying results, reporting $0.89 per share after adjusting for impairment charges. And for the full-year 2015, we reported $3.05 per share, again adjusting for the impairment charges. Fourth-quarter results did benefit from a $33 million trueup payment for a customer who exercised an option not to extend the term on the Ocean BlackRhino contract.

Gary will provide more details on the financials, but overall our results reflect our successful efforts to reduce costs while continuously improving our safety and operational performance. Further, across the entire fleet, we delivered 97% operational efficiency -- that is the percentage of the time the equipment was available to work -- without unanticipated downtime and for 2015, we delivered the best safety performance in the Company's history, achieving a 34% improvement on our normalized safety stats over the prior year.

But despite this very solid performance, we are, unfortunately, yet to see any signs of improvement in the offshore rig market fundamentals. All asset classes are struggling, but, as I've said before, the higher-end dynamically positioned fifth and sixth-generation market has the biggest problem. But on a positive note, and as you are aware, all of our sixth-generation assets are contracted to 2019 or beyond. The market will recover as oil supply and demand fundamentals come into balance, but we believe that due to the long leadtimes in the deepwater space, any uptick in activity could be further over the horizon than current consensus. Therefore, despite sharing the best credit rating in our industry, we are taking action to bolster our already solid balance sheet.

And with that, this morning, we announced that our Board of Directors has eliminated the regular quarterly dividend, which was previously $0.125 per share. This will add an additional $69 million per year of liquidity for the Company. We have paid a regular dividend for a considerable period of time, so it was only after careful deliberation that such a decision was reached. By conserving additional cash, we will improve our flexibility to take advantage of strategic opportunities that may materialize.

So let me now return to our press release this morning announcing our agreement (technical difficulty) oil and gas. We are entering an industry first of its kind performance-based service and maintenance arrangement for the provision of pressure control. In other words, GE, as the original equipment manufacturer, will now be a key stakeholder in improving the availability and performance of the subsea stacks on Diamond Offshore's sixth-generation ultra-deepwater drillships. These are the Oceans BlackHawk, BlackHornet, BlackRhino and BlackLion.

We already know that the breakeven cost of deepwater drilling is coming down, but, as I have said before, all stakeholders in offshore drilling have to continue to look at the structure of the industry and address efficiency, capital efficiency for ourselves and our clients. We have to lower both costs and cycle times. One of the largest impediments to delivering the required economic returns for deepwater projects today relates to the poor uptime availability of the subsea systems. A single stack pool can add up to an expensive 20 days of nonproductive time to our clients' well construction process.

Presently, downtime on subsea equipment is by far the largest cause of nonproductive time. Each day of downtime can represent as much as $0.5 million of lost revenue for Diamond Offshore in addition to another $0.5 million of unwarranted spread expense for our client. The new service model, which we refer to as pressure control by the hour, transfers full responsibility for the maintenance service, the management and supply of spare parts, equipment upgrades, continuous certification and data monitoring back to the original equipment manufacturer. GE employees will be permanently stationed on our rigs, but Diamond will retain operation and control of the subsea stack itself. Not only will GE maintain the subsea stacks, but they will buy back Diamond Offshore systems, which include all 8 units, [2 aborting ship], as well as the diverters and control systems.

Under the arrangement, Diamond Offshore will pay a day rate similar to how we are paid by our own customers. If downtime occurs because of the subsea stack, GE will not be paid and will therefore feel the financial impact, similar to the way the driller and the operator are affected today. This is new to the industry. GE will be further incentivized to improve subsea equipment performance through a bonus malus system based on an already-determined performance metric. As an example, should uptime not meet a certain threshold, which is higher than where we are today, malus payments will be made.

These performance incentives will drive further improvement in deepwater drilling efficiencies by motivating all parties to prioritize availability. Under our 10-year agreement, GE, as the original equipment manufacturer, will be in a performance-based alliance that leverages the scale of their data, predictive analytics, including condition-based monitoring and maintenance, that will proactively improve the availability of our subsea stacks. In essence, they will be further incentivized to embrace the design for reliability ethos.

Now the task at hand for us is implementation. The agreement will phase in our 4 ultra-deepwater drillships over the course of 2016 beginning next month. So what will this mean to the bottom line for Diamond Offshore? For obvious competitive reasons, I will not share specific commercial terms; however, we will record the sale of the subsea stacks as we transition to the arrangement throughout the course of the upcoming year with a staggered implementation.

Going forward, we will not provide rig-level cost guidance for drill ships operating under the agreement, but Gary will continue to provide it for total drilling expense. However, we do believe that this arrangement will provide for incremental contract revenue in the long run. This is a tangible example of the Diamond difference, a new way of thinking that will drive continuous improvement in offshore drilling. Pressure control by the hour is a new service model for our industry that is long overdue. We hope that along with our service partner, GE Oil & Gas, we can help further improve the full lifecycle NPVs of deepwater drilling and in so doing further differentiate Diamond's sixth-generation assets from the rest of the pack. With that, I will now hand over the call to Gary to discuss the financials and then I will have some closing remarks. Gary.

Thanks, Marc. As always, I will give a little color on this past quarter's results and then cover what is to be expected for the upcoming quarter. In addition, as is our custom with our fourth-quarter earnings call, I will spend some time providing additional selected information on what we expect for the entire year of 2016 with regards to various line items on the income statement, expected capital expenditures, downtime, etc.

For the quarter just ended, we reported an after-tax net loss of $245 million, or $1.79 per share, based on contract drilling revenues of $556 million. This net loss compared to net income of $136 million or $0.99 per share reported in the previous quarter was, of course, primarily driven by the non-cash impairment write-down recorded in Q4. The impairment charge to our rig fleet totaled $499 million, which resulted in an after-tax charge of $2.68 to EPS. I'll add a little color on that in a moment.

Contract drilling revenues decreased from $599 million in Q3 to $544 million in Q4 primarily as a result of a number of rigs rolling off contract in mid to late Q3 or early Q4 and failing to find follow-on work in this depressed market. Partially offsetting this decrease was the additional revenue received by the drillship, Ocean BlackRhino, due to a customer exercising their contractual option in Q4 not to extend the rig's contract. This resulted in the contract day rate reverting back to the higher original rate from the reduced day rate that we reported in our last rig status report and thus enabling us to bill and record approximately $33 million of additional revenue in Q4 over and above what we would've recorded had the day rate stayed at its revised rate.

During the fourth quarter, the Company made the decision to actively market an attempt to sell its jackup fleet with the exception of the Ocean Scepter, which is under long-term contract in Mexico. The remaining five jackup rigs were included in our impairment charge this quarter and have been written to nominal amounts that we expect to receive as a result of their sales. We expect these sales to occur within the next 12 months and as a result have reclassified these rigs from fixed assets to assets held for sale on the balance sheet at December 31.

I will now address some of the additional line items on our fourth-quarter income statement. First, contract drilling expenses for the quarter came in at $256 million, which is $22 million less than the prior quarter and at the very low end of our Q4 guidance of $255 million to $275 million. However, the BlackRhino's extension cancellation not only impacted revenues for the quarter, but also contract drilling expenses. GAAP accounting requires us to defer and amortize mobe and contract prep costs over the expected length of a contract. When the contract was shortened, it required us to amortize the contract drilling expense of approximately $9 million more than what we had anticipated for Q4. Had this not occurred, we would have come in below our guidance for the quarter, again reflecting the efforts of the Company to be as cost-efficient as possible. As I've stated in prior earnings calls, after safety, cost controls and efficiencies remain one of our top goals.

Depreciation expense decreased slightly in Q4 and came in about $3.5 million below our guidance, mostly as a result of a normal trueup of depreciation at year-end to reflect exact timing of capital expenditures made during the year. G&A cost and interest expense for the fourth quarter of 2015 also came in at or slightly below the low end of our previous guidance ranges while our effective tax rate, excluding the impairment charge, was 11.9%, again slightly below the guidance range of 12% to 16%.

Now looking forward into 2016 and some of the items that will affect our financial performance next quarter and for the coming full year. First, a look at anticipated downtime for our rigs under contract. For the first time in recent memory, we have no special surveys for rigs in our fleet scheduled for 2016. We do have several rigs that will be mobing during the year and also have some acceptance testing and modification downtime scheduled. For the exact number of down days expected in 2016 and the timing of these projects, I refer you to our rig status report that we filed this morning.

Now turning to our guidance for the full year ahead, I will give estimates for the first quarter and full-year 2016 for individual line items on the income statement with the exception of contract drilling expense. Because of the uncertain industry outlook, it is difficult to predict longer-term rig utilization and therefore I'll only comment on operating expense for the first quarter of 2016.

We expect rig operating costs to decrease for the sixth consecutive quarter. In Q1, we expect to report contract drilling expense between $205 million and $225 million. While a part of the decrease in this guidance from the Q4 actual cost is activity-related. For example, the Ocean Clipper and the Ocean Alliance going from working in a portion of Q4 to currently either sold or cold-stacked. It also reflects our ongoing cost-savings initiatives. As always, I remind everyone that I've been talking about the line, contract drilling expenses, on our income statement, which does not include costs incurred in the line reimbursable expenses.

Depreciation expense for the full-year 2016 is estimated to be in the range of $420 million to $440 million, a decrease compared to 2015 DD&A. This decrease is primarily due to the sale of a number of rigs in 2015 along with the impairment charges we took in Q1 and Q4. We expect Q1 2016 depreciation cost to come in at between $100 million and $110 million and then increase slightly when we begin normal depreciation of the Ocean GreatWhite subsequent to the delivery of the rig from the shipyard.

G&A costs are expected to total $60 million to $80 million for the year with approximately $15 million $20 million incurred during each quarter of 2016. Interest expense on our current debt and expected borrowings on our bank line of credit net of capitalized interest is projected to total between $105 million to $115 million in 2016. Net interest in the first two quarters of 2016 should run close to $25 million per quarter and then increase slightly to closer to $27 million or $28 billion in the final two quarters when we're no longer capitalizing interest on the GreatWhite.

We're currently looking at an effective tax rate for the year to be in the range of 10% to 18%. As always, any changes of the geographic mix in the source of earnings, as well as tax assessments or settlements or movements in exchange rates will impact our effective tax rate. For the sake of clarity, I'd like to point out that while we're not going to share the commercial terms of our pressure control by the hour agreement with GE, the expected financial impact of the agreement has been included in the guidance that I've just given you. In addition, the sale of the subsea stacks back to GE will not generate any recordable gain or loss on our financial statements.

And finally, moving on to our capital expenditure guidance, reflecting decreased rig activity, we believe that we will incur maintenance capital cost of approximately $150 million for the full-year 2016, which is down from our 2015 maintenance CapEx spend of $215 million. Newbuild CapEx for 2016 is expected to be $525 million, which includes oversight costs and the final 70% shipyard payment for the Ocean GreatWhite. Adding those together, maintenance and newbuild capital expenditures are expected to total approximately $675 million in 2016. And with that, I will turn it back to Marc.

Thank you, Gary. For well over a year, I have expressed the view that we are facing a severe and prolonged down cycle and today, it seems clearer that the oversupply of drilling capacity may persist well into 2017 and possibly beyond. Eventually, however, the price of oil should stabilize at a much higher price than where we are today and deepwater production should again be a growing component of total global energy supply.

We are in a cyclical business and eventually our clients priorities will shift from reducing spending to growing deepwater production and reserve replacement. The industry may look different in the future, but supply and demand will eventually come back into balance. Today, with the suspension of the dividend, we have further bolstered our already-strong balance sheet and although the introduction of our pressure control by the hour service also improves our liquidity, this was not the reason why we introduced the concept to the industry. Instead, we're further differentiating our fleet in a manner that meets our clients' most pressing well construction needs.

So let me be clear, we intend for our Company to come out of this downturn well-positioned to succeed during the eventual recovery. We will continue to focus on conducting safe operations, delivering quality performance for our clients, rationalizing costs and utilizing our capital efficiency. And now with that, we'll take your questions.

(Operator Instructions). Ian Macpherson, Simmons.

Thank you. Good morning. Marc, do you think that this business model will roll out fairly rapidly, or do you think that we'll be looking at this as a test case for a year or more before it's adopted more broadly across your fleet or across the industry?

Ian, thanks for the question. Look, at the end of the day, this was our idea and we reached out to GE because they were already familiar with guaranteeing availability in other industrial segments. And importantly, we had their subsea stacks, of course, on our new drillships. If they were to have correct skin in the game from a financial perspective, we needed for them to have the total accountability that comes with owning the assets too. So we've collected $210 million from the proceeds of the sale, but I'm not sure the OEMs will be willing to repurchase subsea stacks carte blanche.

So as a result, we have significant advantages that come with first-mover advantage and this is actually a huge vote of confidence regarding Diamond Offshore as a leading offshore driller, one that come from a corporation of the scale and sophistication of GE. This is -- this was a difficult construct to put in the industry. There was no precedent. It's a combination of eight months of negotiation. We're there now and our clients are applauding. So we aim to bring uptime and availability performance improvements to the subsea stack similar to what was seen, for example, in other industries such as aviation and power generation with rotating equipment.

Let me not underestimate the difficulty of putting this in place. What I wanted to do was I wanted to have the original equipment manufacturer to have total skin in the game. So that involved selling the BOPs back to the OEM, back to GE in this case. For us, we did it on our new drill ships because clearly that was, as you rightly mentioned, perhaps the best test case. I see this rolling out across the industry. The reliability of subsea stacks needs to improve if we're to drive the efficiency gains to make this more economic. So to answer your question, yes, I think it will expand across the industry, but clearly we've got first-mover advantage in this particular case.

Very interesting. Thanks, Marc. Then just as a separate follow-up, I think we can make our own judgments about some of your rig rollovers this year. But one that I am curious on is the Endeavor as it's coming back from the Black Sea. What are your current plans for that rig as it's being brought back, I presume, to this side of the world?

We got high marks from Exxon on the work the Endeavor did in the Black Sea, but really based on markets and just geology of what they found, that work is not extended in the Black Sea with Exxon. So she's in Romania now where the derrick will be removed so we can take her back to the Bosphorus on a heavy lift. We definitely see her as part of our fleet going forward, but there's no immediate follow-on work that we are announcing today.

So likely cold-stacked in pretty short order, is that a reasonable assumption?

Yes, we've got several months worth of work I think before we take her down to a cold-stacking status, so we've got to -- there's some work still ahead before we get there, but we'll minimize her costs and then see where the market takes us.

Got it. Okay, thank you.

Gregory Lewis, Credit Suisse.

Thank you and good morning. Marc, clearly, what you are doing is turning the industry a little bit on its head here. I guess as I think about this and the profitability side of working the subsea control system and the stack, do we think this actually longer-term reduces overall returns for the industry? Is that a concern that we should be having?

Not at all. I see it actually quite different to that. The near-term impact of this arrangement is not material to earnings. This is a part of a long-term strategy that will address one of the Achilles heels of offshore drilling today. The subsea downtime is huge in the industry and if you think of each day that we are down from drilling in order to do a stack pool, that's a loss of $1 million per -- for our clients on a daily basis. A stack pool can be up to 20 days. So in terms of drilling a well, you lose a subsea stack for whatever reliability issue. Then that adds sometimes up to $20 million to the cost of the well.

The reliability just isn't there and buy incentivizing the original equipment manufacturer from a financial basis, and as I said in my prepared remarks, when -- the current status today, they do a direct sale and then they hand us a spare parts price list. They are not really incentivized like the driller or the operating company to minimize downtime. I'd like to think that they do have the design for reliability ethos, but by bringing them to the table so that they have financial skin in the game, then I can be certain that they are designing their equipment for maximum reliability and if you -- GE know this construct. They do it for aviation turbines. The GE90 engine, as we all fly across the Atlantic, we're riding with a GE90 engine on the 777. That's a power by the hour philosophy. And we're going to a similar philosophy here with the subsea stacks.

They do it for rotating equipment in compression plants and power stations. So it's already well-known and if you actually study those industries, you can see that when you go to this construct, there is an improvement in reliability and any improvement in reliability puts money on the bottom line for Diamond Offshore and helps out my shareholders. So really the construct here is to have more uptime over the fleet itself based on dragging the original equipment manufacturer to the table with skin in the game. This is what our clients want. This is not a technology push from a Diamond Offshore perspective. This is a demand pull from my clients.

Okay, perfect. And then just I guess shifting gears over real quick on the rig side. I guess I saw that contract extension on the Scepter in Mexico. Does this pave the way for potentially an expansion or incremental work on the Ambassador as it rolls off I guess later this quarter?

The Scepter, I think, was a good arrangement between us and Pemex, but I would probably not connect the dots to the Ambassador. I think it's quite likely here that she will be winding down in 2016, so I wouldn't model the Ambassador beyond where she is today.

Okay, guys. Thank you for the time and good luck on this push forward with BOP.

Mike Urban, Deutsche Bank.

Thanks. Good morning. Does the agreement with GE require any change in the contracts with your customers, or does that relationship remain the same?

The relationship effectively stays the same. Obviously, our customers were involved, as we were getting to the finish line on setting up the agreement with GE, but both customers were very, very positive and as I go around the industry and I visit the executives in charge of drilling not just for my own customers, but for other E&P operators out there, they are very positive on this construct. They say it is a win for everybody in deepwater drilling.

And then I understand completely you don't want to share specific commercial terms, but just in general terms, in terms of the mechanics or the accounting that goes into it, since you are selling -- effectively selling the BOP, would that be a reduction in the carrying value of the rig and therefore the depreciation and you offset that a little bit with presumably higher OpEx with the payment to GE going to the OpEx line?

You pretty much hit it on the head there, Mike. Yes, we'll have less depreciation. Of course, the agreement with GE will be treated as an operating lease, so costs will increase there, but they will be offset by cost savings by us for things that we no longer have to provide for for that BOP maintenance. So at the and, as Mark said in his opening remarks, we don't see it having a great bottom-line impact or very material, particularly when you factor in our expected increased utilization on the rigs.

So let me just reemphasize one point here. [Drill] no subsea downtime is the Achilles' heel of our industry. I've used that expression quite a bit. These four Black ships now effectively go to the front of the deli line in terms of desirability from our clients. This is -- yes, it's helped us from a liquidity perspective for sure, but more importantly our assets become extremely attractive as it relates to future contracting opportunities moving forward. We're the first to do this in our space. Is there a possibility of further rolling it out throughout the fleet? I would say that there is. I'm not saying at this time that we're going to do it, but this is all about competitive differentiation and I believe that our four Black ships now, frankly, in a market that is oversupplied have become very, very attractive assets from the client perspective.

If I could sneak one more in, since presumably this would lower the cost of a newbuild rig, it's just one less new piece of equipment you have to buy and then of, course, the reliability factor, does that change or increase the likelihood that you might go forward with the floating factory concept?

So, yes, thanks for that question. As we put thought leadership in the industry here, it's very important to be focused on the immediate future. We've positioned the Company early for an extended downturn, both from a backlog, liquidity and an operating cost perspective. And we are executing very well on the short-term strategy, but it's also important not to lose sight of the longer term either.

So as much as we listen to our clients' needs on pressure control by the hour, we're also listening to clients' needs as it relates to efficiency gains. For example, on the 80% of a time, a rig is actually over the wellhead and not drilling. The conundrum is how do we lower cost through efficiency gains and here, at Diamond, we continue to ask ourselves such questions and we have some neat answers that we share with our clients. They like what we're saying. But I bring you back to the capital allocation conundrum. My management team and I are laser-focused on maximizing shareholder value over the long term and in this respect, it's important that we have a series of strategic options that are available to us. We've pulled the trigger on pressure control by the hour, but -- and that's somewhat of a no-brainer. However, I cannot say it's the right time to declare on other strategies, for example.

The important thing is to have as many alternative options available, frankly, as possible and the floating factory is simply yet another option that I have on the table. But, first and foremost, I have to review everything in the context of long-term shareholder value and right now, at this moment in time, frankly, we're just keeping that on the table as an option for further down the road.

Okay, great. Thank you.

Waqar Syed, Goldman Sachs.

Thank you for taking my question. In terms of just going into further detail on that just broadly, you still won't get the day rate in case the BOP is not functioning, is that correct?

So, Waqar, that is correct. Just to be specific here, what happens today is if the subsea stack goes down for performance-related issues around reliability, etc., and we have to pull the stack, then, from the client's perspective, obviously, they are not progressing the well; yet they are still paying for the spread costs. From our perspective, in the most part, we go off day rate, because, again, we're not pursuing the well. The OEM, the manufacture of the stack, doesn't suffer at all.

So part of this construct moving forward is I am paying a daily rate for pressure control moving forward. When I have to pull the stack, I no longer pay that daily rate, so I'm off rate, the OEM is off rate and the operator is suffering the cost of the spread that he's paying for for the other services. So I'm still off rate, but I'm no longer paying for the BOP stack on a daily basis and if during the course of the year the OEM performance is below a metric that we're already at today then not only are they off day rate, but they pay me a malus payment for poor performance. So effectively what GE have agreed to do is guarantee performance backed up by financial consequences. So for the first time in the industry, the OEM is sitting at the table when we have problems as an equal stakeholder, as the driller, the operator and of course the OEM.

That makes sense. In terms of the liabilities in the case of any third-party consequence damage, does that change at all the BOP if pressure control equipment is owned by somebody else?

That's a good question. Part of the reason the negotiations took so long was to actually sort out and get agreement on reliability. In essence, there's no real change to the liabilities moving forward. At the end of the day, the manufacturer of product liability remains in place as do other liabilities, so there's no real change moving forward. But that was an extensive part of the negotiations that we undertook with GE.

Okay. And for this model to work, do you need only the sixth-generation rigs or could this work on some of the older rigs as well, or the OEM wants to have like (inaudible) will be a piece on the rigs to reduce their risk?

Yes, okay, so this is an industry first. It made sense that we looked at our brand-new rigs. Well, in essence, they are brand-new. One of them has been -- a couple of them have been drilling for well over a year now. It was easier to convince the OEMs to buy back the BOP stack, the subsea stack, on equipment that was relatively new. If it's equipment that was sold to a driller let's say five years ago, I think that conversation will be a much harder discussion because obviously the passage of time creates an understanding of just exactly how well was the stack maintained and then you've got further discussions around the true valuation of the BOP.

One of the things I insisted moving forward was this was not just a standard maintenance contract. I didn't want to do that. I needed these guys to truly sit at the table with skin in the game and I wanted them to own their performance, which included owning the stack. This is perhaps something that's easier to do on new drill ships as they come out, but what made it a little bit more complicated is I needed to sell the BOP stack back to the OEM and that's actually harder than you'd naturally think. I think it will be even harder on stacks that are older than the stacks we've got on our drill ships, take it from me.

Yes. And then with respect to the GreatWhite, have you heard from the customer? Are they on track to receive the drilling rig and have they budgeted for all what they plan to do with the rig?

Well, I can't speak for what their budgets are, but right now at this moment in time we're planning to deliver the GreatWhite as planned and to move forward. The GreatWhite was supposed to be delivered in December of last year, but we've known all along and have been in communication with our client that there will be let's say a six-month delay on it, but our contract is quite robust and the rig called for a delivery before the end of this year and we're still on target. We've got a lot of wiggle room on that to deliver it accordingly.

Okay, great. Thank you very much.

Sean Meakim, JPMorgan.

Good morning. So just following up a bit more on GE, did you have discussions with any other OEMs about this type of work? It sounds like perhaps you approached GE. Just curious what that discussion could have looked like outside of GE.

Yes, that is an interesting question. A lot of things actually came together quite well for us to kick this off. First of all, GE understands this kind of concept. I spoke about how they approach the aviation industry and the industrial products they sell in there. I spoke about what they do with rotating equipment and compression power and power plants. So they already get it. We looked at when GE introduced let's say power by the hour to the aviation industry. We looked at how the uptime improved once they were on that construct. Then we -- our newest assets in the fleet also had GE stacks on them. So it came together quite well and, yes, we did approach GE.

We wanted to -- if you stand back and you look at the issues in our industry and you look at it from an economic perspective, this isn't just about day rates. This is driving efficiency gains. This is what I did in my prior life when we were developing unconventionals here in North America. It's about efficiency gains. And you've got to bring efficiency gains to deepwater drilling to make the -- to make it economically viable at this kind of oil price. We know the oil price is going to come back up. And then the other thing we need to do is differentiate Diamond from the rest of the fleet that's out there, and I think everything came together well. GE understood what we were looking at. We had long and detailed discussions over the course of what is an eight-month period to put together this construct.

There was no precedent. But we knew what we wanted to do, GE got it and their CEO really came to the table on this, GE Oil & Gas and gave us a vote of confidence that we're the people that they wanted to bring this to the market to as well. So it all came together due to the fact that GE knew what we wanted, that we had the assets already on our new drill ships and so here we are.

Right. That all makes sense. Shifting to the dividend, not surprised to see the move today, but just curious if your thoughts have changed, or as you think about across cycles, do you still think that the offshore rig business is capable of having regular dividends?

I'm not sure I've got an easy answer for that one, but, every quarter, our Board meets to consider the dividend. We agreed that our balance sheet is relatively strong and we're comfortable with our liquidity. But let me put it this way, there will be winners and losers in offshore drilling as we progress through what is frankly a super cycle. And we are positioning Diamond to be one of the winners by enabling us to take advantage of the right opportunities if and when they materialize. And I spoke about many different strategic options that we're considering right now. And whether it's a floating factory, whether it's distressed asset purchase, whether it's consolidation through M&A, it's all on the table.

But my management team and myself are positioning us that when the cycle starts -- we start exiting the down cycle, that Diamond Offshore is one of the best, if not the best positioned company to take advantage of the wave so that we ride that wave when it comes back because perhaps let me answer the question in this way. Deepwater drilling will recover; of that I have no doubt. What I can't tell you is when. And to that point -- well, let me reiterate, in the past, we have not given future guidance as to our long-term dividend policy and we've not changed that stance. So that's as much as I can say.

That's all very fair. Thanks, Marc.

Rob MacKenzie, Iberia Capital.

Thanks, guys. I'm going to ask another question on the GE contract in a little different way, I guess. What kind of increase in BOP reliability would you need to see to break even in terms of the incremental costs you are incurring? And further to that, what kind of upside looking at power by the hour in aviation dollars do you think you could really achieve for your customers and yourselves?

Yes, both very, very good questions. Now I will remind you that the near-term impact of the arrangement is not material to earnings. So that's as much as I'm going to say here from a competitive perspective because I don't want to broadcast exactly what's going on here. Gary pointed out what will happen in terms of how it looks on the financial statements, but be careful around suggesting this is going to be hugely incremental or decremental to earnings moving forward.

And as to uptime, this is not -- we're not switching a light switch here and then tomorrow automatically we suddenly have improved reliability. This is a journey. This is a journey that's going to see incremental improvement and the same happened in aviation, the same happened in power generation that over the course of time will improve subsea downtime.

We looked at how much money we lost in 2014 relating to subsea stack pulls and it's significant. It's a very, very large number. If I can improve or reduce that number by 50%, then it's material to my shareholders. So it's an incremental improvement and what it means is we will be -- our revenue uptime will improve moving forward and my partner, in terms of the OEM providing the subsea stacks, will have a stake in the game from a financial perspective.

So, yes, it's going to be beneficial from revenue, but I would admit it's going to be hard to model for you guys right now. I will remind you that with our current status and reliability, if that doesn't improve on our subsea stacks then the OEM is already paying us a malus payment. So they're expecting it to improve moving forward. We're expecting it to improve moving forward and our clients are applauding our efforts.

Great. Thank you. That does it for me.

Robin Shoemaker, KeyBanc Capital Markets.

Yes, thank you. So I was wondering if you could comment on what several other of your peers have talked about in terms of the customers requesting relief from existing long-term contracts. And a second part of that is, if you had a -- if you negotiated a blend and extend deal or since this GE contract goes for 10 years and your current contracts go for three years, what kind of market risk does GE have under these contracts?

Let me take the first half of that question first. In terms of from a contract renegotiation standpoint, look, the current market provides ample incentive for operators to try to renegotiate contracts. Any even observer in the market can see that today, so we get that motivation. That said though, we do believe in the validity of our contracts and we are willing to work with customers to find mutually agreeable trades that help both parties. We did that with Petrobras earlier in 2015 on the Courage and rotating out some older rigs. We did that with other clients along the way.

So those trades are things that we have, I think, a history making where they are good for both parties. But I have to emphasize though we do stand behind the contracts and what they mean. Where we could help a partner solve their problems and help our shareholders at the same time, that's good. But absent I think one customer with Pemex that has some unique rights, absent that though, we do stand behind our contracts.

So from the second part of the question, yes, it's a 10-year agreement. I don't think deepwater drilling with sixth-generation assets is going to disappear. I would argue, however, that you have this kind of construct and I really believe that not all sixth-generation assets are going to be able to do this. Let me just say that we have the highest -- we share the highest credit rating amongst all offshore drillers who are still investment-grade. We received another $210 million of liquidity moving forward.

I can't say that every OEM is going to do that with all of my competitors. Now, to that point, within the contract, there is an ability to ramp down the costs and reduce the services being provided if the rigs go idle. But when my rigs come back for contract renegotiations, we all know that deepwater drilling is still going to exist. My rigs will be -- let's say the expectation is they will be very, very attractive in the market because of this construct and they will go to work.

So I don't think that there's much risk at this time of these assets becoming idled moving forward. And that's the key issue here. What we have done is we've differentiated our assets. I would like to remind everybody once again this was not a liquidity issue for us. This was to lower downtime, improve efficiencies of deepwater drilling, lower the costs for my clients and make my drill ships or my assets more attractive than the others that are out there in the industry.

Okay. Understood. So in the -- if we thought about a stacking cost of a deepwater rig, one of these four rigs in the future, obviously, there is some cost with this contract associated with that.

Well, I don't want to give too much away, but basically it goes down to the cost of borrowing. The other costs go to zero.

Okay. Thank you.

Darren Gacicia, KLR Group.

Good morning. Thanks for taking my question. I'm going to stay on the same line as everybody else, I guess. I guess just from a different functional angle, forget about the economics, when you think about GE servicing mix, is this something where you've leased a specific BOP, or is it something where they have service spaces everywhere? Are you kind of leasing a BOP from their pool so that they can run it -- in terms of maintaining and maintenance taking BOPs on and off rigs, what's the mechanics of how it works with specific assets?

So Darren, this is as it relates to the BOPs we have on the rig itself. These BOPs are actually very, very heavy items. It's actually quite difficult -- well, it's not difficult, it's just a huge logistic issue to transfer a BOP off a rig and get a new one on there. But BOPs are modular, so part of the construct here is actually we'll be first in line from modular upgrades to the BOP stack itself all in terms of driving reliability forward. So this is not sailing around the world and picking up a new BOP. This is a continuous conditioned maintenance type contract moving forward where GE as the OEM is continually incentivized to improve availability and uptime at the BOP stack over and above where we are today in the industry.

So again, one of the things of partnering with GE on this deal is because they have a huge global footprint, so we're not really worried about their ability to service us as we pick up contracts around the world. But I don't expect we will be switching BOPs on and off the rig on a carte blanche manner. This is about continuous upgrades, modular improvements to the BOP stack over the course of time that just continues to drive availability and uptime.

Got you. So for the risk that GE takes -- and it sounds like they have it within a contractual business sense of reward -- what does that do to the average cost of BOPing our rig over time? You used to buy something depending on what the BOP cost was, let's call it $50 million. Then you sat there and maintained it thereafter. If you think about kind of the cost of BOP given the fact that you are getting an added element of service and you are passing on some of your risk, how does that price back in terms of the cost of BOP on a comparable basis to what you were doing before?

So again, I'm going to be very, very careful here because I don't want to broadcast -- I don't want to give our competitors a leg up on adopting this construct should they so desire. This is an expensive negotiation over a long period of time. All I'm going to say, again, is that the near-term impact of the arrangement is not material to earnings, so draw your own conclusions from that. It's not a significant impact on cost for us. There's various elements of the deal itself as it relates to how we reward GE for leasing or the service arrangement moving forward, however you want to put it in the construct. But from the perspective of your models moving forward, we're hoping to see an improvement in revenue in the long run, but the cost, the incremental cost to us, as you can imagine, if it's not material to earnings is de minimis moving forward.

Got you. And just one last one (inaudible). The malus payments, does that only relate to like -- in terms of how they are calculated, is it a cost of your overall downtime, like the overall spread costs in terms of your downtime, or what are the components that go into -- even if you don't want to quantify it, what are the components that go into the malus [products]?

Okay, so we pay a day rate for pressure control. When the stack is down for maintenance reasons or reliability issues then we don't pay that. Then on the top of that, there is a construct that enables us, if GE doesn't provide an uptime metric, which again I'm not going to share with you all, then a malus payment is due. If, however, they provide a standard, which is much higher than we're at today, then, of course, we provide them a bonus payment because we will more than be rewarded by having additional revenue uptime on these rigs.

Got you. Thank you. I will turn it back.

Ian Macpherson, Simmons.

Thanks for the follow-up. Does your agreement address renewal or extension terms after 10 years, or will that only be revisited later in time?

Ian, is your question regarding the renewal of the GE arrangement?

Yes. Sorry, yes, yes.

Yes, yes, fair enough, yes. So do have the ability to renew that agreement before the 10 years is up. We'll have, given the complexity and what it means to continue or not, I think there's a pretty substantial leadtime in the agreement, so we have to declare our intentions. But, yes, there are provisions to renew that agreement.

And pricing is attached to those provisions already?

It addresses some of the pricing topic. It's not pre-wired in that sense, but, yes, that is a topic, which, obviously, pricing something 10 years in the future is not an easy undertaking. So it's addressed conceptually, but it's not an arithmetic calculation.

Got it. Okay. Thank you.

That was our final question.

So thank you for participating in the call today and we look forward to speaking again with you next quarter.

Thank you. This concludes today's conference call. You may now disconnect.