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Pacific Drilling SA (NYSE:PACD)

Q2 2013 Earnings Call

August 8, 2013 11:00 AM ET

Executives

Amy Roddy – VP, IR and External Communications

Chris Beckett – CEO

William Restrepo – CFO

Analysts

Dave Wilson – Howard Weil

Mike Urban – Deutsche Bank

David Smith – Johnson Rice

Ian Macpherson – Simmons & Co

Darren Hicks – Evercore Partners

Darren Gacicia – Guggenheim Securities

Lukas Daul – SEB Enskilda

Paul Cho – Standard General

Jacob Ng – Morgan Stanley

Operator

Good day everyone and welcome to the Pacific Drilling Second Quarter 2013 Results Conference Call. Today’s call is being recorded. And at this time, I would like to turn the conference over to the Vice President of Investor Relations and External Communications, Amy Roddy. Please go ahead.

Amy Roddy

Thank you, Vicky, and welcome everyone to Pacific Drilling second 2013 earnings conference call. Joining me on this morning’s call are Chris Beckett, our CEO; and William Restrepo, CFO.

Before I turn the call over to Chris, I would like to remind everyone that any statements we make about our plans, expectations, estimates, predictions or other statements about the future, including but not limited to those concerning future financial and operating performance, revenue efficiency, operating cost, contract backlog, day rates, rig downtime, market outlook, contract commencement dates and durations, options and extensions, newbuild delivery cost and dates, capital expenditures, the timing and payment of any dividends and plans and objectives of management for future operations, are all forward-looking statements.

These statements are not guarantees of future performance and are subject to risks and uncertainties. Our filings with the U.S. Securities and Exchange Commission which are posted on our website, discuss the risks and uncertainties in our business and industry, and other factors which could prevent us from realizing the outcome of any forward-looking statements. Our actual results could differ materially from any forward-looking statements made during this conference call.

Also note that we use Non-GAAP financial measures during this call. You will find required supplemental disclosures for these measures, including the most directly comparable GAAP measure and an associated reconciliation in our results press release, which is available on our website.

I’ll now turn the call over to Chris Beckett, Chief Executive Officer of Pacific Drilling.

Chris Beckett

Thank you, Amy, and good morning everyone and thanks for joining us today. I am happy to report that our continued focus on fleet performance and expenses has resulted in a third consecutive quarter of strong operational results.

Our revenues for the quarter were $176.8 million, and our operating fleet achieved a revenue efficiency of 90.2%. During this quarter, we completed contractually required upgrades on the Pacific Mistral which includes the installation of new NOV low-force shear ram in the blowout preventer which we believe is the first installation of that system.

Excluding the time dedicated to perform those upgrades, the fleet actually achieved a revenue efficiency of 95%. So we’re extremely happy with the fleet’s performance. The strong revenue generation was matched by good cost control with direct rig operating expenses averaging about a $164,000 a day during the quarter, which delivered an EBITDA of $85.5 million for the full quarter, which excludes the impact of our successful refinancing. And William is going to talk about the financial results in a bit more detail in a few minutes.

But I would like to move on to looking at the operational performance in some more detail. We continued to progress very well with the dual-gradient drilling project in the Pacific Santa Ana. We recently installed the mud-lift pump on both the vessels. And in the coming weeks, we expect to use this system to drill sections of the existing well.

I want to recognize the success of the Pacific Santa Ana crew and the most excited DGD team which includes people from both the vendors and from our client Chevron, that have worked together extremely well in meeting the challenges of implementing this revolutionary project. I am extremely proud of the professionalism exhibited by all those involved, and delivering this leading edge project, at the same time with achieving exceptional operating performance and securing the highest safety rating under Chevron’s Health, Environment and Safety Management System.

This pattern of exceptional performance while implementing leading edge technologies and processes is a consistent theme across Pacific Drilling. And I am equally proud of Pacific Bora’s recent successful construction of a second BOP on two of the vessel in Nigeria. We think this is the first instance that anyone has built a subsea BOP from scratch offshore and it was completed in parallel with delivering industry leading operational leading uptime.

As indicated in our last month’s fleet status report, we expect delivery of Pacific Khamsin in early September, which is a little later than we originally planned due to the requirements from the place that compensate our vessels previously installed on the rig which is since been recalled by the manufacturer, but we’re talking advantage of the extended time in the shipyard to complete activities that we originally planned to perform after delivery. And consequently, we don’t expect startup to be delayed beyond our originally planned timeline in the fourth quarter of this year.

We continue to monitor the progress of our other rigs under construction, and our expectations on that contract startups remain unchanged.

Now turning to the market for ultra-deepwater rigs and our contracting activities. We believe that the fundamentals of the industry will continue to remain favorable. Ultra-deepwater reserves continue to be more economically attractive for our clients than unconventional sources, such as shale oil or heavy oil sands and further developing ultra-deepwater projects is one of the few remaining options for the major oil companies and larger independents to materially impact their reserves.

Well the ultra-deepwater industry continues to be dominated by these large stable operators, developing long-term projects which are relatively insensitive to short-term fluctuations in spot oil prices. But we’ve also seen the emergence of a new class of client in the ultra-deepwater in the form of smaller private equity-backed independents. And in this environment, we saw fixture activity in the first half of 2013 outpace the activity in the same period of 2012.

Second quarter was particularly strong with 38 rig years assigned. And we continue to see stability in day rates for these premium ultra-deepwater rigs with rates in the high 500s below 600,000 per day. As we look into the second half of the year, we expect to see continued strong contracting activity. Obviously the Pacific Meltem is now one of the earliest available newbuilds and we’d expect to be able to announce the commitment in the near future.

Recent new buildings – newbuild ordering activity continues to reflect both the strength of this market and to illustrate the discipline that’s been evident over the last couple of years from the drilling contractors. Our payers and ourselves continue to address the fundamental shortage of high efficiency assets in this market, while carefully managing the individual risk exposure, and helping to maintain the vibrant and strong market.

Turning to our operating fleets, we are in active discussions with Chevron regarding the exercise of options on the Pacific Bora, and we expect to restart discussions with Petrobras regarding the contract extensions for the Mistral in the near future.

One interesting development in the market we’ve seen is some operators starting to request the second BOP on both the drillship and in response to this trend, we recently took advantage of an opportunity to buy an additional blowout preventer for delivery in the third quarter of 2014.

This delivery will allow us to either assign a second BOP to the Pacific Zonda upon delivery or potentially to add a second BOP to one of our other rigs, all of which are capable of carrying two BOPs if we can get a financial advantage from doing so, but we don’t intend to assign two BOPs to our rigs is a standard.

Finally, I’d like to provide some perspective on the company’s long-term capital structure. The recent successful completion of our financial transaction which William is going to discuss in more detail marks an important milestone from the company’s development. Our capital structure has been significantly strengthened, and we have greater financial flexibility as a result.

We expanded our access to the capital markets and further diversified our sources of capital. And we don’t expect our next financing activity to occur until late ‘14 or early ‘15 in order to address the almost simultaneous maturing of our senior unsecured notes and the delivery of the Pacific Zonda. But even with that event, we don’t expect to increase our total borrowings above the level of our current outstanding debt and undrawn credit facilities in order to complete our first eight rigs.

As such, we can now begin planning for the return of cash to shareholders. I have increased confidence in terms of our ability to start distributing dividend as early as 2015, while also continuing to grow the fleet to our target size of 10 to 12 rigs.

With that, I’ll turn it over to William to review the financial results.

William Restrepo

Thank you, Chris. Good morning everyone. As Chris mentioned, our fleet delivered a third consecutive quarter of strong operating performance, with solid revenue efficiency, with the lowest ever rig operating expenses per day, and with contained overhead costs.

As a result, our net income excluding charges from our debt refinancing reached $21 million or $0.10 per diluted share, as compared to $15.1 million or $0.07 per diluted share in the first quarter. The debt refinancing costs consisted primarily of a $27.6 million non-cash write-off of unamortized debt issue cost and a $38.2 million termination fee for interest rate swaps.

The terminated hedges have been replaced by lower cost interest rate swaps. We expect the lower cost in the new swaps to recover the swap termination fee over the next two years. Contract drilling revenue for the second quarter was a $176.8 million, as compared to a $175 million during the first quarter.

The increase was essentially driven by one more day in the second quarter than in the first. Revenue efficiency for the second quarter was 90.2%, in line with the first quarter. In both periods, we experienced similar unpaid downtime in connection with projects related to maintenance or equipment upgrade. I would like to point out, that we do not currently expect material downtime from planned projects during the third quarter.

Revenue for the second quarter included $17.3 million of deferred revenue, slightly above the level of the first quarter. Contract drilling expenses for the second quarter decreased to $79.5 million as compared to $84.5 million for the first quarter. Lease expenses included $9.7 million in amortization of deferred costs and $5.9 million of shore-based and other support costs. This compares to $9.6 million in the first half and $5.6 million in the first half for the first quarter.

Rig related OpEx per day excluding reimbursable costs averaged a $164,000 in the second quarter, as compared to a $178,000 for the prior quarter. Although the $14,000 sequential decrease reflects a general positive trend in expenses, the second quarter did benefit from lower operating costs during the time spend and equipment upgrade projects on two of our drillships.

The focus on these upgrades also resulted in the postponement of the third quarter of two scheduled maintenance projects. Consequently, we expect our rig operating expenses in the second half to increase somewhat over the exceptional level attained in the second quarter.

Reimbursable costs accounted for approximately $11,500 per day in the second quarter of this year, as compared to approximately $14,000 per day in the first quarter. The quarterly variations in these costs are difficult to predict, as they depend on the individual request by clients for items that are on occasion relatively large.

I would like to emphasize though, that the quarterly variations in reimbursable costs have very limited impact on our EBITDA as these costs are fully recovered in our revenue.

General and administrative expenses for the second quarter were $11.6 million, as compared to $11 million in the first quarter. The quarter-over-quarter increase is primarily a result of annual salary increases and equity grants effective on April 1. During the quarter, we have continued to manage the ramp up in operational technical support and the corresponding SG&A costs in line with a new delivery date for the Khamsin and Sharav.

Nonetheless, we expect our overhead structure to continue to growth throughout the remainder of the year towards the level required to support our eight rig fleet. Interest expenses for the second quarter excluding the $38.2 million of non-recurring swap termination costs was $21.7 million, as compared to $22.8 million for the first quarter.

EBITDA for the second quarter adjusted for the debt repayment cost was $85.5 million, as compared to as compared to $79.7 million during the first quarter. The sequential $5.7 million improvement resulted from lower operating costs and by an additional day during the second quarter, which yielded a $1.9 million quarter-on-quarter day, day rate revenue increase.

I will now turn to our capital investment programs and recent financing transactions. During the second quarter, we invested $83 million in our fleet, of which $54 million related to the construction of our newbuild drillships and $24 million was capitalized interest. The remaining expenditures were primarily for contractually required equipment upgrades on our operating rigs that are partially or fully reimbursed by our customers.

Excluding capitalized interest and client reimbursed upgrades, we forecast the remaining capital expenditures to complete construction of our four newbuild drillships at approximately $1.9 billion.

In early June, we issued secured institutional term loan and senior notes for a combined $1.5 billion with interest rates in the low 5% range, and maturities of 5 and 7 years.

The transactions also included a $500 million revolving credit facility that provides up to $300 million in capacity to issue temporary import bonds, as well as $200 million in additional liquidity which is currently undrawn. The notes and term loans funded the repayments of the $1.35 billion outstanding on the Project Facilities Agreement. While providing immediate incremental liquidity of approximately $230 million, including the need for restricted cash, but less the issue costs were new debt and the swap termination fees.

The refinancing also reduced debt amortization payments by over $210 million per year, while removing significant limitations on our ability to pay dividends, and restricted covenants that hampered the free movement of our cash.

Further, we have extended and laddered our debt maturity profile. We have locked in attractive interest rates, and we have reduced the weighted average debt interest to 5.6%. We believe that these transactions when added to the undrawn $1 billion in available capacity from our senior secured credit facility and to a projected $1 billion cash flow from operations in 2015, provides Pacific Drilling with a solid foundation to meet the obligations on our existing drillships and to plan for dividend distributions in 2015.

Finally, we have updated guidance on several performance metrics and costs for the second half of the year. The updated guidance was included on our August 7 earnings press release and is posted on our website. We have also updated our investor toolkit including the impact of our recent refinancing transactions on our interest expense. The investor toolkit is posted on our website under Investor Relations.

And with that, I will turn the call back to Amy.

Amy Roddy

Thank you, William. Vicky, we are now ready to begin the question-and-answer portion of the call.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) We’ll take our first question of the day from Dave Wilson with Howard Weil. Please go ahead.

Dave Wilson – Howard Weil

Hi, good morning. Thanks for taking my questions. Chris, just wanted to get verified from your prepared comments that the Santa Ana does have all the necessarily equipment to drill the dual-gradient well? And secondly, maybe your thoughts around what can potentially delay the startup of the well either from a Chevron’s standpoint or a regulatory standpoint?

Chris Beckett

Yes. So I confirm we now have on board all the necessary equipment to run dual-gradient. We are obviously – we’ve just installed that mud-lift pump which is about the same size as a blowout preventer, so it’s a pretty substantial piece of equipment. And it’s going through its own testing process. It has control systems much like a BOP and so on. And it will take us a little time to get through all of that testing and ensure that it’s going to perform exactly as we intend. But the rig is now fully equipped. There is some minor upgrades and modifications, tweaks to set up that we’re going to want to do as we use the system and see how it performs, but we’re ready to go.

In terms of approvals, we anticipate drilling in certain sections of this upcoming well with this system. As much of – as a proof of concept done and shape down for the equipment, as anything else, we will need obviously formal regulatory approval to complete the well or drilling to our reservoir section with that mud-lift pump which we don’t and haven’t requested as yet, because we want to take this at a measured pace to ensure the equipment performs as anticipated before we enter that stage.

So this well is not a dual-gradient well per se, but we will drill sections of it in dual-gradient, and we don’t expect to drill a complete dual-gradient well until the next well.

Dave Wilson – Howard Weil

Okay, great. Thanks. And then regarding, the Khamsin. Getting closer to the delivery of this, and I know the fleet has reported – you mentioned delivery in the fourth quarter, but depending earlier in the quarter, later in the quarter, you could have a noticeable impact on the earnings for the quarter. It’s just – not trying to pin you down on specific date, but we just wanted to get some idea if you expect it early or late or maybe in the middle of the quarter?

Chris Beckett

Yes. So we’re expecting delivery on the Khamsin in early September. And then we’ll mobilize it to Nigeria, which is where it will start operating. We expect it to be in Nigeria middle of the quarter and then its question of time required for claiming customers which is obviously a little bit of a difficult timeframe to forecast, but we’d expect to see a meaningful impact in Q4 at this point.

Dave Wilson – Howard Weil

Okay, great. And then one more if I could.

William Restrepo

I think our experience has been between two weeks and a month.

Dave Wilson – Howard Weil

All right.

William Restrepo

For all the necessary approvals.

Chris Beckett

Yes. For the purposes of modeling, then you can probably assume December 1 is a reasonable date for revenue contribution.

Dave Wilson – Howard Weil

All right (inaudible). And then one final one if I could sneak one in here. Given the size of your fleet and where you want it to get it. Do you think you have enough critical mass now to source the key rig employees from your current labor force, through internally gained experience, or do you think you’ll have to go out to the market to find that experience and that talent to staff up the other rigs?

Chris Beckett

Yes, I mean in general we have staffed the key positions on Khamsin and on Sharav from our existing employee base. So that’s our primary preference, and that’s why we are obviously using the opportunity to take the good guys that we got, and promote them where the opportunity is available. Having said that, we’re also still looking to add talented individuals who may be available in the marketplace where we can. So it’s going to be a combination of both on a longer scale [ph].

Dave Wilson – Howard Weil

Okay, great. Thanks for the additional info. I’ll turn the call back over.

Operator

Thank you. And we will take the next question from Mike Urban with Deutsche Bank. Please go ahead.

Mike Urban – Deutsche Bank

Thanks, good morning.

William Restrepo

Good morning, Mike.

Mike Urban – Deutsche Bank

The dual-gradient opportunity sounds pretty exciting. It’s something that we’ve talked about a lot since the IPO and then before that. Are there any other opportunities out there? Are there any other operators that are looking at those kind of wells or is this the thing where it’s somewhat of a – I don’t know, science experiment is the right word here and we’ll see how the opportunity goes with Chevron, and that might unlock other opportunities for you. I’m just wondering if that is something that’s kind of a differentiator for you.

Chris Beckett

Yes. So I think we would describe it as having moved beyond the science experiment stage sometime ago. This was born out of the joint industry project, where there were multiple oil companies and others involved in the development of the concept. This commercialization phase we’re in now is I would say beyond the science experiments. In terms of its applicability to other operators, it’s particularly valuable technique in very deep wells, in very deepwater.

So anybody who is working (inaudible) in the government, I would imagine will have some interest in using it, once it’s been commercially proven as we expect in the next probably 12 months to get people comfortable with it. So our expectation is, yes, it will have significant applicability for a wide range of operators, initially in the Gulf of Mexico and potentially in further fields as it gets more developed.

But Chevron has taken on the challenge of proving everything up from a commercial standpoint, and going through the initial startup phase on this. And they are obviously very committed to it, we’re very committed to it as well. And we think that it will be an interesting and attractive technology for other players in the very near future.

Mike Urban – Deutsche Bank

Great. And I have a related follow-up. In terms of bifurcation in the ultra-markets, I think it’s a pretty well accepted principle, but thinking whether it was kind of ultra-deepwater and then everything else, yes, I think you mentioned in the press release and I think the data would bear this out as well, but with the leasing [ph] is that even seeing that between newbuild or sixth generation assets versus the existing fifth gen fleet. One, is that something you’re seeing, and two, are you concerned about creating kind of an arms race there. In other words, overcapitalizing this fleet whereas the operators are just conditioned only expect and only pay for the newest and the best, and even though you have very capable assets in the fleet, otherwise you kind of are constantly in CapEx mode?

Chris Beckett

Yes. So I think there is a perception – there has been a perception that is concept of bifurcation is about age of the assets or about water depth of the assets. And frankly I don’t think it’s about eavesdrop and particularly, they’re just coincident to really the drivers behind it which is the enhanced efficiency of the latest generation of rigs, and we would consider that as sort of second term generation as we think of them in the drillship world, bring significant benefit to the clients and they are willing to pay for that.

Now there are obviously some fifth generation rigs that have similar levels of efficiency, there are some sixth generation rigs that are less efficient than the average, but I think clients tend to be much more measured and sensible if you like, about their analysis of the assets that are offered to them and look at what they can – what they are really going to gain from them, and they’re willing to pay for assets that will deliver wells faster and more efficiently.

So it gets – we tend to generalize a lot of things. I am talking about bifurcation. It’s really about clients being willing to pay for. What a rig will do for that? So I don’t necessarily see that leading to some kind of an arms race where we continue to keep tweaking individual assets. There is some fundamentals that have to be in place for the rig to be more efficient, and if they are [ph] and clients are willing to pay for that at this point. But there is a clearly a preference and therefore willingness to pay, because of the benefits of enhanced efficiencies with these new assets.

Mike Urban – Deutsche Bank

Okay, great. Very helpful. Thank you.

Operator

Next up is David Smith with Johnson Rice. Please go ahead.

David Smith – Johnson Rice

Hi, good morning. Thank you. Regarding client demands for dual BOP systems, can you help us think about the economics that makes the second BOP investment attractive to the rig owner? Whether the second BOP translates into less unpaid downtime, maybe the range of about a day rate or payback period that compensates for the investment?

Chris Beckett

Yes, good morning, Dave. I can tell you how we think about it. I think each drilling contractor has their own views of the benefits. Our general bias is that the majority of it or frankly, the lion’s share of the benefit is accrued by the clients, in as much as it may help reduce non-productive to them. And as such, we would look for the client to cover the majority of the cost.

Now I think from a drilling context standpoint, there are some benefits in potentially reducing downtime. And there are really two possible sources of that, one is sort of unplanned, unexpected downtime where having a second BOP, that’s ready to go to work, may allow you to just swap out the BOPs rather than have to repair and then re-run, but it’s not clear how much of the time you’re really going to gain that benefit, because practically speaking you’re not going to have the BOPs sitting fully dressed, ready to go all the time.

The second area where this probably benefits in between well maintenance, whereby we can effectively trade out the BOP and then perform maintenance on the one that we’ve just recovered from seabed, drilling in the progress of the next well and that clearly can be a benefit – that could be planned for and valued in.

Was that worth? I think it depends on the nature of the contract you have. So it’s hard to give you a generalization, but if you think about the maintenance – between well maintenance time taking 10 days, and that maybe happening two to three times a year, if your contract provides for you to get that maintenance paid already, then there is less value in having second BOP. And if doesn’t, then it could save you a portion of downtime. But that’s kind of how tend to think about it.

When we roll out together and look at it across the fleet, we see that it may make sense to have two BOPs on some of our fleet, but it’s not something we expect to make a fleet standard. And we look for the clients to contribute towards the cost of that second BOP, because frankly they get the greatest benefit.

David Smith – Johnson Rice

That’s very clear answer. Thank you. And just a follow-up on the comments around the ultra-deepwater bifurcation and growing operator demand for the newbuilds compared to the earlier fifth gen rigs. Is there any concern that this aftermarket for the early fifth gen rigs could see those units try to compete for utilization with pricing, and throughout in the broader day rates structure, or maybe that the demand shift just more structural with enough operators especially the IOCs [ph] that just own one or neither of earlier units?

Chris Beckett

Well I mean clearly I think there is a probably a couple of different markets for the ultra-deepwater rigs. There is the market for very deep wells in places like the Gulf of Mexico, where frankly you just can’t drill them with a fifth gen. You don’t have the hook load capacity and so on. And so that one is a market that’s going to be addressed by sixth and seventh generation rigs, exclusively going forward. And then there is a broader market for ultra-deepwater, but not necessarily ultra-deep wells, where fifth gen and earlier rigs can compete in terms of being able to operate there, but they are going to be less efficient and that’s going to drive a cost differential between the rigs.

If your question is, am I concerned that we could see rigs drag down because fifth gens are willing to operate at very low revenue streams? I don’t think we’ve seen that so far, but I am not sure we’re that qualified to say, what people might be willing to operate fifth gens at. But it’s clear that there is a sufficiently large increase in efficiency from the latest generation of rigs that clients can afford to pay a significant premium and still come out ahead because of the straight cost impact.

David Smith – Johnson Rice

Very helpful answers. Thank you, and congratulations on another solid quarter.

Chris Beckett

Thank you.

Operator

Next is Ian Macpherson with Simmons.

Ian Macpherson – Simmons & Co

Thanks. My congratulations as well on the quarter. And Chris, first question I had was could you just refresh us on your – the total BOP inventory status across your fleet now. You mentioned ordering the additional unit this past quarter. So across eight drillships, how many total stacks do you have or have on order at this time?

Chris Beckett

Yes. So at this point in time we have two stacks installed on the Pacific Bora.

Ian Macpherson – Simmons & Co

Okay.

Chris Beckett

And we’ve just built the second one actually offshore. We have one stack on the Scirocco, one on the Mistral, and one on the Santa Ana. We have the Pacific Khamsin being delivered with one stack, but Sharav with two, the Meltem and the Zonda each with one and then as I mentioned – as we mentioned are mostly ordered new an incremental stack that we can assign to – whichever the rigs deserve it shall we say, in terms of being able to give us a benefit from having that extra stack there.

And we have the majority of stack as a fleet spare that we use for – we can use on any of the rigs, and that that’s always been intended to be there as our fleet spare was part of the original four rigs that we ordered.

Ian Macpherson – Simmons & Co

Okay. So it sounds like with the recent order, you – not to put words in your mouth, but it sounds like you’re content with that inventory being across the fleet?

Chris Beckett

Yes. I mean obviously if we have a client who wants one of those incremental stacks and is willing to pay for it effectively, whether that’s direct or through rate change or whatever, then obviously we look at ordering another one, because there are some clients for whom it’s a marketing differentiator. But we don’t believe that – we’re not looking to move to having two stacks in every rig unless it’s clear that we get paid for them.

Ian Macpherson – Simmons & Co

Okay. And then with the dual-gradient kit, where do you think a realistic timeframe is for getting sort of completing the first complete well next year, and then how that may feed into a decision to expand the technology onto a second rig, either at Chevron (inaudible) your ability to market it outside of – that specific relationship with Chevron?

Chris Beckett

Yes, and it’s obviously the well planning program for the Pacific Santa Ana on Chevron and I am not sure that we can give much more detail as to exactly what their well program looks like at this stage. I think that we need to leave with them, but we would expect that by the next year, we would have used the system in (inaudible). As far as preparation of another rig to be able to provide the same services, we’ve done 95% of the work for the Pacific Sharav to be capable of delivering a fine service.

So that rig is basically ready to go. We would need another mud-lift pump, the Max Lift [ph] pump and that’s probably got a couple of years delivery window on it, but we will have a second rig in the fleet, that’s largely completes the dual-gradient already.

Ian Macpherson – Simmons & Co

But the mud-life pump you said probably would be two year lead time?

Chris Beckett

Something like that.

Ian Macpherson – Simmons & Co

Okay, interesting. That’s great. Thanks very much.

Chris Beckett

Thank you.

Operator

Next we’ll go to Darren Hicks with Evercore Partners.

Darren Hicks – Evercore Partners

Hi, good morning.

Chris Beckett

Good morning.

Darren Hicks – Evercore Partners

I just wanted to touch on the dividend topic. What is it likely to have the biggest influence on the timing of the dividend initiation, as you probably know a dividend initiation would be a catalyst and would open the stock up to a whole new category of investors? So in your opinion would it mean the additional new building financing that’s likely to come at the end of ‘14 and early ‘15 or maybe the contract renewal rates or terms for those rig that are going to be available in late ‘14 or ‘15, or is it the potential delays it may occur or early deliveries I guess on the Meltem and the Zonda? Which one do you think will have the biggest influence, or may have the biggest influence on a dividend initiation?

William Restrepo

Darren, I think there is a lot of things that you covered there, but our cash flow is nearly as 2015 indicated by year end. We will have sufficient cash to fund the dividend. The only requirement that we have for financing in late 2014 early 2015 is only because the two payments comes simultaneously, so we have to inject temporary some cash to be able to meet our obligations in the first half of 2015. By the second half, we don’t have those issues any more. So we – now the decision will be – the biggest impact will be the decision of the board.

The board obviously is on board today but we’ll have to seek their approval, but I don’t believe it will be a cash flow issue in 2015. That’s why we went ahead and said, we’re already planning for that.

Darren Hicks – Evercore Partners

Okay, great. Thanks. And on the operating cost side, you mentioned that second half ‘13 costs would likely be higher than what you posted in the second quarter, but is there anything that you could point to in this quarter that just passed that could be possibly replicated and help keep operating costs going forward, a little bit more subdued?

William Restrepo

I would tell you something, I think that $164,000 is probably about the lowest in the industry and that was not our plan. They have as lower costs as we did. But because we are working in some equipment upgrade projects, our costs were temporarily reduced, so I don’t think the $164,000 is indicative of where our costs should be.

I’ll tell you one thing, two things you don’t skimp on, it’s your employee compensation which is the largest piece of your OpEx, otherwise your turnover will increase and you will lose people, the right, left, and center. And you don’t skimp on maintenance. Those are the things – I mean we are not here to provide the lowest cost in the industry, but we will certainly be one of the most well-managed cost basis in the industry and we’ll be sure that we keep our cost at reasonable level, and that we invest in the right things. That’s our focus in terms of OpEx.

So we’re very proud that we manage to get the results that we did, but we do expect that some of the projects that were rescheduled to the third quarter will have an impact. And I think their guidance will prove out to be right.

Darren Hicks – Evercore Partners

Great, thank you very much.

Operator

And we’ll go to Darren Gacicia with Guggenheim Securities.

Darren Gacicia – Guggenheim Securities

Thanks for taking my question. One of the things that’s come up on a previous call today, was there seem to be a little bit more of a cautious view on the market. I’m trying to calibrate that, and I think probably two ways to sort of think about it. The first one is, are you starting to see any kind of weak players in the market that maybe sort of more willing to compete on price? And the second, yes, it seems like everybody has a pretty rapid ramp in the trajectory of development drilling and the speed at which it will come. Do you think the market maybe a little bit aggressive on their thoughts with regard to how quickly development work maybe there albeit with the inventory flow projects is there?

Chris Beckett

Yes, so I mean I guess firstly I’ll tell you, we always compete on price, that’s the nature of the tender process we go through in the majority of cases. Occasionally you get the direct award discussions, but most of the time it’s a tender process, and to some degree it’s competition on prices.

But we haven’t seen people rushing to the bottom. I think that the markets for these latest generation of assets continues to be pretty strong, and we haven’t seen it fall of appreciably in the last couple of months, but I think we have seen this bias towards wanting the newest generation of rigs.

As far as the – lot of the forward demand is predicated on development projects, as you say, but not all of it. We’ve seen quite a lot of rig contracting activity this year from some of the – from some companies that are clearly focused on exploring. And I think that the rigs that have been contracted so far have been contracted against existing successful projects. So eventually a significant amount of potential demand is there on the success scenario, that various of our clients are thinking about right now whereby they know that they’re actually short and will have to take incremental mix, but this cycle or the market in general goes through these pulses of activity and we continue to be extremely comfortable with the state of it. We’re not seeing any evidence ourselves that the rates are looking weak and appreciable [ph].

Darren Gacicia – Guggenheim Securities

Well I think the tender market probably gives us a little bit better visibility in to ‘14, but there is definitely, I don’t know, if the question was the wrong word, I think that there is a visibility issue for ‘15 for investors and kind of beyond. How is your visibility shaping up for ‘15 and beyond? Is it getting better or worse in your view of the market, is it getting kind of incrementally better or worse?

Chris Beckett

Yes, it’s interesting. One of the things that we tend to track is the amount of rig months within the next five years that are contracted, and in terms of the percentage of the total available time within the fleet that we consider competitive. And relatively small percentage changes in that tend to illicit fairly significant psychology changes in our investor base frankly.

And so we’ve seen – the way that dynamic works is you add a couple of rigs to the fleet, and that obviously increases your number of available months, so unless you contract at the same sort of pace then you change, and it’s typically run some around 61% to 65% contracted on a five year outlook, that’s been kind of the way it’s been for the last couple of years. And we see changes in sentiment from the investor base when we see changes as little as 1% in that absolute level of contracting.

And honestly we’ve seen that level come down by about 1% over the course of the last quarter. But frankly, coming from 63% to 62% in our view is not really a material change in the level of contracted activity or contracting activity, but it’s indicative of maybe the pace. So we’re going to see that this norm in the industry of the industries either always growing or shrinking, and therefore there an expectation that it must be getting – the pace of activity must be accelerating or decelerating.

And frankly it’s been remarkably stable for the last over a year now, and I think that that’s drives people to be concerned that stability is not the norms of the ultra-deepwater or the drilling space in general, so they are looking for it to change, when it’s not necessarily going to.

We’re – I’ll just tell you, our view of ‘15 is that when you look at what’s being added in terms of that incremental supply and what could be added which at this point is pretty much if it’s not been ordered, it’s not going to come because it’s too late for ‘15 delivery anyway. And we look at why we see the probably growth in the demand going, we see the markets still significantly undersupplied.

So we’re extremely comfortable with ‘15 and we’re starting to look into ‘16. We haven’t done that detailed analysis, but the team is working on that now. And we’re extremely comfortable with the state of the markets, certainly for ‘15.

William Restrepo

I’ll make a comment on that Darren also. This is William. There is lot of noise in the industry coming from different sources. Some of the newer players with quality assets speak out and as well as some of the bigger players with sloppy fleets and by that I mean older assets. But I’m sure those bigger players with older assets should be concerned. I think that’s part of the reason they are listening to some negative flow because all the fleets are not clearly equal, they are different.

Darren Gacicia – Guggenheim Securities

Understood. Well, thanks again and I very much applaud the gravitation towards the dividend.

William Restrepo

Thanks.

Chris Beckett

Thanks.

Operator

And at this time there is one name remaining in the queue, so if there are any additional question, please press star one at this time. And we will go to Lukas Daul with SEB. Please go ahead.

Lukas Daul – SEB Enskilda

Hi guys, good afternoon. A question on…

William Restrepo

Hi Lukas.

Lukas Daul – SEB Enskilda

Some six months ago you have been talking about you and the industry basically discussing how to deal with the – let’s call it increased downtime on the subsea equipment etcetera in the contract negotiations. And I was wondering whether there has been any change or maybe going towards some sort of a new equilibrium in that sense? Could you provide some color on that?

Chris Beckett

Yes. I think what we have seen in the industry is a recognition in most clients that the level of maintenance that’s required to keep a BOP fully functional and fully operational when its operating in 8,000 to 10,000 feet of water is significant. And there needs to be within the contract, the recognition that that’s part of the service that we provide is the maintenance of the BOP between those and so on.

So I think that side of things – yes, there has been something of a recognition in the industry, that that part of the basic services level is to be compensated. I think it’s always going to be hard to try and persuade clients that should pay you for non-productive time when your equipment doesn’t work. And frankly that’s not what we’re trying to do. What we are trying to do is get them to accept that in order to avoid that non-productive time, we have to do certain levels of basic maintenance that require more time to complete in today’s regulatory environment.

And so I would say yes, I think we’ve got to a recognition with most clients if that’s the case and a willingness from most clients to contribute towards that, or consider to be part of the services should it compensated. I think that’s part of the driver why you’re seeing some clients look at this concept of adding the second BOP, because to the extent that they are going to recognize that maintenance on the stack is a fundamental requirement and part of the basic services then adding a second BOP allows them to continue working and not suffer non-productive time themselves while they’re paying you to do the maintenance.

So that’s – I think it is the driver behind why you see some clients start to look at that. And then it becomes an economic question of whether the second stack causes is justified by the potential non-productive time saving. It depends very much on the program they’re working on, how long the wells are water depth and all sorts of other things.

Lukas Daul – SEB Enskilda

Okay. Well that’s a good color. And then William, you mentioned the salary increase throughout the organization in April, and I don’t know if you want to disclose the percentage increase, but if you were to look one year, two years ahead, there is obviously one of the rigs been delivered to the market, do you have an estimate for what to expect on the labor cost side going forward?

William Restrepo

I will just make a couple of comments. First of all, what I was referring to April was the SG&A really, so it’s not really operational personnel. The operational personnel salaries were increased on January 1. And what we guided at that time was the impact of those salary increases would represent a 5% hit on our total OpEx. The reason is that about 6% of our costs come from personnel, so you can work backwards and see what our salary increases were.

We expect at least during the coming years, we expect to see similar rate of increases overtime that will take care of itself, but more people brought into the industry. Right now the industry is ramping very fast and people have to be attracted to the industry. So we have seen increase in general – in operational personnel salary increase.

Lukas Daul – SEB Enskilda

Okay. Perfect. Thank you very much for that. Thanks guys.

Operator

Next is Paul Cho [ph] with Standard General [ph]. Please go ahead.

Paul Cho – Standard General

Hi, thanks for taking my question. I just wanted to look forward as you progress in the future, and I just want to know like when your fleet is completely delivered what your maintenance CapEx will be, and then special survey costs I guess on top of that?

William Restrepo

Maintenance CapEx is a concept that really we should go after (inaudible). When you have a new fleet with assets almost three years old and that have life in the seven years or over, you don’t have a lot of maintenance CapEx for a long time. So that’s one the advantages of a new fleet. Obviously it’s a big marketing advantage, but it’s also a great cash flow advantage.

When we look at EBITDA margin for a company, that’s it, we don’t have those big cash trends on the existing assets that you would see in a fleet that is more spread out in terms of age distribution. So what you do expect is that after five years, we’ll have to sell it, and I’ll tell you what remodel, it doesn’t mean that that’s going to happen but we expect somewhere in the range of $7 million or so up to five years including the cost of the survey plus incremental CapEx and that number being higher for the 10 year survey.

And then when the rig are getting to reach towards the 10 year old level, then we can start talking about maintenance CapEx. For the time being, I can tell you that level is pretty close to zero.

Chris Beckett

Yes, I mean I’ll just echo that a little bit. I think that the point William is making is the money we’re spending on our rigs in terms of maintenance, now there is different reason capital equipment because it’s not worn out or wearing out at this stage in time. So we don’t see a lot of maintenance CapEx at this time.

Our forecast that we give you on what we report in terms of maintenance OpEx is our maintenance costs, and we don’t have much of that allocated to capital projects at this stage. I don’t believe we will until the rigs are certainly beyond five years old and possibly longer.

Paul Cho – Standard General

Okay. So even though let’s say the impact of life for a rig is like – let’s call it for accounting purposes like 25 years, you’re saying the cash costs in the first five is de minimis and then it sort of ramps up over the last half of the year after life.

William Restrepo

So the way you need to think about the rig is not like one element. The rig is made up of multiple components, some of which are very, very long life in five years and others that have seven years, others that have 15. So it’s a whole mix of assets. And if you start to hitting the life of the total big assets than your start seeing some maintenance CapEx. Then 10 years down the road you see some more as we hit the next layer of depreciating equipment let’s say with longer life. So that’s how you need to view it.

So when you have a fairly new asset, there is nothing really happening in terms of – to have CapEx you have to replace something on the rigs that’s materially enough and those things have just doesn’t happen too much in the first five years.

Paul Cho – Standard General

All right, that’s great. Thank you very much.

Chris Beckett

Thanks.

Operator

And we’ll now go to the Jacob Ng with Morgan Stanley.

Jacob Ng – Morgan Stanley

Thanks. Good morning and congrats on the quarter.

William Restrepo

Thanks, Jacob.

Jacob Ng – Morgan Stanley

I am just wondering if you are seeing new building supply issues crop up on the A&F [ph] equipment manufacturers in shipyards, and would you say there is no high risk of new building delivery delays with the industry as a result of this?

Chris Beckett

So I think we’re seeing something that I would consider unique and obviously the Pacific Khamsin is going to be delivered to us little bit later than we had anticipated. Now we’ve been able to offset that by doing that work ourselves but that’s on the back of an equipment issue, but it’s not a supply chain issue as much as an equipment quality issue in that case. In that equipment, those pressure vessels are being replaced.

In terms of pressure on the supply chain in general, I think that many of our peers have made similar comments that we’re seeing some pressure on the subsea equipment, across the board, and I think that may increase the risk of some delays on some of the rigs. And we’re not immune from that. The Khamsin is delayed a little bit by a specific issue on pressure vessels, but frankly that’s masked with the fact that otherwise you might have had a week or two delayed on the back on the subsea equipment.

So yes, we’re seeing some of that. The forecast that we use in our forward guidance, takes into account some assumptions about any risk, if there is any to supply chains and delivery windows. We’re not seeing anything that we consider will push out the start days of our first revenue or risk any contract that we have in hand, but I think it would be fair to say that there is some incremental risk today versus a year ago on the supply chain, and in particular for subsea equipment.

Jacob Ng – Morgan Stanley

Got it. And just a quick follow-up, if you do see other newbuild today, when might be the earliest delivery date be given your option for ninth newbuild is already expired?

Chris Beckett

Yes, we’ve actually been having those discussions just because we like to understand where the market stands, and we’re not yet in a position already to order an incremental rig, but our basic understanding is given our timeline for an order of end of the year than – or early next year we’d be looking at a Q2 ‘16 delivery.

I think if we wanted to accelerate the Boda, we might be able to get a Q1 ‘16 delivery, but I think that’s kind of the earliest, we don’t see anything at this point.

Jacob Ng – Morgan Stanley

Okay, great. Thanks for the color. I’ll turn it over.

William Restrepo

Thank you, Jacob.

Chris Beckett

Thanks.

Operator

Thank you. And that does conclude our question-and-answer session for today. I’d like to turn it back to Amy Roddy for any additional or closing remarks.

Amy Roddy

Thank you everyone for participating in Pacific Drilling’s second quarter 2013 results conference call. William and I will be available for the rest of the day for any further questions. Thank you.

Operator

Thank you very much. That does conclude our conference for today. Thank you for your participation and you may now disconnect.

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