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Good day, everyone, and welcome to Valaris plc's Second Quarter 2019 Financial Results Conference Call. All participants will be in a listen-only mode. [Operator Instructions]
Please note, today's event is being recorded. And at this time, I would like to turn the conference call over to Mr. Nick Georgas, Senior Director of Investor Relations, who will moderate the call. Please go ahead, sir.
Welcome everyone to the Valaris second quarter 2019 conference call. With me today are President and CEO, Tom Burke; Executive Vice President and CFO, Jon Bakst; and other members of our executive management team. We issued a press release, which is available on our Web site at valaris.com.
Any comments we make today about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially from our expectations. Please refer to our press release and SEC filings on our Web site that define forward-looking statements and list risk factors and other events that could impact future results. Also, please note that the company undertakes no duty to update forward-looking statements.
During this call, we will refer to GAAP and non-GAAP financial measures. Please see the press release on our Web site for additional information and required reconciliations. As a reminder, we issued our most recent Fleet Status Report, which provides details on contracts across our rig fleet on July 25. An updated investor presentation is also available on our Web site.
Now let me turn the call over to Tom Burke, President and CEO.
Thanks, Nick, and good morning everyone. Following our name change early this week, Jon and I are very pleased to be speaking to you today on our first quarterly conference call at Valaris. During our conference call in May, I laid out four short-term priorities for the company. Integration and synergy capture, delivering value from ARO drilling, balance sheet and liquidity, and lastly fleet management which encompasses our contracting strategy.
In a moment, I will review our progress on each of these priorities. But first I will briefly discuss our second quarter performance. The second quarter of 2019 was our first quarter as a combined company following the close of our merger in April. In terms of our financial results, we reported adjusted EBITDA of $59 million for the quarter better than the outlook we provided in our first quarter conference call. While these results exceeded expectation, some of this outperformance was due to the timing of contract drilling expenses that were originally anticipated to occur in the second quarter and are now expected to occur in the third quarter of 2019. Jon will discuss our second quarter results and third quarter outlook in more detail later in the call.
Our financial results benefited from strong operational performance with 98% uptime across our floaters and 99% uptime across our jackup. Additionally through the first-half of 2019, our recordable incident rate was nearly 20% better than the industry average as measured by the International Association of Drilling Contractors. These results are a testament to the continued focus on safety and efficiency from our offshore crews and onshore personnel.
I want to commend our employees for their professionalism and unwavering commitment over the past several months as they have worked tirelessly to work to keep our rigs up and running and avoid distractions that often arise during a merger. I also want to acknowledge everyone's hard work on the integration so that we would achieve our targeted synergies and deliver on our commitments to create value from the merger.
On this note, I will now update you on the first of our priorities. Integration and synergy capture, we recently reached the 100 day milestone following the merger closing in April. And I am pleased to report that the integration is moving forward as planned. We have a detailed and robust integration plan. And to date we have completed more than half of all our integration activities including a major ERP conversion, the consolidation of offices and warehouses in Aberdeen and Houston, and approximately 65% of our staffing reductions.
We are confident that we will achieve targeted synergies of $165 million by the end of next year and are continuing to look for opportunities to deliver additional synergies from the combination. Jon will provide additional details on the synergy realization in his commentary. In conjunction with these integration efforts and after thoughtful consideration review, we decided that renaming the company was the best way forward. This decision was not taken lightly.
Our predecessor companies have solid history that spans many years. And we are extremely proud of what these organizations accomplished over time. But we believe that a new name is important part of our evolution. While renaming a company is an obvious sign of change, it is a part of more broad transition as we move forward as a larger, more diverse organization. We will continue to provide updates on this transition in the coming quarters including the status of our integration efforts and synergy capture.
Second priority is ARO drilling, our 50:50 venture with Saudi Aramco. As a reminder, this is a joint venture to own and operate jackups in partnership with the largest customer for jackup in the world, which also secures backlog for a portion of our jackup fleet for leasing structure and provides strong organic growth through ARO drillings new build program. Jon will comment on ARO drillings financial results in a moment.
But from an operational perspective, the ARO drilling team delivered safe and efficient operations in the second quarter with excellent operational uptime and safety performance. ARO drilling from leased fleet will expand as the best brands, a Modern Strata GT [ph] Super 116E is in the process of commencing its maiden contract, and the Earnest Dees, another Super 116E rig is also expected to join the active fleet later this quarter. The addition of these two jackups will bring the number of least rigs to ARO drilling to nine, which will contribute to our 50% interest in ARO drillings net earnings and increase the bareboat charter fees recognized as revenue by Valaris.
On our prior conference call, we mentioned that the first two ARO drilling new built rigs were expected to be ordered in May. However, this has not occurred as ARO drilling continues to have discussions with the shipyard related to certain aspects of read specifications and construction costs. While the older for these new builds has pushed to the right, we firmly believe that it is most important for ARO drilling to reach appropriate terms with the shipyard.
We respect to our priority of balance sheet management; we continue to practically manage our capital structure to most effectively execute on our strategic priorities and maximize value for shareholders. As we've stated previously, this entails managing our debt maturities and our cost of capital and reducing total debt. After a thorough evaluation of the capital structure and market conditions, we recently launched a tender to repurchase debt at a meaningful discount. We completed the tender in July. We repurchased $952 million of senior nodes at a 24% discount. Interest payments for these notes were $52 million per year. And we realize $228 million of principal savings as a result of the transaction.
Our current capital structure provides the flexibility to further manage the balance sheet, including adding guaranteed or secured debt. Given overall market conditions and our near-term debt maturities, we view our revolving credit facility, which gives us access to approximately $1.7 billion of funding through the third quarter of 2022 as an important source of liquidity. Our last priority to detail is our approach to fleet's management and contracting, which are influenced by overall market conditions.
With respect to the market, as you know, we are navigating a protracted offshore sector recovery then include a significant amount of uncertainty in its timing and its magnitude. Macro factors are largely supportive of growing demand for hydrocarbons with the global economy continuing to expand, although this growth is occurring at a slower pace today than in recent years.
In addition, industry conditions are fairly positive with commodity prices remaining at levels that should be conducive for new offshore project investments. We saw evidence of this in the second quarter as the amount of offshore reserves that were proved through Final Investment Decisions or FIDs, with the highest in any quarter over the last six years according to Bernstein Research.
However, while this is a good sign for future demand for offshore drilling rigs, we know that the lead time between FID and an offshore drilling rig beginning work on a project is measured in years rather than months, particularly for deepwater projects. Even supportive commodity prices, the number of new floater contracts increased approximately 50% join the first-half of 2019 as compared to the same period in 2018, helping to push marketing utilization for the global floated deep [ph] up to roughly 80%.
However, despite spot utilization increasing, we still have not seen deepwater contract terms lengthen with a six-month average duration for new contracts and extensions in the first-half of 2019, which is in line with contract length over the prior period. Since Floater contract lengths have remained relatively short-term in duration, day rates for new Floater contracts continue to be competitive as offshore drillers they keep active rigs working.
Additionally, the number of tenders for future Floater program has been relatively flat for the past several months, and there remains a limited number of opportunities with meaningful term that are expected to begin for year-end 2020. With Floater contract duration short and a number of future opportunities flat. Meaningful recovery in flow to day rates maybe further out than many in the markets are expecting. What is positive that low to day rates have moved off recent lows to levels that are now generating positive cash margins. A number of new opportunities and the corresponding day rates have not progressed at the pace we would have expected six months ago. As a result, our outlook forecloses the remainder of this year and the first-half of 2020 have softened since we began the year. Considering these conditions, we're taking additional steps to manage our flow to fleet and reduce cash outlays.
First, we mobilize the row in reliance from U.S. Gulf to the Canary Islands, where the rig will be warm stacked alongside ENSCO DS-7 and ENSCO DS-6, providing a significant reduction in daily costs. Second, we are in discussions with the shipyard to delay the delivery of new build drill ships ENSCO DS-13 and ENSCO DS-14. We expect to delays these rigs beyond their currently scheduled delivery date later this year and next year, we have the option to convert the final milestone payments to promissory notes that are due at year end 2022.
In terms of our floater contracting strategy, we will continue to take a portfolio approach where we aim to increase near time utilization for certain assets and hold additional capacity off the market until we see day rates advance to levels that justify additional flow to supply. For example, we prioritize contracting the row and relentless which is scheduled to come off contract in the fourth quarter and recently won a short term job with options that could extend the rigs contract period into 2020, while electing to warm stack Rowan reliance.
For our three vintage floating rigs that are older than 15 years of age, all of which are scheduled to complete contracts in the next 9 months, we will assess the costs required to keep each rig competitive in the global fleet. And if we do see adequate returns on required invested capital, we will move to divest the rigs from our fleet.
Moving to the jackup market; while global market of utilization is similar to floaters at approximately 80%, the jackup recovery seems further along. New jackup contracts signed during the first-half of 2019 was 25% percent higher than the first 6 months of 2018. Contract lengths of new fixtures have increased by 2 months on the average over the same period to 14 months. While a two month increase in contract length may seem minor on the face of it, this coupled with the pickup in contracting activity has helped to drive a broad based over a modest increase in pricing for jackup rigs. This is particularly evident for jackup's capable of working in the most challenging environment, where spot utilization is above 95%. And as a result, we've seen day rates moving higher for these rigs.
Valaris has a large fleet that can service this segment of the market with 14 units; 7 ultra harsh and 7 harsh environments rigs. Most of these assets are in the North Sea where we have had some recent contracting success. We've added two years of term to Ensco-120, a harsh environment jackup. And this rig is now contracted until the middle of 2022. We also won a two well contract for the Ensco-122, also a harsh environment jackup that will keep the rigs utilized for most of 2020, and a six month extension for the Rowan 5, an ultra-harsh environment jackup. These contracts have options beyond their firm term that could lead to substantial additional contracted days. I would note that these options are either priced at meaningfully higher rates or un-priced, and indicates of the improving market dynamics.
We've seen improvements across other major shallow water markets and utilization of modern benign environment asset is approximately 80%. With 25 of these modern benign units in our fleet, 14 heavy-duty jackups and 11 standard duty jackups, Valaris has one of the leading fleets of modern benign environment jackups. Our global footprint enables us to service a wide range of customer's shallow water requirements around the world as evidenced by our recent contracting success in West Africa, the Middle East, Australia and Central America.
With respect to our jackup contracting strategy, all of our marketed jackups are either currently under contract or scheduled to begin contracts. So our focus is on bridging any gaps between contracts for these rigs. We're also monitoring pricing and other market conditions and we will carefully evaluate reactivating jackups to meet cuts of demands when day rates justify cost to return these rigs to our active fleet.
In closing, while certain aspects of the market recovery maybe progressing slower than anticipated, we will continue to focus on key areas within our control; namely: staying highly involved with average drilling development, winning new contracts for our rigs with availability, driving high levels of operation uptime for our contracted fleet, managing our balance sheets and delivering our targeted merger synergies. By accomplishing this, we will best position the company to weather the cyclical nature of our industry, participate in the unfolding offshore market recovery and maximize value for our shareholders.
I'll now turn the call over to Jon.
Thanks, Tom, and good morning, everyone. In my prepared remarks today, I'll cover our second quarter 2019 financial results, our outlook for third quarter 2019, CapEx guidance for the remainder of the year and provide some high level commentary on ARO drilling. I will also spend some time discussing our financial position and capital allocation in light of our recent debt tender. And finally, I'll provide an update on merger synergies and transaction costs.
As a reminder, we closed the merger on April 11. Therefore, the second quarter of 2019 results in our press release reflect legacy and corporations [ph] only for the first 10 days of the quarter and the combined company from April 11 onwards. This is because legacy and ENSCO was the accounting acquirer in the merger.
Additionally, in conjunction with the organizations for large rebranding, you know we've attempted to simplify the categorization and naming with our rig fleet. The jackups fleet is now subdivided into more logical categories in our fleet status report with rig names aligning to those categories. My comments on this call will reflect legacy rig names to ease the transition. However, going forward, the updated rig names will be reflected in our investor material.
Given that second quarter 2019 is our first reporting period as a combined company. My commentary will compare actual results against guidance provided on our prior conference call.
Adjusted EBITDA for the quarter was $59 million compared to guidance of approximately $35 million. This feat was driven by a variety of factors including strong operational performance and disciplined expense management, which I'll review in more detail. However, as Tom mentioned, it'll also reflect the deferral of certain expenses into the third quarter, which will have an adverse impact on that quarter and effectively pull the portion of EBITDA forward into the second quarter.
Starting with the second quarter revenue of $584 million versus guidance of $580 million, the revenue beat is primarily due to higher operational utilization across the fleet and more operating days for the Rowan Ole [ph] and Rowan Viking.
Excluding transaction costs, contractor drilling expense was $489 million. This is approximately $20 million lower than the prior conference call guidance, mainly due to the removal of an expected rig reactivation from our plan, due to the transfer of a drilling contract to an active rig with availability and the deferral of mobilization costs and certain repair and maintenance costs into the third quarter.
Second quarter depreciation expense was $158 million, which was $7 million higher than guidance, primarily due to changes to the fair value of Legacy Rowan assets. As a reminder, the fair value estimates of the assets and liabilities required from Legacy Rowan are preliminary and may change as we finalize those estimates during the one year accounting measurement period.
Excluding transaction costs, general and administrative expenses, $33 million, this is $2 million lower than our second quarter guidance due to disciplined cost management. During the second quarter, we incurred approximately $60 million of merger related transaction costs, which are excluded for the adjusted EBITDA and the adjusted loss per share presented in the press release.
Other income was $597 million in the second quarter, driven by $713 million bargain purchase gain related to the merger transaction and partially offset by $118 million of net interest expense and $9 million of transition services fees and other related costs. Finally, tax expense was $33 million, in line with the guidance we provided on our prior conference call.
Now moving to our third quarter 2019 outlook, we are expecting to see a meaningful drop off in EBITDA due to a variety of factors including contract roll loss and contracted time between contracts for repair and maintenance, mobilizations and some seasonal gaps in utilization. We expect total revenues will be approximately $545 million with the sequential quarter decline primarily due to contract roll loss across the floater fleet.
As Tom mentioned earlier, we see more uncertainty in the near term for the floater market which may result in revenue and EBITDA that are substantially lower than sell side analyst estimates for the second-half of 2019 and full-year 2020. Our third quarter revenue outlook breaks down as $255 million to $260 million from our floater segment, $220 million to $225 million from our Jackup segment and approximately $65 million of other revenues including $23 million of reimbursable revenue from ARO Drilling, $21 million of ARO Drilling lease revenue and $21 million related to two managed rigs in the U.S. Gulf.
Excluding transaction costs, we anticipate that third quarter contract drilling expense will be approximately $505 million. The sequential quarter increase is mostly due to a full quarter of operating costs to drill ENSCO DS-7, DS-9 and DS-12 which commenced new contracts during the second quarter along with the fourth quarter contribution from the Legacy Rowan fleet. Mobilization costs with our own alliance, Ralph Coffman, and Rowan Norway higher operating costs of their Rowan Norway due to a change of operating location from Turkey to Norway and a portion partial quarter of operations for ENSCO 123 which is due to commence its remaining contractor in the third quarter.
While we have a number of floaters that are expected to roll off contract in the third quarter, reducing costs from operating levels to warm stack state can take 60 to 90 days. The gradual reduction in contract drilling expense does not correspond with immediate decline in revenue. Therefore we would expect to see the benefit of these floater cost reductions in the fourth quarter when we anticipate total contract drilling expense will be below second quarter levels excluding transaction costs which were $489 million. We expect depreciation expense will increase to approximately $163 million due to a full quarter of depreciation for Legacy Rowan assets along with ENSCO 123, Best Brands, and Earnest Dees joining the active fleet.
G&A expense excluding transaction costs is expected to decline to approximately $31 million due to the realization of synergies. Finally, we estimate the third quarter tax provision will be approximately $40 million inclusive of discrete tax expense related to the gain on debt extinguishment following our recently completed debt tender.
I'd like to move now to ARO Drilling. ARO Drilling is a 50:50 non-consolidated joint venture between Valaris and Saudi Aramco, which owns and operates offshore drilling rigs for Saudi Aramco. In total we expect ARO Drilling 2019 EBITDA will be towards the upper half of the prior guidance range of $160 million and $180 million for the full-year.
Note that our SEC filing in press release tables present results from ARO Drilling from the merger date forward and will not include pre-merger activity. As of June 30, ARO Drilling own seven assets with substantial contracted revenue backlog. Valaris contributed five of these seven assets to ARO Drilling in exchange for cash and 10-year shareholder notes that bear interest at LIBOR plus 2%.
On an annual basis, ARO Drilling's board of directors will decide whether the interest on the shareholder notes either added to the principal loan balance or paid in cash. As of June 30th, the balance of these shareholder notes is approximately $453 million. As a reminder, ARO Drilling has no external debt which presents a future financing opportunity given that the company's rig fleet is fully contracted and has meaningful revenue backlog.
Moving out to our capital expenditure outlook for the second-half of the year, excluding transaction costs and the final milestone payment at Ensco team, capital expenditures through the remaining six months of 2019 are expected to be approximately $110 million. This includes approximately $90 million of costs for minor rig enhancements and upgrades including schedule G upgrades on the best brands and earnings fees and the addition of a fully automated drill floor on the Rowan [indiscernible]. A portion of these customer required upgrades are reimbursable. We also anticipate $20 million of CapEx primarily for newbuild and recently delivered jackup rigs.
Most of these costs are related to the startup and mobilization of ENSCO 123 which is expected to commence its main contract in the North Sea during the third quarter. Our only remaining newbuild commitments are for drillships ENSCO DS-13 and DS-14. We might have uncontracted rig days on many of our delivered drillships coupled with an uncertain outlook for near-term floater demand.
We are in discussions with the shipyard to delay delivery of these rigs. We do not delay delivery of the rigs. We have the option to finance the final milestone payments totaling $250 million plus accrued interest through a promissory note with the shipyard for the rig. The promissory note would bear interest at 5% per year with maturity at year-end 2022. Turning now to our financial position, since closing the merger financial management has been one of our main priorities with a focus on managing debt maturities and cost of capital and reducing total debt.
During the first 60 days after closing, our capital management actions were limited by the Legacy Rowan 2025 senior notes which contained a change in control provision with the double trigger mechanism granting holders a put option in the event of both a changing drill and a downgrade by both Moody's and S&P within this time period. Subsequently, we launched and recently completed a debt tender that reduced total debt by $952 million repurchasing debt that carried annual interest payments of $52 million and realizing $228 million of principal savings and an average pre-tax discount of 24%.
Adjusted for the results of the debt tender, pro-forma liquidity as of June 30 totaled $2.7 billion including approximately $350 million of cash and short term investments and a $2.3 million revolving credit facility which steps down to approximately $1.7 billion from October 2019 to September 2022.
As a consequence of the debt tender, we have significantly reduced our available cash and equivalents and we anticipate that we will need to draw on the revolver as a source of funding under the current market conditions. To this point, we have drawn $125 million on our revolving credit facility in advance of repaying our 2019 senior notes that mature today. Given greater uncertainty on the near term outlook for the floater market, we view our revolving credit facility as an important source of available liquidity as we navigate the protracted deepwater recovery.
The key covenants in our revolving credit facility are maintaining a total debt to capital ratio of below 60% providing guarantees from certain of our rig owning subsidiaries such as these entities represent at least 80% of total net book value and having net book value coverage from our marketing rig fleet that is at least 3.25X the size of the facility. Importantly, this revolver is unsecured and has no covenants based on operating cash flows. We also maintain the flexibility to raise additional capital through asset sales and the issuance of guaranteed unsecured debt.
In terms of our next steps, we will look to opportunistically raise additional capital to increase our available liquidity and address near-term debt maturities. It is important to note that we have the largest fleet of offshore drilling rigs in the world which is comprised primarily of modern floaters and jack-ups with an unencumbered gross asset value of approximately $11 billion according to third-party research. We believe that this fleet profile and our unsecured capital structure should provide us with access to capital and financial flexibility as we navigate the market cyclicality.
Finally, I'll provide an update on synergies and transaction cost. As Tom alluded to earlier, we are on track to achieve our annual expense synergies approximately $165 million and we are evaluating additional opportunities with the potential to achieve synergies beyond this target.
In total, these synergies are expected to result in approximately $1.1 billion of capitalized value, more than 75% of these synergies are expected to capture within one year of closing and we expect to reach full run rate synergies of $165 million at year-end 2020. As of June 30, we had reached run rate synergies of $80 million which will benefit contract drilling and G&A expense going forward.
Consistent with our prior guidance, we anticipate the cash transaction costs associated with the merger will total approximately $175 million related to employee severance costs, legal and professional fees and other integration related costs. These transaction cost estimates include costs incurred by Legacy Rowan prior closing as those costs associated with our recent re-branding.
As of June 30, we have incurred total cash transaction costs of approximately $110 million with the majority of the remaining $65 million expected to be incurred in the second-half of this year and they also incurred certain non-cash charges as a result of the merger such as the approximately $3 million of lease impairment charges incurred in our second quarter results.
We'll continue providing updates on our synergy achievement and transaction costs in subsequent conference calls. In closing, I want to reiterate that we will continue to proactively manage our capital structure to most effectively execute our strategic priorities and maximize value for shareholders. We continue to evaluate options that will help us to achieve these objectives, and remain focused on delivering our targeted synergies and actively managing our cost base so we best position the company for the future.
Now, I'll turn the call back over to Nick.
Thanks, Jon.
Jamie, at this time, please open the line for questions.
Ladies and gentlemen, at this point we'll open the lines for questions. [Operator Instructions] And our first question today comes from Ian MacPherson from Simmons. Please go ahead with your question.
Okay. Good morning and afternoon. Thanks. Tom, one thing we picked out of the feet status was a few jackups that have longer priced options behind what we saw before. Most significantly I think was Fist of Anger that shows it has customer price options out through 2025. Can you speak to the genesis of those, how recently were they done? I think you said, broadly, that you have escalating options on some of these rigs, but is that something that goes back in time or were these options more freshly priced with something closer to market pricing expectations?
Hi, good morning, Ian. I'd say that, Ian, as far the sort of a general trend pile of contracting around jackups, particularly the last jackup, we are seeing some good trends as far as if we have priced options that are typically at rising rates, or we have maybe options on contracts which are mutually agreeable. And also the option sort of strike bait, [indiscernible] the customer needs to declare it are typically coming sooner in the drilling contract as opposed to later. So, generally all are all positive. Respect to those -- that specific contract, they were put in place some time ago.
Yes, as part of the master services agreement that we signed with Equinor [ph].
Yes, so we signed a master service agreement with Equinor, and those options were put in place, and we're happy with the cadence of them and how they're priced.
Okay, thanks. I wanted to ask a follow-up of you, Jon. Your working capital kind of crushed your cash flow in the second quarter, and I wonder if you could provide some perspective on your expectations for that component and for the rest of the year?
Yes, sure. Good morning, Ian. From a working capital standpoint, really this quarter there was a lot of moving pieces, I guess as there typically are. But this particular quarter we had a lot of startups in Q2, so for example, the DS-12, the DS-7, the 8500s a few jackups. So typically your accounts receivable will swell when that happens. So we had -- that was one of the drivers. And then we had other aspects such as some tax payments that hit in the second quarter. Typically we would accrue those, but those there was just a bit more a cash standpoint in Q2 than others. And then there were some other mobilizations that were going on this quarter. I would say those are probably the unique items this quarter that impacting working capital. And I would expect that the next quarters would be more normalized but for other kind of movement of rig, so those type of things.
Okay. And Jon, just to clarify, you said your merger costs are expected to be $65 million in the second-half, and I assume probably a little bit heavier in Q3 than Q4. Is that fair?
I think that's fair, yes.
Great. All right, thanks. I'll pass it over.
Our next question comes from Cole Sullivan from Wells Fargo. Please go ahead with your question.
Hi, good morning. On the guidance for third quarter revenues, can you help us walk through kind of the moving parts there a little bit more in depth on -- and as to the rollovers it sounds like the utilization could be a little lower there.
Sure, Cole. Good morning. From a kind of a bridge standpoint from Q2 to Q3, what you see is that we do have some roll-offs happening in Q3. So we've got the DS-4, 8504, the DPS-1, all roll-off in July, and the 5006 in August. And so a lot of that is early in the quarter, and so that will contribute to a meaningful part of that drop-off. And then as I mentioned in the prepared remarks, CDNE is going up because it does take some time for us to ramp down those crews to put them in a more kind of warm state, if you will. And given that a lot of those rollouts are early in Q3 we will incur a lot of the cost of those rigs throughout the quarter.
And then you also have other startups that are occurring, and so typically, as you know, we're going to ramp up the rigs to get ready to work. And so we had some other startups occur in the second quarter that from a third quarter standpoint that you're now going to recognize a full quarter of CDNE, so those are the drillships, the DS-7, the DS-9, the DS-12. And we've also got some mobilizations which I mentioned, the Reliance, the Roth Kauffman, and the Norway, all kind of impact in Q3, which are all lines that are adversely impacting the quarter.
All right, thanks for the color there. You said the cost savings in the second quarter ended at around $80 million on a run rate basis. Can you help us kind of split that up between G&A and OpEx? And then also can you help us think about how much additional cost savings is implied in the third quarter then?
Well, in terms of where we're at today, so from a run rate standpoint, the majority of that savings is impacting G&A at this point. And it's all -- the majority of it is back office expenses as you'd expect. In terms of kind of the ongoing guidance, that trend will continue going forward, and you will see, as Tom mentioned and I mentioned we are aggressively hitting the -- working on reducing cost. And so we're more focused on that part, and so would expect that the Q3 numbers would continue to, from a synergy standpoint, go up, more of that kind of in the near-term.
All right, thanks. I'll turn it back.
Our next question comes from Taylor Zurcher from Tudor, Pickering & Holt. Please go ahead with your question.
Hey, good morning. Thank you. Tom, maybe to start on some of your commentary on the floater market as it relates to pricing. Clearly the commentary you provided, it sounds like a recovery in pricing is continually pushed out to the right. And so my question is, if we could think about the futures curve for ultra-deepwater pricing could you help us understand what your viewpoint of that curve might look like? And then is the inflection point higher really now a 2021 event or is it a late kind of 2020 event?
Hello, good morning. So I think when we -- when I look at my comments in our prepared remarks, what is clear is that we have seen a recovery in ultra-deepwater, and if we think back to sort of 2016-2017, the total utilization for floaters has come up from about 50% to about 66%, and market utilization is gone from less than 70% to over 80% today. So we're on a good trajectory of improving our floater utilization. And as I mentioned in my prepared remarks, we have a significant number of FIDs. So we are seeing floater utilization go up, and correspondingly we have seen floater pricing go up. And floater pricing is up. Where, as I mentioned, we are working against contracts which are generating cash flow, which is good news. And that wasn't the case two years ago.
We are seeing on a number on a number of floater contracts which are -- there are a lot of floater contracts, and the teams are very busy here preparing responding to tenders, and frankly very busy on the floating side, but the length of the contracts they're responding to are shorter than when we would like. And so if we think about contracts that's just starting between now and the end of 2020, more than two-thirds of them are less than one year in duration. And so while utilization has gone up and we are seeing pricing momentum, the short-term nature of these contracts means that we won't see that much pricing momentum in the second-half of 2019 or in the first-half of 2020.
Now hopefully, we're wrong and we see more acceleration in pricing. But given the short-term nature, what we're seeing, a lot of the competitors in the market are going to be focused on getting this rig to work and then worried about the contract straight after it, and so, keeping rigs that are working. Now, as we think [indiscernible] into the latter-half of 2020 and into 2021, we expect to see some longer-term work and we are seeing more longer term work every month, more longer-term contracts appear, but right now the majority of the contracts are less than one year in duration. And so therefore, we won't see much pricing momentum in the short-term.
Okay, that's helpful. And maybe if we think about that your ultra-deepwater fleet and clearly, you've got a handful of Tier-1 floaters that will roll-off in next several months, and you've got at least two warm stack, high-end floaters. If we think about rigs, like the DS-4 and DS-6 still very capable rigs, but probably a step-down from the bucket I just talked about, what sort of the marketability outlook for those two rigs moving forward?
Well, it really depends on the application that the customers have. So I would say that, the DS-4 and the DS-6. You know, the DS-4 for example, has just finished a job in West Africa and it's available right now, but it is a hot rig and customers are looking for assets which have been working recently. So it's not all gloom on the light sixth-generation rigs like the DS-4 because it's really about the customers application, is that they are drilling, if the needs of the reservoirs they are drilling into are in a very deepwater or very, very high-end work.
And then perhaps that's not the rig, not the rig that's needed, but a lot of the applications, the DS-4 is just fine, as well, as being shown in the work. It's just done in West Africa. There is no doubt customers are more focused on the high-end rigs. On have on the seventh-generation rigs, but the DS-4 is still an excellent rig and it's got it's place in the market.
Okay. Thanks for that. I'll turn it back.
Thank you, Taylor.
Our next question comes from Kurt Hallead from RBC. Please go ahead with your question.
Hey, good morning.
Hi, good morning, Kurt.
I appreciate the color and the update and perspective on the dynamics to play in the market over overall. I think maybe Tom just in the dynamics of how you outlined the short duration and the churn, if you will, that's going to occur in the marketplace? Yes just curious when you say the pricing momentum or won't see much pricing momentum into the first-half of 2020, would you suggest that the pricing momentum is completely going to stall? Or just from an upward dynamic? It's, going to maybe inch along from here, instead of maybe take a serious step? Can you just maybe provide a little bit more context to that?
Sure. So it's hard? It's, I would say, it's more likely the latter. We'll see pricing improvements, but we certainly aren't going to see, we're not expecting to see a fair step up. But we are not expecting it to store but again, we are seeing utilization go up, we are seeing rigs being re-contracted. We are seeing in South America more assets being put to work. So, utilization is improving and it will continue to improve but the short term of the contracts will mean that, even though utilization is pushing up, we're not expecting to see significantly, increased pricing momentum, doesn't mean it's going to store, but it doesn't feel like it's going to take a jump up.
Okay, I appreciate that context, Tom. In the dynamic of the guidance points that have been provided for the third quarter in initial outlook into maybe the fourth quarter from an operating cost standpoint. Just kind of curious with the reduction in your debt, is that, I guess that's going to map out to be what about less than $100 million of interest expense for the second-half of the year per quarter? Is that about, right? If I were to kind of map that out?
That's about right. Yes, so we're our run rate is just around 400 pro forma for the tender, so roughly about a 100. And just keep in mind, Kurt, that's on a book basis, the cash is a bit different. And so, third quarter for us is typically a higher cash interest expense. But your numbers are in line.
Okay. And just wondering if you might be able to just offer us on -- you provided the guidance or the input for ARO EBITDA for the full-year, what's the flow through in the current equity and earnings line for the year for ARO?
Well, for the year, we didn't provide any guidance for the year, but you can see Q2 and what I'd say is that, it's highly contracted fleet. So there's a lot less variability than maybe the broader Valaris fleet, and so, if you look, one of the interesting things here and I'll probably use this opportunity to kind of make a point on the purchase accounting aspect of this, but if you look at the equity earnings, that flows through this quarter, it's really, it's less, it's about $0.5 million. But if you look at and I'll guide you there's a bit more detail, if you look at this, these footnotes for in the 10-Q, but if you look without the amortization of the purchase accounting, the equity interest is $8.4 million. And so, it's probably fair to look at that as kind of the more normalized run rate for the business. But because we have to write that when the merger happened, we had to write up our investment. And then amortize that, we effectively knock off a lot of the net income there due to purchase accounting, which is what you see flowing through on the income statements.
That's perfect. That's great. That's great color. I really appreciate that. I'll keep it there. Thank you, guys. Bye.
Our next question comes from Greg Lewis from BTIG. Please go ahead with your question.
Yes, hi everybody. Thank you and good morning.
Hi, Greg.
Hi, Greg.
Jon, I think in your prepared remarks, you mentioned about ARO and the potential financing opportunities around ARO, any kind of color, you could provide us around that?
Well, certainly what we've said, in the past, Greg still it remains true that obviously, we are a couple, just as in two years into our journey with ARO as far as operating. We have a highly contracted fleet. We are right, as I mentioned in my remarks, we are right in the middle of determining a new build project, which is flipped a little bit because of negotiations with the shipyard, as well as, there is a shipyard construction being pushed a bit to the right. But things are going well, with ARO. As far as the capital structure, we will -- once we understand the tempo and the timing of the new builds, then we'll determine what the right next steps are. One of those steps would be putting in an involving credit facility. Another one would be making sure we have the right construction financing for the new builds. And another one might be bringing in some external debt. So, but until we actually, find the -- we have some visibility on the new bill program, which is premature to start changing the capital structure.
Okay, great. And then just one more for me, you mentioned, and you can -- I think you called out three of the older floaters. And then, you kind of follow that up with comments around assets sales. As we think about asset sales, I mean, historically, I mean, I guess, we have a name change, but historically, Ensco has been very good at kind of renewing the fleet getting selling older assets, bringing in I mean, as we think about asset sales, really, should I be thinking? Should we be thinking about these as really just, legacy non-core assets? Or do you think we can? Or do you see a scenario where maybe we could even sell some of the more valuable higher end rigs, just as you mentioned you have more ultra-deepwater rigs than anyone else on the world?
Yes, we would look at all avenues. With respect to the rigs that I mentioned in the -- in my prepared remarks, I would say that, we will evaluate those rigs, we continue to evaluate them, we have a very, very robust understanding of the need as far as upgrades, special split surveys, et cetera. So we'll look at those rigs as a role of contracts over the next nine months and then determine what the right role is for them. And whether we should keep them in the fleet, if there's a good opportunity for them or we should sell them, and you're correct, the company has sold a lot of assets over the last 10 years.
With respect to sales of other rigs, nothing is off the table, we certainly look at what we believe the assets are worth, and from our cash flow generation over time and what will we're able to get to them and nothing is off the table.
Okay great. And then okay guys and congratulations on the tender. That was a really big deal for you guys. So thank you very much.
Thank you, Rick.
Our next question comes from Chase Mulvehill from Bank of America. Please go ahead with your question.
Hey, thanks, good morning. So I guess I wanted to talk about the debt relief. Maybe you talked a little bit about this earlier in the call but often a little late but maybe did you provide any timing or maybe the amount of refinancing that you expect to do on the debt side and then talk about maybe whether you'd prefer to secured debt or preferred guaranteed notes?
Yes, sure, Chase. So we actually haven't covered that much detail, so I will cover some new ground with my comments. But in terms of just in the prepared remarks, I did mention the fact that on top of the debt tender which you versed on, we did just repay the 2019 maturities that we had due today. So those are repaid and we did draw on our revolver to do that. Right now we're drawn on the revolver at $125 million. So we are going to look at external funding sources to potentially continue to improve our liquidity. And so, those funding sources could be secured debt or guaranteed debt. I mentioned that right now, we have a completely unsecured capital structure with gross asset value of $11 billion per third-party. We have a book capitalization of over $18 billion and for even the prior question we have the ability to monetize assets as well. So we're going to look at all funding sources we have in the current environment to continue to bolster our liquidity to manage our way through the cycle in the current conditions.
Okay, all right. And on the timing would you expect something to happen in the third quarter here?
Yes, Chase. I think what you've seen is that we're going to continue to be opportunistic. It's we're not going to rule anything off the table but we're also not narrowing in, I think we continue to watch the market look for opportunities. We certainly have no need to rush out to the markets to do anything. We have ample liquidity at the moment. If you look at the liquidity, we have we still have the $2.3 billion on the credit facility which does tick down to $1.7 billion. But with that that amount of liquidity, we can be patient and wait for the appropriate market window.
All right, that makes sense. And on the CapEx side, have you given any color around 2020 CapEx would you care to provide any color. Maybe we can kind of use the back half run rate as maybe as a starting point for 2020 is that a good starting point?
Well we haven't provided 2020 guidance just yet Chase. But what I would say is that we've effectively if you look at 2019 versus 2020, we're effectively passed the newbuild program moving forward. We do have the DS-13 and the DS-14 that are outstanding. I'm putting those in a different bucket because we do have the ability to roll that CapEx into a notes receivable. But barring those two rigs if you just look at kind of the kind of the sustaining CapEx and the run rate kind of the base CapEx that's something that will clearly have next year but we haven't gone through our capital kind of planning cycle yet. So we don't have any guidance for that.
Okay, understood. I'll turn it back over. Thanks Jon.
And our next question comes from Vebs Vaishnav from Howard Weil. Please go ahead with your question.
Hey, good morning, and thank you for taking my questions. Can you talk about going forward with all the changes you have done in the debt. How do we think about the cash interest expense? I think tell us a little bit about that and how to think about cash taxes and maintenance CapEx?
Sorry just to clarify. So cash interest expense, cash taxes, and what is last thing?
Maintenance CapEx for the pro forma company?
Yes, so I'll start with the cash interest expense and I think you're looking for more of a run rate, and so as I mentioned, our cash interest right now pro forma for the tender are our debt. I call it our unsecured bonds carry an interest expense of roughly $400 million. If we are to draw on the revolver for additional funding needs that will add to that interest expense and so you saw that we shaved off about $52 million from the tender that we just did from our bonds. However that will be partially offset by any revolver draw that we do, so I mentioned we just drew this week in order to pay down the 2020 maturities. And so, as you go forward the cash interest expense will be somewhat higher if we need to draw on that revolver further and in the current environment with the environment that we have today, we do anticipate that we are going to continue to be drawing on that revolver which will increase that that cash interest expense.
On a cash taxes standpoint, I don't know if we have. It's very hard to guide to it to run rate on that. I think we could probably go through that a bit more detail offline, if you want to kind of understand how taxes work. But it really is a function of what jurisdictions we are working in, the timing of contracts. And as you know, we do make profits in certain jurisdictions even though we are operating at a net loss today, our cash taxes are very much impacted by where we're working in the margins in different jurisdictions which does change over time and so it's much harder to provide a kind of a run rate for that one. But if you look at kind of the current quarters as a probably fairly decent guides to kind of the near-term anywhere near-term being maybe the next quarter or two but it will very much be a function of our business mix. And then there is some base level taxes that we will be paying just based on our jurisdiction that we operate in our structure. So I know that's not completely clear but it's taxes isn't variability just based on the operating profile.
And I guess maintenance CapEx how should we think about it going forward?
Yes, and similar to what I mentioned with Chase. We don't have guidance out there from a long-term basis. I would say that if you look at kind of where we're at between now and the end of this current year's CapEx cycle or at least the back half of the year that's probably good guidance for the end of the next. That is the guidance for the next six months next year, we're going to have our capital budgeting cycle later this year where we'll look at 2020. We've completed the merger in the last quarter so it's something we need to get together and really do an assessment on the fleet on what the type of maintenance run rate we really want to have as a pro forma fleet in the current environment.
And so, it's probably premature to guide to it but sufficed to say that on a gross CapEx basis, we should be lower year-over-year given that we don't have the same number of upgrades and enhancements that we have this year barring the two DS-13 and the DS-14 which we can roll those into a promissory note. So stay tuned, we'll provide a bit more guidance on that in the coming quarter.
Okay. And as we think about the debt markets like can you say like what bankers are telling you about, how open the debt markets are either on unsecured basis or secured basis?
It's hard to comment, I think you can probably talk to your bankers and get the same input. I mean you can see where the bonds are trading clearly it's a bit of a challenge market right now which is one of the reasons why we did the debt tender, so it was that the bonds have really traded off. And so, we were able to capture a meaningful discount, so mentioned 24% discount. So you can read through where our bonds are trading now and the discount that they're at the yields that we purchase those bonds that is a bit of a proxy for new issuance.
Obviously there would be some variances and a new issuance then where they're trading, but it's very much market dependent and it could trade. So I don't change I said don't necessary I want to provide guidance out there but using that you could look at the yield on our bonds as a proxy. And clearly if we were to do anything that was senior to the current bonds, we would expect that those would trade at a premium to the current complex given a similar type of tenor but the market is challenged at the moment.
Got it. Thank you so much for taking my questions.
Thank you.
And ladies and gentlemen we've reached the end of today's question-and-answer session. At this time, I'd like to turn the conference call back over to Nick for any closing remarks.
Thanks, Jamie, and thank you to everyone on the call today for your interest in Valaris. We look forward to speaking with you again when we report third quarter 2019 results. Have a great rest of your day.
Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.