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Executives

Chris Beckett - Chief Executive Officer

William Restrepo - Chief Financial Officer

Amy Roddy - Director of Investor Relations

Analysts

Dave Wilson - Howard Weil

Todd Scholl - Clarkson Capital Markets

Andreas Stubsrud - Pareto

Anders Bergland - Platou Markets

Matt Beeby - Williams Financial Group

Chris Kallos (ph) - Net Capital

Darren Gacicia - Guggenheim Partners

David Sparks (ph) - BB&T Capital Management

Pacific Drilling S.A. (PACD) Q4 2012 Earnings Conference Call February 28, 2013 10:00 AM ET

Operator

Good day and welcome the Pacific Drilling, fourth quarter and full year 2012 results conference call. Today’s conference is being recorded.

At this time I would like to turn the conference over to the Director of Investor Relations, Amy Roddy. Please go ahead ma'am.

Amy Roddy

Thank you Jessica and welcome everyone to Pacific Drilling, fourth quarter and full year 2012 results 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-rate, market outlook, contract commencements and durations, new build delivery cost and dates, capital expenditures 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.

And with that, I will now turn the call over to Chris Beckett, Chief Executive Officer of Pacific Drilling.

Chris Beckett

Thank you Amy. Good morning everyone and thank you for joining us today. Before William provides the details of our financial results and our written financial transactions, I’ll disuses the operational performance and the highlights of the company over the past year before I close with comments from the market’s relative deep-water rigs and its impact on our contracting activities.

The fourth quarter of 2012 reflects a very strong operating performance by our fleet, with all four rigs having now completed their shakedown periods. Our revenue for the quarter was $192 million and our operating fleet achieved an average revenue efficiency of 94.6%, is at the top end of our range of expectations for the quarter.

Looking at the individual performance of our rigs, despite 12 days of previously disclosed downtime in early October due to work on its blowout preventer, the Pacific’s Santa Ana reached its six month milestone of operations in early November and performed extremely well for the rest of the year, achieving the revenue efficiency for the quarter of 87.3%.

Also during the quarter our other three operating rigs continued to exceed our operational targets. The Pacific Bora averaged 97.4% revenue efficiency during the quarter, the Pacific Mistral has just completed its first year of operations as of February 6, this year, delivered 93.9% revenue efficiency, which exceeds our expectations for drillship in its second six months of operations and its particularly impressive given the challenging contracts that its working under.

And I particularly want to recognize Scirocco’s outstanding performance in the startup. The rig achieved a year without an OPI at the end of 2012 and delivered an exceptional 99.8% revenue efficiency for the fourth quarter. In January we finally brought the blowout preventer for that rig to the surface to perform client maintenance and client requested upgrades after over seven months of uninterrupted operations. So even with that maintenance period we really delivered over 95% or just about 95% revenue efficiency since start of operations 13 months ago.

I’d now like to take the opportunity to address the safety alert that was issued on January 29 by Beckie regarding GE connectors and bolts. We previously stated that we expected no direct revenue impact as a result of the safety alerts and I’m pleased to report that we’ve already completed the replacement of the required bolts on the Santa Ana, the Scirocco and the Mistral and we are in the process of changing the bolts in the Pacific Bora as we speak. In terms of the replacements that were scheduled around our customers drilling plans, there was no related revenue loss in any rig for this replacement.

Finally, before I move onto the status of our construction, I’d like to discuss our ongoing efforts to achieve and maintain an optimal balance of performance and cost management. William will discuss our costs in more detail, but I would highlight the beginning of 2012, as Pacific Drilling transitions from an operational start up to a mature operating company, we’ve begun to focus on performance managements of the strategic tools to deliver the value proposition that we promised our clients.

We laid a strong foundation with a state of the art Pacific Drilling management system and the associated quality management processes over the course of the last few years, and in January we created a specific function to support the implementation of key performance indicators throughout the organization.

While the details of these internal efforts may not be directly visible to those outside the company, it’s our expectation that they will ultimately be visible for our consolidated financial performance and the strength of our client relationships and is a natural part of our maturing organization.

Moving on there to our rigs under construction and our plans for future fleet growth. Since our last conference call, our rig construction program continues to progress. We are undertaking fleet commissioning and commissioning on the Pacific Khamsin as planned and expect to take delivery of the rig in June.

On January 22 we launched the Pacific Sharav and expect delivery of the world’s second drill rig in drillship in the late fourth quarter. We also touched in the Pacific Meltem on October 24 of last year and the construction progress is on target. Finally, of course we announced the order of our eighth drillship from Samsung on January 22 and we expect to cut steel on that vessel in October of this year.

Together with the order of that eight rig, we received an option for a ninth rig, which expires on April 30 of this year. Well as previously indicated in both our presentations and our conference calls, the pace of our growth will take into consideration the state that we ought to keep with the markets, as well as operational and financing criteria. At this time we do not expect to exercise this option within its current validity, but of course we will look to extend the expiration date if we can.

Now turning to the state of the deep-water market and our contracting activities. Presenting the rigs and commentating of course that ultra deep water rates have leveled off and the rated contract awards have slowed. However we continue to see a very healthy supply in demand balance through 2015 and we expect rates to remain at their current levels for sometime. Furthermore those current rates are for very attractive returns to drilling contractors.

The ultra deep-water rig market’s always been characterized by high variability and the level of contracting activity and we are very comfortable with the state of the market. We are confident that we will secure attractive contracts for the Pacific Meltem and our newly ordered rig and we are already in discussions regarding extensions on the contracted rigs with our various clients.

While I’m not going to go into discuss the specifics of those negotiations on Pacific Bora, Scirocco and Mistral, all of those contract extension conversions are already underway, and given the current market conditions, we would expect to deliver a meaningful rate increase on those rigs that have un-priced options.

Now before I turn the call over to William, I want to reiterate that the company’s focus and performance excellence to support our client’s goals and the growth of our earnings. 2013 will represent the first full year of operations for our initial four rigs. The Pansan will join our operating fleet by the end of the year. We continue to secure attractive financing to support fleet growth and we look forward to the delivery of two more rigs this year, to further contribute to growth in 2014.

With that I’m going to turn it over to William to review the financial results.

William Restrepo

Thank you Chris. Good morning. Before I begin with a discussion of our financial statements, I would like to point out that in the fourth quarter our operating fleet started to demonstrate what our company can deliver, now that our rigs are fully operational.

Although our newest rig, the Santa Ana, finalized in early November, what we call a shakedown period in its first six months of operations, our remaining three rigs were already beyond that initial period. As we had anticipated, all three of our post shakedown drillships had strong financial performance during the quarter as a result of high revenue efficiency rates and decreasing operating expenses.

For the first quarter of 2012 we had net income of $15.5 million or $0.08 per diluted share. As compared to the third quarter, net income increased by $18.5 million. This improvement reflected a $19.9 million increase in revenue and a $9.3 million reduction in operating expenses, partially offset by a $5.8 million increase in interest expense and $2.9 million higher income taxes.

Contract drilling revenue for the fourth quarter of 2012 was $191.9 million as compared to revenue of $172 million during the third quarter. The 11.6% increase in drilling revenue was primarily the result of an 11.5 percentage point improvement in revenue efficiency, reflecting significantly higher revenue for the Santa Ana and above expectation revenue efficiencies for the remaining three rigs.

Contract drilling expenses for the fourth quarter of 2012 were $86.9 million as compared to drilling expenses of $96.2 million in the third quarter. Direct rig operating expenses accounted for $63.7 million of the total, while shore-based and other support costs were $4.6 million.

The 9.6% reduction in contract drilling expenses was a result of the $7.2 million reduction in direct rig operating expenses, driven primarily by significantly lower maintenance and repair costs by the Mistral and Santa Ana and by a $2 million decrease in our shore based and support costs, reflecting cost reduction measures throughout our support structure. The proceeding rig and support cost decreases also included a $1.3 million and a now recurring reduction in compensation costs.

Our average fleet direct rig expenses decreased sequentially from $192,500 per day in the third quarter to $173,100 per day during the fourth quarter. I would like to point out thought that the non-recurring reduction in compensation costs just mentioned, accounted for an improvement of $2,700 per day in rig OpEx reduction in the quarter.

General and administrative expenses for the fourth quarter were $11.6 million as compared to $10.5 million in the third quarter of this year. Third quarter expenses included an implement on $900,000 in legal and consulting fees, mainly related to the restructuring of legal entities and ownership structures to optimize our tax and treasury processes.

Interest expense for the fourth quarter of $32.7 million increased by $5.8 million, mainly as a result of the non-recurring, non-cash $2.8 million charge, related to the accounting of our interest rate cash flow hedges, and to the issuance of our senior secured bonds in the month of November.

The income taxes for the fourth quarter were $7 million or 3.7% of revenue, as compared to $4.2 million or 2.4% of revenue during the third quarter. Our total income taxes for the full year were $21.7 million or 3.4% of total revenue, somewhat below our full year guidance of 4% to 4.5%, mainly as a result of the streamlining of our legal entity structure mentioned previously.

EBITDA increased by $27.4 million or 42% over the third quarter to $92.7 million, reflecting the stronger operational performance; both in terms of rig up time and operating costs.

I will now turn to our recent financing transaction and investment programs. We ended 2012 with $778 million in cash and cash equivalents, of which $172 million were restricted by our project financing facility or were collateral for our balance and other lines of credit.

In November we issued $500 million or 7.25% senior secured bonds upon construction of Pacific Khamsin. This offering marked our initial entry into the U.S. fixed income markets, providing us with one more attractive source of capital and a much broader group of investors to help us fund our future growth.

The outstanding debt on our credit facility at the end of 2012 through that $1.5 billion and together with the $800 million in bonds issued in 2012, our total debt was $2.3 billion.

We continue to work with our lenders to relieve trapped cash and in December we negotiated a release of $78 million of restricted cash from a project credit facility. This release is recognition by a lender group of the increased operational and financial strength of our company.

Finally, we recently entered a $1 billion secured credit facility with a group of non-commercial banks and with the support of Norwegian export credit entities. The credit facility will help us fund construction of Pacific Sharav and Pacific Meltem.

As I have said about our improved credit profile, our strong relationships with federal investment and commercial banks and the credibility we have built with (Inaudible) and export credit Norwich, we were able to incorporate several attractive features into the facility.

This includes six year financing with a 12 year amortization profile, an estimated all in swap interest cost in the low 5%, no restricted cash or debt for this accounts, 72% loan to value, pre-delivery financing and full flexibility to move the cash generated by these two rigs throughout our corporate structure.

This cost effective and relatively flexible financing facility completes the funding for the construction costs of our 47 rigs and significantly strengthens our capital structure. The signing of this new facility is one more significant milestone for our company and one more promise we have kept to our investors in terms of prudent financing, sufficiently in advance of our liquidity requirements.

During the fourth quarter we invested $88 million in the construction of the fleet. At the end of the year we had approximately $1.5 billion in remaining capital expenditures for the completion of the Pacific Khamsin, Pacific Sharav and Pacific Meltem, of which we expect to pay approximately $1.1 billion in 2013 and the remainder in 2014.

Total expenditures for rig number eight are forecasted at $634 million. We expect to invest $106 million in 2013, of which $26 million were already paid to Samsung in February. We anticipate paying an additional $175 million in 2014 and $353 million in 2015.

For the longer term we intend to fund the remaining $2.1 billion in capital expenditures for the construction of new builds with the unrestricted cash of $606 million at the end of 2012. Our recently signed $1 billion credit facility, $500 million of incremental long term debt that we expect to issue before the March 2015 delivery of our eight drillships and from operating cash flow.

Because of cancellation of the long term debt for rig number eight towards the later part of 2014, its likely that we will decide to address funding for the rigs with remaining 2013 capital expenditures of approximately $80 million by the summer of this year.

We are currently evaluating several debt alternatives to fund this relatively contained amount and planted aside on the best option by the end of the quarter based on market conditions and other considerations.

Turning now to guidance for 2013. We expect revenue efficiency to average between 91% and 94% for the coming year. However, we expect the average revenue efficiency of our fleet to fluctuate from quarter-to-quarter and the efficiency of the individual rigs to vary from one another within the quarters. In fact our efficiency guidance is more applicable to our fleet as a whole than to individual rigs. Also our estimates include an assumption for the expected start-up of the Pacific Khamsin in mid-fourth quarter of 2013.

In using our guidance, its essential to realize the certain planned maintenance activities that have an impact on operational uptime and operating expenses may affect some quarters more than others for individual rigs or even for our fleet as a whole.

For example, we expect to deliver revenue efficiency for the first quarter at the bottom of our full year revenue efficiency guidance range, primarily as a result of planned unpaid maintenance performed on Pacific Scirocco in January and February, which was timed to align with our customers well construction plans.

We also expect to perform certain activity with the Pacific Santa Ana during the first quarter, for which the contract species our reduced rate. Further more, I think it’s worth being explicit that our first quarter efficiency guidance in the range of 91% translates into 32 days of paid downtime across the fleet. These dates are inclusive of the 13-downtime dates for the Scirocco, already reported on our January fleet status report.

The main item that effects our efficient expectations for the full year 2013 as compared to 2012 is the completion of the shakedown period for our currently operating rigs. Nonetheless, our practice is to forecast revenue efficiency at expected average rates, based on the historical industry experience and our own track record to-date.

I would like to caution our investors that the average rate experienced during the fourth quarter of last year by the rigs that have already completed their shakedown period, were several points higher than the longer term average we use in our forward guidance.

In addition, given the terms of ownness to our contract and our experience to-date, we expect that rig to deliver 2 percentage points lower revenue efficiency than our other rigs on comparable operational uptime.

Rig operating expenses on a per day basis for the year 2013 will benefit as compared to the full year 2012, from the completion of rig shakedown for our four currently operating rigs. However, versus the normalized fourth quarter, we expect our full year 2013 daily rig operating expenses to increase by approximately 5%. A significant portion of this increase is attributable to annual compensation increases for our operations personnel.

For the full year 2013 we expect net rig related operating expenses to range between $182,000 and $187,000 per day. Rig operating expenses per day for the first quarter of 2013 will be affected by the eight fewer rig dates in the quarter and by the timing of planned maintenance projects for the Pacific Scirocco and the Pacific Bora, scheduled early in the year to align with the customers well construction plans. We expect our first quarter 2013 rig operating expenses to reflect the top of our annual guidance range.

We expect our 2013 overhead costs, including SG&A as well as shore-based and other support costs to increase when compared to 2012, as a result of strengthening our organization to support an eight rig fleet, as well as the normal annual salary increases.

We will anticipate shore based and other support costs per rig to range between $18,000 and $20,000 per day during 2013. We expect our selling, general and administrative expenses to total between $55 million and $57 million for 2013.

Income tax expanse for the full year 2013 is anticipated to range between 3% and 4.5% of total contract drilling revenue. However we expect significant movement in this metric quarter-to-quarter, depending on the mix of revenues between geographical locations and the timing of cost in our various operating entities, some of which are located in non-tax jurisdictions or effectively taxed on a cost plus basis.

In addition, duet to the renewable status of our fleet and the significant result of certain items that affect our accounting, we will continue to update our investor tool kit each quarter. Schedules of expected amortization of deferred revenue, amortization of deferred mobilization expenses, depreciation, capital expenditures and interest expense for the 15 credit facilities and bonds were provided in conjunction with our results press release yesterday evening.

Keep in mind that this information is only specified for the existing fleet and for the existing financing facilities and its intended as a tool to help our investors prepare their own projection.

For instance 2013 and 2014 inertest expense only take into account the debt facilities currently in place and do not intend to reflect our total forecast cost for those years. As additional debt is put in place, the interest for the incremental debt will be added to the amount presented on the schedules on our tool kit. These schedules are posted on our website www.pacificdrilling.com in the Investor Relations section.

As a final comment, we will file our 2012 financial results with the U.S. Securities and Exchange Commission before the end of this week. Fiscal year 2012 represented the first year in which we will require to demonstrate compliance with Sarbanes-Oxley and as such we are pleased to report that for 2012 we are in full compliance with Sarbanes-Oxley and all of its requirements.

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

Amy Roddy

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

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). We’ll take our first question from Dave Wilson with Howard Weil.

Dave Wilson - Howard Weil

Good morning Chris, William and Amy. Chris, currently I know you guys have a stated goal of 12 rigs and you have a fleet of eight standardized jack-ups, sorry drillships. Are there any thoughts of doing something with the next four; kind of like a version two of the existing drillships or approximately going down the road of ultra-deepwater semis.

Chris Beckett

As you said, we have pretty similar ships right now and we would like to go to fleet 12. We think that’s the optimal size obviously, but the pace in which we do that is going to be determined by a number of different factors.

We do have underway currently a method internally to determine whether the next four should be an evolution of our current design or something more revolutionary. I think it’s unlikely that we will move to deep-water semi-submersible. As a tool we think the drillship is a more fundamentally more flexible tool and are more attractive to our clients, and we are certainly not looking to move into the jack-up space or out of the ultra deepwater.

So I would expect it to be a drillship, but we are certainly evaluating whether any of the new technologies that are out there, that make sense to change the base design, given that we have some of our own specific requirements that we want to make sure we build in, like that ability to operate at the moment when required.

Dave Wilson - Howard Weil

Okay, all right, and then another question. There has not seemed to be any radical changes in the structure of contracts within the industry, regards to downtime particularly around the BOP and subsea systems and if the contractual changes have been slow in coming and a bit vague, can you updated us on anything different that you guys are seeing in your contracts or doing in your contacts, since you tried to implement some of the changes regarding the contacts from the BOP.

Chris Beckett

Yes, I think you will continue to see the impact of contracts that were not written, to take into account the new expectations on the back of new regulations and the development banks, but also I think on the back of heightened expectations across the industry.

Certainly the contacts that we have in place, the older contracts we have place, the Bora and Scirocco and so on do not reflect the level of maintenance, and in particular testing that we now perform in our BOP’s when we’ve done maintenance on them, and so we are not fully compensated for that maintenance time on those contracts.

On the newer contracts that we have signed, we have modified the way in which we have compensated for subsea maintenance. Historically that was done on a sort of monthly allowance basis, but frankly when it takes you four or five days to recover a BOP to surface and then four to five days to do work and four of five days to run it again, then getting a day in the month doesn’t help you very much.

So we are trying to steer our contracts towards more of an allowance that accrues over time and gives us sufficient time to perform all the necessary maintenance and testing on surface after the BOP performed its function satisfactorily for an extend timeframe, whether that be 90 days or 120 days. It depends much on the client and to some extent that drilling program, exactly what they are willing to do.

But we certainly haven’t been able to achieve that on a couple of the most recent contracts and that’s our goal going forward. I know we are not alone in the industry in trying to do that and I think that’s going to become a more common structure going forward.

But for the next couple of years, while we are still working on contracts signed before the full implications and new regulations were recognized, we are going to continue to see some incremental un-paid downtime when we are doing that more extensive maintenance.

Dave Wilson - Howard Weil

Okay, great, got it. And then one final one if could sneak one in here, more of a kind of industry type question. I know a couple of your rigs are not drilling in ultra-deepwater depths. Basically ultra-deepwater rigs are drilling in mid-water and deep-water depths. Do you have an idea of how many ultra deepwater rigs within the industry are doing the same thing, drilling up to shallow depts. And as a follow on, how do you think the market should interpret this.

Chris Beckett

Yes, I would say, that (a) it’s geographically dependent. In the Gulf of Mexico, I think most of the ultra deepwater rigs are operating in relative deep water. But I think over the years, the last time heard of that sort of normalized analysis adjusted, the average water depth for ultra-deepwater rigs was actually somewhere around 6,000 to 6,500 feet, which is obviously well below their absolute capabilities.

In certain geographies, we see clients using our drillships in substantially shallow water than that. In the case of Scirocco and the Bora, they are working between 2,500 and 4,500 feet of water. And really they are being chosen by clients, by preference in those areas because of their ability to operate in those remote locations with usually logistical support and their ability to handle very complex completion equipment and complex well construction programs, and still deliver enhanced efficiency versus some of the older smaller rigs that might be an alternative there.

I think that that will continue to be the case in geographies like Nigeria and a lot of West Africa where the water depth requirements are not really the governing factor, but on the other efficiencies that are taken into account that rigs bring to the table are more than offsetting the incremental cost of use them. I cant give you a percentage of how many rigs are being used in that environment, but in our fleet clearly half of our operational fleet is working in those shallow water though.

Dave Wilson - Howard Weil

Got it. Great, thanks for answering my questions. I’ll turn it back over to Chris thanks.

Chris Beckett

Thanks Dave.

Operator

We’ll go next to Ian Macpherson with Simmons. Caller, please check your mute function. Your line is open Ian Macpherson.

Hearing no response, we will move on to Todd Scholl with Clarkson Capital Markets.

Todd Scholl - Clarkson Capital Markets

Good morning guys.

Chris Beckett

Good morning.

Todd Scholl - Clarkson Capital Markets

Hey, I just had a quick question on your SG&A guidance. It looks like you represent about a 20% to 25% year-over-year increase and I was just curious, how much of that is related to supporting the Khamsin and Scirocco and how much of it is just inflationary. And then also, is this the amount we should expect kind of on a go-forward basis to support an eight rig fleet or as additional rigs coming to service, is that SG&A number going to continue to refract higher.

William Restrepo

Todd, that’s a good question. The numbers for next year, we have already increased over the year a structure, a date, so obviously what we are seeing next year is partially the full year impact of the current situation. We are also seeing 5% roughly on the average dollar increases and the remainder, yes, its part of accommodating or structuring within organizations that meet the requirements of an eight-rig fleet.

Part of that fleet is already being constructed and thus require the sources to supervise, market the fleet, finance the fleet and so forth; the incremental new builds that are going to be coming in the next couple of years.

And then a final, I think obviously this is an important year for us. We are doubling the fleet size, so that’s why you see a bit of increase in R&D increase, and increase in SG&A that you mentioned. Obviously in the future, the pace of growth is not going to be quite as accelerated and we want to see SG&A growing at those rates.

Todd Scholl - Clarkson Capital Markets

Look, I’m happy what we are thinking is that as you realized this increase and afterwards future rigs, basically there will be some synergies there and the phase would slow. Just one last question if I might. Can you give us a little bit more granular detail on when the Khamsin is actually going to start in the fourth quarter? Should we expect and should we model that for early or late or can you kind of give us a little bit better color there?

Chris Beckett

Yes Todd, it’s Chris. The downtime we are anticipating right now to start earning revenue, somewhere right in the middle of the quarter, so sometime in November. The exact data, obviously it’s a little too far out to give you accurate positions on to that field of magnitude.

Well, something I wanted to make to, to add to Williams statement, I mean he’s absolutely right. We see an opportunity where we have to increase the SG&A and the overheard support structures for the organization well in advance of the rig we’re riding, because if you think about it in practical terms today, we are already recruiting. So all of the rigs that will be in fleet, we are already marketing for all eight of the rigs, we are already overseeing construction there for having technical involvement in all of them.

We do not anticipate SG&A to grow at anything like the same pace in future years, assuming that we stated an eight rig fleet, and so the point is that we are investing in that future growth in advance to make sure that when those rigs come out, they are adequately and properly staffed and the people are trained and that we can get them up and running the way we intend to.

Todd Scholl - Clarkson Capital Markets

Great, thanks for that clarification, and I’ll turn it back.

Operator

We’ll go next to Andreas Stubsrud with Pareto.

Andreas Stubsrud – Pareto

Yes, hello. Good morning.

Chris Beckett

Good morning Andreas.

Andreas Stubsrud – Pareto

I just had a question on the cost escalation in your contract. How do you feel you are protected based on the guidance you are giving us? We see from some other fleet repots that day rates specifically in the fleet status report are jumping up when you have some cost inflation. We are not seeing that in your report. Will we see that in the future?

William Restrepo

We are not going to give specific guidance on that, because its based, our escalation costs are based on the indices that we don’t feel at this point we are capable of forecasting. But what we do estimate and what we assume in our own model Andreas is that the different rigs have differ contracts and for instance the Nigerian rig, some costs are recovered. For instance you can see that the Bora and Scirocco have already recovered about $5,000 per day worth of costs.

The Scirocco by the end of the year, if the option is removed, will recover another $11,000 for the worth of cost increases, because the options are prized with an $11,000 increase, and also the Nigerian rigs.

Brazil and the Gulf of Mexico, Petrobras and Sharav do have specific escalation costs. In Brazil we will recover about 60% worth of those cost increases over the remaining life of the contact. The indices are there, but of course the indices are more general and don’t always address the cost increases in their specific industry.

But sometime they are probably, it’s about 75% increases. As you can see the starting rate for this entire month was $457,000, $500,000 per day; its currently $489,000 per day. So this in turn is nicely recovering the cost increases and we will continue to do so. The next cost adjustments for the Santa Ana will be in May of this year. As for the Khamsin, the contact has even higher cost recoveries. We think we have a recovery in access of 90% of cost escalation over the life of that two-year contact.

So to answer your question yes, that guidance thus includes some increase in costs and a good portion of that will be recovered over the coming years.

Chris Beckett

Yes Andreas, just quickly I would add to that, there are two specific cost increases that are included in our guidance, for incremental personal on both the Pacific Bora and the Pacific Santa Ana, which are explicitly, the costs of which are explicitly covered by the clients.

You should have noticed an increase in the day-rate on the Pacific Santa Ana on our last week’s status report. That was a direct result of offsetting incremental cost or incremental personnel. On Pacific Bora it’s treated as a reimbursable, so you won’t see it in the day-rate, but you will see it in the revenues.

Andreas Stubsrud – Pareto

Okay, great, and to you well then we have, I guess we have discussed a little bit slide 23 on your last investor presentation, where you illustrate your excess operating cash flow in the future. That is of course including the guidance you’re giving today, right.

William Restrepo

Yes.

Andreas Stubsrud – Pareto

And the last question is related to Scirocco, so I just didn’t get all your comments in the beginning and when did they have to declare the option, the option that starts in 2014.

Chris Beckett

So the official dates for that option is April 6 I believe that they have to declare it by for the next year. And then obviously there was a two-year option that for which they have another year to declare. We are having some conversations about the best way to handle that and whether they in fact may want to extend the rig deal in those three years. So watch the spaces.

Andreas Stubsrud – Pareto

Okay, great. Thank you.

Chris Beckett

Thank you Andreas.

Operator

And we’ll go next to Anders Bergland with Platou Markets.

Anders Bergland - Platou Markets

Yes, good morning gentlemen. Just a quick question on the credit facilities that you received lately. How much can be drown down to that before delivery of the vessels?

Chris Beckett

Well, the facility provides for free delivery based on a ratio. For every $28 that we have invested already or paid for in those drillships from our own money, we can draw $72 on the facility. We estimate that by year-end we will have drawn about $700 million from the facility to fund those two vessels, and the remaining $300 million will be drawn in the first half of 2014.

Anders Bergland - Platou Markets

Okay and one question on the shore based cost guidance. How much of those is 18,000 to 20,000 from last quarter.

Chris Beckett

From last quarter its about $5,000 per day. Now, the increase of that particular category is pretty disciplined, because we are strengthening and our operations in Nigeria. We are going to have three rigs operating there at some point, late this year and early next year, so we do have to put more resources on the ground in that particular location.

The drill in the Gulf of Mexico is pretty stable, except for the fact that obviously the salary increases that you see throughout the industry are going to affect those costs that are mainly salaries. So you will see some increase based on that.

Anders Bergland - Platou Markets

Okay, and will this be reduced again at the point where you have all the units in place and operations are going on or is it this is the level that they expect going forward.

William Restrepo

Well, like we have the Khamsin fully operational, we used to look at this like a fixed dollar amount and as we put in the fifth rig, if we divide the number of days, mechanically you will see a per day reduction, but that doesn’t mean the cost will go down, the cost will be the same and will tend to grow by 5% each year. And if we add more rigs say in other operating locations, you will see an increase again temporarily until the revenue comes in.

Chris Beckett

But just because we don’t charge that overhead local support cost structure to the rig until its actually operating, so you will see a core rig reduction, because this is going to be slightly of a more operating rig with the new rigs come in, but its not an absolute dollar cost reduction.

Anders Bergland - Platou Markets

Okay, thank you very much.

Chris Beckett

Thank you.

Operator

We’ll take our next question from Matt Beeby with Williams Financial.

Matt Beeby - Williams Financial Group

Thanks. Good morning everybody.

Chris Beckett

Good morning Matt.

Matt Beeby - Williams Financial Group

Chris, I want to talk about the revenue efficiency. I think William you offered some good guidance for 1Q and it sounds like the Khamsin stated in 4Q. Those two quarters might be little lower than average, is that fair to say? And then is there anything, maybe in the middle quarters of the year that you can identify right now that might lead to kind of abnormality in terms of the rig efficiency for 2Q and 3Q?

Chris Beckett

Matt, I think you are absolutely right, that’s the message. The Q1 we have, obviously the maintenance on Scirocco that you’ve already seen in the fleet status report that will impact Q1. We don’t see anything abnormal in Q2 or Q3 at this point. Q4 we expect the fully operating rigs to deliver, to leverage utilizations, but we will be introducing a new rig and it will obviously go through the usual start up.

We said in the past that we expect about a 90% utilization for the first six months of operation of any rig on average. I think in reality and this is going to be a little clear on Khamsin, because you’re only going to get a month or two of operations into the year. It’s going to be a little lower than that. Its likely to be 80%, 85% in the first month, so that maybe all you see. But we expect that to balance out over the six-month period to average that 90% that we target. But it does mean that it drags things down a little bit until December.

Matt Beeby - Williams Financial Group

Okay, that’s helpful. And then can you talk; does your operating cost guidance reflect any change in the GAAP between the regions, specifically West Africa and the U.S. Gulf. Does that GAAP in operating cost on a daily basis pretty much stay the same in expectations for that into 2013?

Chris Beckett

Not explicitly, but I will tell you that I think that we are extremely pleased with the way in which Brazil is now performing and in fact we are bring in the Brazilian operations at a lower cost than we’d anticipate we’ll be able to, so that’s clearly a position.

That really brings Brazil down into line with Nigeria in terms of the cost and so you might see, Nigeria is probably a little higher than we had originally anticipated, in part because of the extra security that we put in place given the challenge in this today. So that’s kind of balancing out and then obviously the Gulf of Mexico is a low operating cost environment than the other three.

Matt Beeby - Williams Financial Group

Got you, and then one more quick one if I could. I sounds like the G&A is going to be fairly consistently moving higher over the course of the year, is that the best way to look at that versus a lumpy quarter somewhere in there.

Chris Beckett

Yes, I mean its recognition that over the course of the next year. As William said, we’ve added some resources to the organization already and so the starting point is a little higher for the year if you like. We expect to continue to add some resources through the year as we ramp up to be fully ready for the eight-rig fleet, and so it should be a sort of steady increase. We are not expecting anything specific or lumpy to happen through the year at this point.

Matt Beeby - Williams Financial Group

All right, great. Thanks.

Operator

And we’ll go next to Chris Kallos (ph) with Net Capital.

Chris Kallos (ph) - Net Capital

Hi, just a very quick question. As more and more of your rigs comes on line in the next year or two, given internal or state dividend policy that you’ll look to implement once your growth build out has fully been executed.

Chris Beckett

We haven’t made an explicit statement about dividend policy going forward. What we have said is that as we transition from growth to operations that obviously we expect to generate a significant amount of free cash flow and that we intent to return that to shareholders in the most efficient way possible.

That most likely would include dividend at some point in time, but this is probably something we are talking about for a 2015 event as opposed to prior to that. I mean obviously we are focused on growing the fleet and investing in the access at this point. But certainly dividends are under discussion already with the board and there is an expiation that that will happen at a point in the future.

Chris Kallos (ph) - Net Capital

Great, thanks.

Operator

We’ll go next to Darren Gacicia with Guggenheim Partners.

Darren Gacicia - Guggenheim Partners

Hey, good morning. I wanted to ask, it seems like the market is scared on this space because they are worried that sort of day rates are flat and then costs are increasing. What you seem to be saying is that maybe some of the focus of market power is pushing towards kind of getting more subsea downtime covered. Do you think that that flips back towards more pressure, up-word pressure at day rates at some point in the game? Kind of what do you see is the status of the market on the floater side?

Chris Beckett

Yes, I mean obviously we don’t really hold the deck front, so I won’t make any comments on that, but on the fleet side and in particular the ultra deepwater. We’ve obviously seen a significant increase in the size of the fleet over the course of the last few years and there are substantial new builds coming down the road, but we’ve seen demand grow more than fast enough to keep up and stay ahead of that. So we still a market that’s fundamentally under supplied for the next couple of years at least.

That puts a, gives a fairly healthy market from the drilling contractor standpoint in terms of our ability to get attractive rates. I think rates that you’ve seen in the markets recently and we would expect you to continue to see offer extremely good returns. But I think a lot of the contractors, and certainly we are focused at the moment, I’m trying to make sure that we get contract forms that are able to capture as much of that revenue as we can.

And so I think one of the reasons if you see a stagnation of rates, if you can call it at that when you know that 600,000 is a explicit tradeoff between not only the traditional tradeoff between term and rate, but also a tradeoff between rate and contract provisions and we would expect that tradeoff to continue for sometime as we try to address the new realties of new regulations and so on.

I don’t see a lot of rate increase pressure in the near future, but I also don’t see any rate decrease pressure. So I think we are in a – maybe the rates are at a plateau that we are quite comfortable with.

Darren Gacicia - Guggenheim Partners

So is it unfair to say that you think from an operating line standpoint, marginal economics are improving even though kind of the headline numbers people are seeing may have flattened, but given the fact that you are getting (a) cost escalation causes are probably offsetting a lot of the, even your 5% increase.

But at the same time you are probably getting a higher net utilization, because of what you will be able to put through on the subsea stackdown time. I mean is that – would you say that the operating line is kind of not getting better, because the battle ground is more on those latter cost oriented issues.

Chris Beckett

Yes, I mean we are obviously looking to put explicit numbers, but in general, yes. I think that the focus from the drill is on trying to get better contract terms. This is clearly about maximizing revenue efficiency and maximizing EBITDA at the end of the day.

To give you sort of a flavor for what that means. If we spend 15 days doing maintenance on a stack, which historically would have been substantially less time that than, now we are spending two or three times as much time actually performing maintenance and running through a lot of systems that historically we may not always have maintained it of the same level frequency and we are spending two to three times as much time testing.

That could very easily have a 10-day impact on us, and 10 days, that’s 3% over the course of the year. If we get the fully compensated instead on not compensated then that’s a 3% revenue efficiency improvement over the year. That’s the scale of this little thing that we are talking about.

Darren Gacicia - Guggenheim Partners

Now that’s something to do specific or say, like un-hedged here, because I think what the raw edge is you can’t have cost escalation causes, so the options are kind of set up to help negate that. Is that something that the options can actually include? Some help in that area as well, on the downtime for BOP’s?

Chris Beckett

Yes, I probably wouldn’t call it a rule so much just a requirement of the Nigerian National Company, where we are partners on all of these contacts in Nigeria, but they don’t accept cost escalation provisions.

The auction form basically is a predetermined rate increase to extend the exact same contract. It’s very hared to change contact terms of those contracts once they’ve been signed. So I think what you will see is those contract improvement comes in as new contracts are excruciated rather than exercise of auctions of the existing contracts.

Darren Gacicia - Guggenheim Partners

Got you and just to double, to make sure I understood some of your earlier comments. If you are getting one day a month now, like kind of in the legacy contact structures if you will. There is one you are talking about an accrual, which maybe doesn’t get you back to kind of a full 3% using your kind of theoretic example that you are just talked about. But what are the elements that are now kind of in there to get you closer to recovering that full 3%.

Chris Beckett

Yes, so let me try and expand it a bit; and again, its different by contract, but its not basic to get one day of allowance of time per month, but that typically doesn’t accrue. So you use in the month or you loose it. So at any point in time when you have one these maintenance events, you may get one day out of the 10 days it takes.

What I think the industry is moving toward is the concept of no allowance on a monthly basis, but a minimum subsea period, during which the BOP has to perform its operations as intended, and then an allowance to do the maintenance on a periodic basis, whether its every four month or every five month and it depends by client, during which time you are compensated for doing the work. So the delta between those circumstances is one day under the old model and full coverage under the new model, which maybe an incremental modification, yes.

Darren Gacicia - Guggenheim Partners

So what’s the ballpark of the minimal period that you have to be up and running. Because I understand in essence you are telling me you kind of get two, three stoppages under the new possible contacting and under one methodology. The other one you get a minimum date where you have to be up. What’s the target zone of that minimum period.

Chris Beckett

Well, I think maybe we can do this in detail with you afterwards, but I would say that the political historic model didn’t really give you any allowance beyond whatever the in-month allowance is, which is definitely just one day.

The new model allows for periodic recovery on work and it really does depend on the client, the contract, what is that we are working in on the nature of the specific asset. So it varies from minimum content of how many people do represent the 90 days, so it maybe a 180 days and it may even involve some level of – different level of compensations depending on how long its been done.

Darren Gacicia - Guggenheim Partners

Got you. Hey, that’s great color, thanks a lot.

Chris Beckett

Thanks Darren.

Operator

We’ll take our last question from David Sparks (ph) with BB&T Capital Management.

David Sparks (ph) - BB&T Capital Management

Hey guys, how are you doing?

Chris Beckett

Good David.

David Sparks (ph) - BB&T Capital Management

Just, I wanted to know first the dividend cost and all that differently. I know guys have $80 million sold by the summer. In the original facilities that you guys have done back when the market was a lot worse, you didn’t have cash flow a little more ownness. We’ve talked about this before, but is there the opportunity to refinance those, free up some cash and then potentially address divined this year.

Chris Beckett

Yes, there is the potential for that. I mean the specific need we have for this year as I mentioned in my comments is fairly limited and its something that I could do or the company could do in many different ways, evolving credit facilities, we could issue a medium term paper on secured. I mean it’s a lot of things we could do to meet this specific need for 2013.

However, you are right. The facility that we have if refinanced could inject additional liquidity to free up trough cash and eliminate the future amortization pain, which is about $220 million per year.

Now it is premature right now to discuss that, because we are still evaluating what we will do and it’s a pretty broad portfolio of alternatives. So we expect to be done with our evaluation within the next could of weeks and take a decision by viewing it as a quarter on how we’ll move going forward.

Chris Beckett

But David, I think its fair to say that that’s certainly in consideration.

David Sparks (ph) - BB&T Capital Management

Okay, great. Thanks much.

Operator

That concludes today’s question-and-answer session. Ms. Roddy, at this time I will turn the conference back to you for any additional or closing remarks.

Amy Roddy

Thank you everyone for participating in Pacific Drilling’s fourth quarter and full year 2012 results conference call. William and I will be available for questions throughout the day. Thank you again.

Operator

This does conclude today’s conference. Thank you for your participation.

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