Valaris Ltd

NYSE:VAL

Earnings Call Transcript 2019-Q1

[Operator]

Good day, everyone, and welcome to EnscoRowan PLC's First Quarter 2019 Financial Results Conference Call. [Operator Instructions]. Please note, today's event is being recorded. I will now like to turn the call over to Mr. Nick Georgas, Senior Director of Investor Relations, who will moderate the call. Please go ahead, sir.

[Nick Georgas, Senior Director, IR & Communications]

Welcome, everyone, to EnscoRowan's First Quarter 2019 Conference Call. With me today are President and CEO, Tom Burke; Senior Vice President and CFO, John Bakst; and other members of our executive management team. We issued a press release, which is available on our website at enscorowan.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 website 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 website for additional information and required reconciliation. As a reminder, we issued our most recent Fleet Status Report, which provides details on contracts across our rig fleet on April 29. An updated investor presentation is also available on our website.

Now let me turn the call over to Tom Burke, President and CEO.

[Thomas Burke, President, CEO & Director]

Thanks, Nick, and good morning, everyone. I'd like to begin by welcoming you to the conference call. Since this is our first call as a newly merged company, most of my prepared remarks will focus on EnscoRowan's company profile and an overview of our priorities in the coming months, then I will provide you with some commentary on the offshore drilling market, after which John will speak the financial results and outlook.

As you know, we announced the merger at the beginning of October last year. We began detailed integration planning about a month later in November and our first day of combined company operation was 3 weeks ago on April 11, the day the 2 companies merged.

I'd like to take a moment to acknowledge and thank our employees, who worked so hard over the last 6 months, the plan and execute a successful integration. Our first day in three weeks since we merged have gone well, we experienced no disruption to our offshore operation. This is a major milestone given the complexity inherent in such a large combination and is a testament to the detailed integration planning efforts and attention to detail by our operation team over the past several months.

There is more work to be done from an integration standpoint, I'm extremely pleased with the progress that has been made since the merger closed. And I'm excited about our future as a larger and more diversified company. We'll not consider EnscoRowan's position in the industry. It is clear we have created the industry-leading offshore driller across lower depths and geographies. We have a high-quality rig fleet of ultra-Deepwater drillships, versatile semi- subs and modern jackups, along with a presence in virtually all major offshore basins giving us the ability to service a wide spectrum of customers offshore drilling requirements. We believe that by maintaining a fleet of both floating and jackup rigs and harvesting these assets have scale across the global footprint, EnscoRowan will be a key offshore provider for customers for many years to come.

In terms of customer relationships, we now have the largest and most diverse customer base in the industry. EnscoRowan's current customers include most of the leading international and national oil companies as well as many independent operators. These relationships have been formed over many years by consistently delivering sight and efficient services to customers, and we're eager to raise the bar for service excellence in the industry.

That is why we were honored to have been the top-rated offshore drilling contractor, a total customer satisfaction in the latest independent survey by EnergyPoint Research, the 9th consecutive year EnscoRowan has earned this distinction. While we are proud of the achievements, we recognize that we must continue to improve our performance so that we remain the industry leader.

Developing new technologies and innovative solutions to differentiate our services and drive operational efficiencies at the well site will be an important part of EnscoRowan's future. By partnering with our customers to help lower their offshore project cost, we will further enhance EnscoRowan's position as the leading provider of offshore services.

Our common portfolio of proprietary systems, processes and technologies include a patented system that provides more efficient and safer pipe tripping, technologies that optimize jackup moves to minimize time spent relating on weather and reliability-based maintenance system that help to increase operational uptime and lower the overall cost of asset ownership.

As a combined company with greater scale, we are now able to streamline the legacy company's innovation efforts and spread these and future investments across a larger rig fleet. We also benefit from a solid financial position bolstered by strong liquidity and manageable debt maturities. While John will provide more details on our financial position in a moment, I'd like to highlight that we've already seen the advantage of being a larger more diversified company because in conjunction with the closing of the transaction, we were able to execute an agreement with our banking group to increase the capacity under our revolving credit facility.

I note that our finance team under Jon's direction did a great job working with our banking group to get this extension Now that we closed the merger, our attention has turned to 4 immediate priorities. Some of which we are unable to work on prior to the closing for competitive reasons. But first of these priorities are the management of our existing fleet. Given that we are now operating a much larger rig fleet, our approach will differ from that of either standalone Ensco or Romans. We've taken immediate action on this front by announcing the sale of the jackup ENSCO 97 we've also classified jackup Rowan at held-for-sale and expect this rig will very soon leave the global drilling supply. We will continue to evaluate our fleet for candidate and expect to provide updates in the coming quarters.

This fleet management focus also encompasses our contracting strategy. For jackups, our main focus will remain on contracting the available days across our marketed fleet, and it's worth noting that every one of our marketed jackup is either currently under contract or expected to begin the contract shortly. As a result, we may selectively reactivating 1 or 2 modern jackups later this year to meet increasing customer demand. However, any reactivation decisions would be contract dependent, and we will disciplined return based approach as we evaluate the deployment of funds towards reactivations.

Within our fleet, we do not expect to reactivate any of our preservation stacked asset in 2019. Further, given our larger combined fleet and our successful track record of starting up idle rigs, we will be judicious as we contract floater availability, pursuing a portfolio approach with our available rigs. The second priority will be delivering value drilling of 50-50 joint venture with Saudi Aramco. For those of you on the call, who are not familiar with our drilling, this is a joint venture to own and operate jackups in partnership with the largest customer of jackups in the world, which also secure backlog for a portion of our jackup fleet to a leasing structure and provide strong organic growth through our drilling newbuild program.

I'm pleased to report that operations in our drilling are progressing well and ARO Drilling first quarter results comfortably exceeded our expectations. Later this quarter, we expect ARO Drilling will order 2 newbuild jackups. This will be an important milestone for ARO Drilling as these are the first 2 of the 20 new rigs that the company will build. Because these rigs will have long-term contracts with Saudi Aramco, EnscoRowan will benefit from the visible earnings growth by our ownership stake in this groundbreaking joint venture.

As a reminder, ARO Drilling currently own 7 rigs. And by the end of the third quarter, will have 9 jackups leased from EnscoRowan, all working under 3-year contract with Saudi Aramco. These 9 lease rigs include the best brands and earnings fee, but are expected to commence 3-year contracts during the third quarter. It's important to note that the contracts for the 7 rigs owned by ARO Drilling and the 9 lease rigs benefit a 50% interest in ARO Drilling's net earnings. And we also received a meaningful buildout from the 9 lease rigs that is recognized as revenue by EnscoRowan.

I would note that the 8 legacy ENSCO jackups will continue to work for Saudi Aramco under that current contracts and remain outside of our drilling. There will also be opportunities to lease additional EnscoRowan assets to ARO Drilling in the future.

The third priority will be balance sheet and liquidity management. Both legacy companies opportunistically manage near-term debt maturities and extended their liquidity run of the past several years. As a combined company, we will continue to take proactive steps that best position EnscoRowan to manage through the market cycles and deliver long-term value for our stakeholders.

Finally, we continue to focus on integration and delivering a $165 million of annual targeted synergies from the merger. We have a dedicated project team in place to help ensure that this merger proved to be a success for our employees, customers and investors. We will provide updates on our integration efforts and our progress towards reaching our synergy targets in subsequent conference calls.

Now moving to the broader market. We continue to see improvement in the offshore drilling industry. While front month Brent crude oil prices have rebounded strongly in the early part of 2019, increasing by approximately 40% since the beginning of the year, intermediates and longer dated pricing have increased slightly and more importantly have been relatively stable about $60 per barrel.

Future oil prices at these levels coupled with attractive new project economics have created an environment more conducive to new offshore project investments. And our exploration and production companies offshore capital expenditures are expected to increase modestly in 2019 and continue growing steadily over the next several years. Indicators of customers' interest support these trends. The number of new contract awards increase 40% year-over-year during the first quarter, supported by higher short-term oil prices.

While contracting activity is up substantially, the number of open tenders for offshore programs has been relatively flat over the past few months, particularly for floaters, which reflects the longer cycle of Deepwater investments.

As a result, the Deepwater recovery is still in its early stages as despite including levels of stock utilization, low contracts beginning in 2019 of a relatively short-term projects. Not surprisingly of these contracts continue to be competitive, while pricing for commencing in 2020 and beyond is much more encouraging with day rates that are substantially higher than current spot rates. This is especially true for the most modern technically capable assets, where we see neutralization for these rigs improve more quickly than that of older less capable assets.

In fact, many of the drillship tenders in the market today require a higher specification assets with features such as tubular preventers, 2.5 million pound and large bearable backloads. We were recently awarded new contracts the 2 of our highest specification drillships in important region of the Deepwater activity. The ENSCO DS-9 was awarded a 4-well contract offshore Brazil with an expected duration of nearly 1-year plus option. This is an important contract for 2 reasons. First, it's a contract with an IOC in the region that has historically had one major customer. We expect IOC to become more active in this region, leading to a more diverse customer base.

Second, the contract provides further evidence of the attractive project economics offshore Brazil, particularly in presell targets. We believe that these conditions will lead to increasing work in the region, requiring additional rigs to service demand and leading to meaningful growth in the number of working offshore Brazil and years to come. For these reasons, we view this as a key contract win such as one of our most capable assets the ENSCO DS-9 and the region where we expect to see growing demand for high specification drillships.

We were also awarded a 6-month contract for the ENSCO DS-7 offshore Egypt with options that could lead to more than 15-month of additional work. The customer is a joint venture between and IOC and national oil company. Further, we are partnered with a local company to establish the workforce that is comprised of a high percentage of the Egyptian nationals, which will benefit the local community where we will be operating and better position us for future opportunities in this important gas basin.

In terms of the jackup market, we saw a significant improvement in the contracting environment during 2018 in certain regions, particularly in and we expect to continue to see signs of improvement in most shallow markets in 2019. This includes the Middle East, where all 19 of our marketed jackups are currently under contract, including the 9 leased rigs for ARO Drilling.

For most of the floating market, we're seeing increased utilization for the highest specification assets with current utilization for modern harsh environment jackup about 90% and approaching 80% for modern 9 units. This level of utilization could lead to pricing increases in some regions.

Before I hand the call over to Jon, I want to reiterate my excitement about the potential for EnscoRowan. Through our merger, we have created a stronger company capable of driving different market cycles. Our increased scale, diversification and financial strength will provide significant advances to better serve our customers and deliver value for our stakeholders. I'm highly optimistic for the future and look forward to executing on the significant long-term growth opportunities as the offshore market recovers.

Now I'll turn the call over to Jon.

[Jonathan Baksht, SVP & CFO]

Thanks, Tom, and good morning, everyone. I'm excited to speak to you on our first conference call as EnscoRowan, as this merger positions the pro forma company well to drive increased efficiencies and returns for our shareholders. I'd like to start off by thanking our employees for a successful start to the integration process and our shareholders and lenders for their overwhelming support. Given that this is our first conference call as EnscoRowan, our prepared remarks will be somewhat longer than usual in addition to providing a review of our first quarter 2019 financial results and our outlook for the second quarter, I'll also provide some high-level commentary on ARO Drilling. Full year 2019 CapEx guidance, a summary of our pro forma financial position as of March 31, 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 first quarter 2019 results our press release reflected legacy Ensco's operations only, since Ensco was the legal entity required in the merger. First quarter 2019 results for Legacy Rowan were broadly in line with company's results in the prior quarter. Detailed first quarter 2019 results for Legacy Rowan will be filed in the coming weeks as part of the pro forma financial filings for EnscoRowan.

As such, my first quarter 2019 commentary today is specific to Legacy Ensco results. First quarter 2019 financial results beat the guidance from the prior conference call by approximately $20 million with adjusted EBITDA of $36 million for the quarter. On a sequential quarter basis, total first quarter revenue was $406 million versus $399 million in the prior quarter. In the Floater segment, revenue increased to $233 million from $228 million in the fourth quarter, primarily due to contract startups for ENSCO DS-10, ENSCO 8503 and ENSCO 8505. This is partially offset by lower revenue for ENSCO DS-7 and DS-12, which completed contracts in the fourth quarter, as well as a decline in the average day rate across the floater fleet.

Operational utilization for the Floater segment, which adjust for uncontracted days and plan downtime was 98% compared with 97% in the prior quarter. In the Jackup segment, revenue increased slightly to $157 million from $156 million in the prior quarter. This was due to a 10 percentage point increase in utilization for the market of jackup fleet to 87%, largely offset by decline in the average day rate.

Operational utilization for the jackup fleet during the first quarter was 98% compared with 97% in the fourth quarter. Moving now to costs. Excluding transaction cost, contract drilling expense increased sequentially by $10 million to $333 million. This is $17 million lower than the prior conference call guidance, primarily due to the later expected commencement of contracts for 3 rigs and of plant repair and maintenance expenses. Due in part the removal of contract preparation costs for certain work that do not materialize.

First quarter depreciation expense increased to $125 million, primarily due to the addition of ENSCO DS-9 to the active fleet, partially offset by lower depreciation expense related to an impairment charge recognized in the prior quarter. Excluding transaction costs and the recovery of certain costs related to an ongoing legal matter in the fourth quarter 2018, general and administrative expense was $24 million during the first quarter 2019 compared with $33 million in the prior quarter.

During the first quarter, we incurred $6 million of merger-related transaction costs, which were excluded from adjusted EBITDA and the adjusted loss per share presented in the press release. Other expense, including net interest expense increased to $75 million from $70 million in the prior quarter. The sequential increase was primarily due to lower capitalized interest as a result of ENSCO DS-9 joining the active fleet.

Finally, tax expense increased to $32 million from $23 million, mostly due to $1 million of discrete tax expense in the first quarter of 2019 compared to $6 million in discrete tax benefit in the prior quarter. Adjusted EBITDA for the first quarter 2019 was $36 million compared to an adjusted EBITDA in the fourth quarter 2018 of $45 million. A reconciliation of net loss to adjusted EBITDA is presented in the press release.

Before I discuss our second quarter 2019 outlook, I'd like to note that my comments reflect expectations for EnscoRowan from April 11 forward plus Legacy Ensco operations for the first 10 days of the quarter.

For the second quarter, we expect total revenues will be approximately $580 million. This breaks down as $290 million to $295 million from our Floater segment, $220 million to $225 million from our Jackup segment and approximately $52 million from the Other segment. Other revenue includes $24 million of reimbursable revenue from ARO Drilling, $21 million related to 2 managed rigs in the U.S. Gulf and $17 million of ARO Drilling lease revenue.

Excluding transaction cost, we anticipate the second quarter contract drilling expense will be approximately $510 million. This includes approximately $11 million of contract preparation costs, mostly related to the best in and which are expected to commence 3-year agreement with ARO Drilling in the third quarter.

We expect second quarter depreciation expense will be approximately $151 million and G&A expense, excluding transaction cost is expected to be approximately $35 million. Finally, we estimate the first quarter tax provision will be approximately $34 million. The effective purchase accounting on the assets acquired in the liabilities assumed from Legacy Rowan has an insignificant impact on the revenue, contract drilling and G&A expense outlook discussed. However, our fair value estimates remain preliminary and may change materially as we finalize those estimates during the 1-year measurement period.

I'd like to move now to ARO Drilling. I'll begin by providing some overview comments on the state of the joint venture given the JV will be new to some listening to the call. ARO Drilling 50-50 unconsolidated joint venture between EnscoRowan and Saudi Aramco, which owns and operates offshore drilling rigs for Saudi Aramco. As of March 31, ARO Drilling owned 7 assets, has cash on hand of more than $200 million and a substantial contracted revenue backlog.

EnscoRowan contributed 5 of these 7 assets to ARO Drilling in exchange for cash and 10-year shareholder notes that pick interest at LIBOR plus 2%. As of March 31, the balance of these shareholder notes was approximately $455 million. This is important to note for 2 reasons. First, the shareholder nodes EnscoRowan hold from ARO Drilling are unique in the industry, and these nodes which are assets that we receive this consideration for rig contributed to the joint venture are often overlooked by the investment community when they evaluate EnscoRowan.

Second, ARO Drilling has no external debt, which present the future financing opportunity in light of the company's rig fleet with high contracted backlog. ARO Drilling 7-owned assets reach contracted to Saudi Aramco for initial 15-year term with renewal and repricing every 3 years, provided that they meet Saudi Aramco's technical and operational requirements. EnscoRowan benefits from our 50% share of these rigs' contribution to ARO Drilling's net earnings.

There are nine rigs owned by EnscoRowan that are or will be leased to ARO Drilling to fill drilling contracts between ARO Drilling and Saudi Aramco. Each rig has an initial three year contract with day rates based on agreed pricing mechanism. EnscoRowan benefits from our 50% share of these rigs' contribution to ARO Drilling's net earnings and from a significant percentage of rig level EBITDA that is received by EnscoRowan as charter fee.

Additionally, ARO Drilling provides long-term visible growth through its newbuild program, which is expected to deliver up to 20 jackups over the next decade. Each rig will have an initial 8-year contract with day rates set by an EBITDA payback model, followed by a further guaranteed 8-year contract with day rates set by a market pricing mechanism. Thereafter, the rigs will receive preference for new contracts in the kingdom provided they need Saudi Aramco's technical requirements.

By way of example, if we are illustratively assume that ARO Drilling newbuild rig costs $180 million to build, we would expect the annual EBITDA contribution from this rig to be approximately $30 million each year for the first 8 years. Importantly, the newbuild program is expected to be fully financed by ARO Drilling through ARO-generated cash flows and external financing. As I mentioned earlier, ARO Drilling currently has more than $200 million of cash on its balance sheet and will fund the down payments on the first 2 rigs that we expect will be ordered later this month.

Finally, EnscoRowan also receives transition services fees, representing the cost of EnscoRowan support functions, which provide services to ARO Drilling. Although the joint venture is expected to build its own support functions overtime, replacing the services currently provided by EnscoRowan. And as a result, the transition services fees are expected to decline in the near term.

In total, we expect ARO Drilling's full year 2019 EBITDA will be between $160 million and $180 million, consistent with previously provided guidance. Moving now to the capital expenditure outlook for EnscoRowan. Excluding transaction costs, capital expenditures for the remaining 9 months of 2019 will be influenced by 3 items. First, we anticipate $150 million of costs from under rig enhancements and upgrades, including $60 million for Schedule G upgrade on the best brands fees and $16 million for Rowan's A portion of these customer required upgrades are reimbursable.

Second, we expect an additional $45 million of CapEx, primarily from newbuild and recently delivered jackups. Most of these costs are related to the startup and mobilization of ENSCO 123, including the majority of costs required to complete the commissioning of continuous tripping technology. We're pleased to note that ENSCO 123 was delivered from the shipyard last week and is expected to commence the contract in the North Sea later this year.

Finally, we are contractually scheduled to take delivery of ENSCO DS-13 in the third quarter, which a result and the final milestone payment to the shipyard of approximately $85 million, excluding accrued interest. However, we have the option to finance this milestone payment and accrued interest through a promissory note with the shipyard for the rig. The promissory note will bear interest at 5% per year with maturity at year-end 2022. If we were opt to use the shipyard financing, we do not expect to incur capital expenditures for the rig in 2019.

Turning now to a summary of our pro forma financial position. I'll start by providing an overview of the transactional impact of the merger. First, a trigger to change of control event for Legacy Rowan of revolving credit facilities, resulting in the termination of these commitments by their banking groups. Second, Rowan senior notes due 2025 contain a change in neutral provision with a double trigger mechanism granting holders of put option in the event of both the changing control and the downgrade by both Moody's and S&P within 60 days of closing. Since we closed, Moody's reaffirmed their prior credit rating and S&P has upgraded the issuance level rating, which does not trigger the change in control of this bond or any other bonds.

In conjunction with the closing of the merger and the termination of the Rowan revolving credit facilities, we executed an agreement with our banking group to increase the capacity under the Legacy Ensco revolving credit facility. As a result, we now have borrowing capacity under our revolver or approximately $2.3 billion through September 2019 and approximately $1.7 billion from October 2019 through September 2022. The upsizing of our revolver was a positive development and demonstrates the support of our banking group and their recognition of the strength and position as a combined company.

Importantly, the revolver remain unsecured and has no covenants based on operating cash flows. While we also maintain the flexibility to raise an additional capital through asset sales and an increased secured debt basket of $1 billion. Adjusted for the amendment to our revolving credit facility, pro forma liquidity, as of March 31, totaled $3.8 billion, including approximately $1.5 billion of cash and short-term investments and are fully available $2.3 billion revolving credit facility.

Additionally, we have $2.6 billion of contracted revenue backlog, excluding our 50% interest in ARO Drilling's contract backlog. Considering our strong liquidity position, our nearest term net debt maturities remain manageable with approximately $1.1 billion of debt maturing before 2024.

As Tom mentioned earlier, balance sheet management will be one of our key priorities with a focus on managing our liquidity, debt maturity runway, minimizing our cost of capital and reducing long-term debt.

Finally, I'll provide an update on synergies and transaction costs. We expect to realize annual expense synergies of approximately $165 million, and our level of conviction in achieving this target has increased since we closed the transaction. In total, these synergies are expected to result in approximately $1.1 billion of capitalized value, creating significant value for shareholders. More than 75% of these synergies are expected to be captured within one year of closing, which will make the transaction accretive to cash flow per share in 2020. And we expect to reach full run rate synergies of $165 million by year-end 2020.

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 various other integration-related costs. This includes cost incurred by Legacy Rowan prior to closing. We may also inform certain noncash charges as a result of the majority such as lease charges. In terms of timing, we anticipate that approximately 85% of cash transaction costs will be incurred in 2019. We'll provide updates on our progress towards achieving these targeted synergies in subsequent conference calls. In closing, we are very pleased to have completed the merger and will be moving forward as one stronger company. Our increased scale, diversification and financial strength will provide us with significant advantages, and we believe we are well positioned to capitalize on opportunities as the industry recovers.

Now I'll turn the call back over to Nick

[Nick Georgas, Senior Director, IR & Communications]

Thanks, Jon. at this time, please open the line for questions.

[Operator]

[Operator Instructions]. Today's first question comes from James West with Evercore ISI.

[James West, Evercore ISI]

Congrats on closing the transaction. So Tom, if we think about the market right now, we're clearly in recovery mode on both shallow and Deepwater. You've got both parts of the -- both segments of the offshore market. How are you thinking about term versus short-term spot at this point, given the trend of higher day rates, I know you just logged in some term on Deepwater rigs, but how are you thinking about staying shorter market versus longer market?

[Thomas Burke, President, CEO & Director]

James, that's a good question. I think as we completed the merger just 3 weeks ago, we're obviously spending a lot of time on our fleet strategy right now. But what's clear is that portfolio approach where we really look at the available assets and how attractive the contract is, certainly keeping our exposure to the upside. So we don't want to look into too many assets for too long, but also keeping our working assets working. So really kind of a portfolio of our available assets against the total contracts.

[James West, Evercore ISI]

Okay. Fair enough. And then with respect to ARO Drilling, so 2 jackups here shortly. What should we expect as the cadence of orders going forward? Is it every 6 months, 12 months? How do you guys think about that?

[Thomas Burke, President, CEO & Director]

Yes. That's certainly I'm on the Board of Rowan and obviously up to the ARO. But the business plan at ARO Drilling basically says every 12 months we're putting another there. So I would expect in order to come out very soon, and 1 every 12 months. While the shipyard is getting up and running, the portion of those jackups will be built in land So I expect the first rig certainly to be -- the first 2 rigs certainly to come out made a press release at the other December basically stating that they had an order from IMI, which is a shipyard. But I would guess every 12 months, James.

[Operator]

And next question today comes from Ian MacPherson of Simmons.

[Ian MacPherson, Simmons & Company International]

Congrats everyone on getting close to and started here. I wanted to also ask the first question about sort of the slope of day rate improvements for Deepwater. My understanding is that the total contract in Brazil is relatively low day rate, it's more about the recent spot environment as opposed to the rising up in 2020, 2021. But you have options, and I wanted to see if you could put any color on the pad with regard to the slope of day rate improving on the options behind that one or any other recent contract wins that illustrates the rising day rate from the spot to price options behind spot?

[Thomas Burke, President, CEO & Director]

To comment on the DS-9, that contract obviously, I wasn't here, but what I understand about the contract, it was So it's not from a contracting process, it's actually happen over a period of time. So that's right, which us going on shortly is really quite some time ago. So I would tell you, we don't typically comment on option when there is across the fleet, there will be a number of different strategies as far as priced versus nonpriced. But I'll hand over to Carey, have a comment on that..

[Patrick Lowe, EVP & COO]

The options are increased rate.

[Thomas Burke, President, CEO & Director]

On the DS-9.

[Patrick Lowe, EVP & COO]

On the DS-9. And then one thing I'd add just as you look at the options just across the fleet, as Tom said, some of these options -- I'm not speaking specifically around the DS-9 now, because there are several of our assets and the contract environment do have options in some cases especially ones that we contracted such as the DS-9 earlier in the cycle. Those could be price options, but some of the options that we have really just prized in market rates. So those are floating just based on where the market is at the time.

[Ian MacPherson, Simmons & Company International]

I understood. I wanted to ask my follow-up question just to do check on my notes on your cost guidance and check my roadmap from current OpEx to your fully optimized energized because burden at the end of next year. So if your contract drilling expense plus your G&A for Q2 is going to be just below 450, assuming constant activity by the end of next year and that won't be true, because activity should be higher. But it were constant activity then you would then be essentially $40 million on a quarter basis below the Q2 guidance for OpEx plus G&S, is that the right way to think about it?

[Jonathan Baksht, SVP & CFO]

Just doing the mental math. Roughly so, right. I think, Ian, we're not guiding beyond Q2 at the moment. We're still working on the full year plan but the way that you're putting together the numbers, we are guiding to 165 of synergies and if you were just to kind of take that by the quarter once you get to the run rate, it is a bit more than $40 million and that will come out of G&A and roughly of a 50% attributable to each one. We won't hit run rates until the end of 2020 on the synergies. So I don't want to it on the path that you should just start applying $40 million a quarter starting right away. It will take some time to get to those. We anticipate that we'll get to that 75% of that run rate about a year from now and full run rate by the end of next year is probably better way to think about it.

[Operator]

And our next question today comes from Connor Lynagh of Morgan Stanley.

[Connor Lynagh, Morgan Stanley]

Wondering if -- obviously, you made clear that you're not planning on reactivating any of the at the moment. Can you talk about the contracting strategy on the fleet? And just broadly can you help clarify not reactivating this year versus not marketing this year? Are you not bidding the preservation into work at the moment? Or is it just that you're not planning on them working in 2019?

[Thomas Burke, President, CEO & Director]

That's a good question. We're definitely still in the middle of planning our marketing strategy and reacting as they come. We do obviously focused on the working assets and then followed by the warm stacked assets -- warm assets. So that is our real focus right now. We always keep in mind that the preservation stacked assets, what they certainly down on the floating assets. Jackups, obviously, as I mentioned in my prepared remarks, we either have everything has a contract or working on a contract. And so we are certainly looking at some opportunities, where we would carefully look at the returns and reactivate a jackup may be 1 or 2 this year, but not sure. And certainly a lot of scrutiny around allocation of capital to reactivation. Connor, did I help you with your question?

[Connor Lynagh, Morgan Stanley]

Yes. I think so. And on the jackup side on things, can you discuss how you think about the potential runway for how much more you could reactivate obviously the market asset is pretty tight at this point? Is there a need to go to the art and acquire new assets at this point? How do you think about that?

[Thomas Burke, President, CEO & Director]

We have an excellent modern assets, which now sort of under the hood and really sort of understanding what we have on the month. And so excited about some of the modern jackups that Ensco has either built or has acquired. So we got some excellent modern assets. And so certainly we always keeping an eye on the shipyard and understanding what's going on there, understanding that. But certainly our focus would be the current assets that we have in our fleet and how we utilize them. And frankly, the assets that we have in the fleet that are warm stacked and modern warm are better than what is in the shipyard.

[Operator]

And our next question today comes from Sasha Sanwal of UBS.

[Sasha Sanwal, UBS Investment Bank]

Thanks for the commentary on a pro forma bidding strategy, something we've all kind of been waiting for some time. So maybe to follow up on Connor's question. Can you maybe give us an update on the reactivation cost, the preservation stacked rig? And then, Tom, you mentioned in your commentary about discipline returns on reactivating jackups, just wanted to get your sense of what the gating factors are in terms of how we should think about reactivation as well?

[Thomas Burke, President, CEO & Director]

Well, one comment. I'll let Carey talk about the reactivation of the preservation stacked assets for a moment. And just one comment on the contracting strategy. So let me talk about a contracting strategy, it's not like we're sitting around and say we should do this rig and that rig. It's a lot more fire than that. It's really an overview of the market, really spending a lot of time building shared understanding amongst the new management team, about the supply and demand dynamics of what we think is going to happen and then using that as the lens to look at the reactivation of the contracting strategy. So we're in the middle of that, and it's a good process. It's a process that Ensco has historically, and it's a very good process. So we're working on that and certainly it's very thorough. As far as the reactivation of the assets, Carey, comment on that.

[Patrick Lowe, EVP & COO]

Yes. So we have a range of cost to reactivate our preservation stacked floaters of between $25 million and $35 million, and that the actual number depends on which rig it is. Some of the rigs are at the lower end of the scale, some are at the higher. This is a 120-day process. We have a very good handle of the condition of these rigs, and we continually update the reactivation cost. We got a track record with ENSCO DS-4 starting it up from preservation stacked under budget and under time and it went to work for in Nigeria and has performed very well coming out of preservation stacked. So we have a good handle on this, and we're confident of the cost and time to reactivate.

[Thomas Burke, President, CEO & Director]

And when we think about -- to answer the last part of your question, when we think about capital allocation towards reactivation, what we are looking at is the supply and demand model. What we think will happen to this asset overtime, and so we fully apply capital. We want to have a good confidence back basically the money will be well spent, and it will have a return. So maybe it won't -- you call justify the reactivation on the first contract, but then do we have high confidence on the second contract. And actually, we have -- in the last 3 weeks, we had a lot of those conversations about here is an opportunity. Yes, we're willing to put this capital potentially on this, but we got to get this contract and this contract. So it's a pretty rigorous approach thinking about making sure that we are getting a good return on the reactivation capital.

[Sasha Sanwal, UBS Investment Bank]

Thank you for that color. Very helpful. And may be just as a follow-up, I'd like to get some context on just how you guys kind of think about essentially the regional mix. And so I think unless you spend a lot of time on day rates sometimes and you kind of miss in terms of cost. And so for example, you referenced DS-9 contract right spend quite some time ago, kind of think about regional cost in areas like Brazil, for example. I think the input cost per rig has gone up versus last cycle, right. And obviously things like scale in terms of share base cost also kind of coming into the mix. So may be beyond looking at day rates, when you think about rate margin for floaters at a high level could be kind of think about the opportunities at in terms of which regions might have a bigger focus for you guys?

[Thomas Burke, President, CEO & Director]

Well, I think it's a good question. And I think one of the thing about the combined company is that the footprint has been, as I mentioned in my comment and as you know is in almost every major basin. And so the cost go into a new region, yes, there is a cost potentially on the rig to become compliant with customer or regional requirements, but there is also whole another cost, which is -- actually typically has a long time line which is getting set up in those countries. And so when we have a footprint in Australia, in Brazil, in Angola, in Nigeria, it actually allows the cost of entry and the ability to move assets from one region to another much more efficiently.

And I have to tell you having worked at the Legacy Rowan, thinking about entering Nigeria or Brazil, the rig modification were the last -- weren't the highest thing on the list. It was getting set up in those countries in such a way that we did it -- we didn't expose ourselves to more regional risk. So I think that we have a very good position that we have a geographic footprint that's been, not in very offshore basin, but certainly the ones that we are focused on. And so as far as the mix of where we would see assets going, we're clearly in the floating assets it's in the Golden Triangle for the Deepwater assets. And I think the 2/3 of contracts today, I guess, between Brazil and West Africa. We also -- in the jackup side, clearly a lot of activity in the Middle East, but also we're seeing some good signs of activity in Southeast Asia. So I hope does that give you a bit of color on that regional mix.

[Operator]

Next question comes from Taylor Zurcher of Pickering Holt.

[Taylor Zurcher, Tudor, Pickering, Holt & Co.]

Tom, you just made a reference in your last response there to wealth of contracts that are coming out of Brazil and you clearly just placed DS-9 then. My question is, it feels like there is all sorts of numbers out there is where Deepwater rig count in Brazil could go in coming years, but it always feels like these things kind of shift to the right. And so wondering if you could give us your take as to, I don't know, maybe over the next 12 to 24 months? Where we could see Deepwater rig demand trend in Brazil in particular moving forward?

[Thomas Burke, President, CEO & Director]

So I think as we think about the Brazilian market, there has perhaps been a lot of activity. I'm just looking for notes there from where it peak to where it is now, but it's obviously is a market with significant potential. As you think the ILC is going into that market, as I alluded to in my comments, it changes the dynamic a bit. And I think it's very positive, because not only will pick up assets, but also will pick up assets. We are seeing -- there are different needs in the market. There are low-end floaters, there are high-end floaters and clearly we have a combination of both. you said that the cost to modify and if the rig is not built in Brazil can be fairly substantial. So I think it's a market. It's hard to say, and we have our own proprietary model about what it's going to do as far as that market and we're not really that -- we're not sharing that. But what I would say is that we are a very positive on the Brazilian market. It's not going to recover overnight, and that is why we kept a good infrastructure there.

[Taylor Zurcher, Tudor, Pickering, Holt & Co.]

Okay. That's helpful. And just a housekeeing follow-up on ARO. You noted that the new build orders are likely to come soon at least for the first two, could you remind us how you're thinking about financing those first couple of orders? I know there is debt within and there is probably bunch of flexibility there...

[Thomas Burke, President, CEO & Director]

Absolutely. So as far as the financing of new build ARO, we are -- there is an issue down payment. We haven't disclosed as of yet what percentage status of the total price, but we are more than able to cover it with cash on hand at I think obviously the award or the placing the order that will be a major milestone will announce that, but certainly the initial financing through -- the initial down payment will come from cash on hand, cash from operations from ARO. And then after that, we will look at the take out financing. We think we'll have a lot of opportunities given the length of the contract and the return profile.

[Operator]

And our next question today comes from Sean Meakim with JPMorgan.

[Sean Meakim, JPMorgan Chase & Co.]

So balance sheet management was noted as a key priority for in terms of capital to be deployed DS-13 upgrades cash out on restructuring, reactivation part of the calculus as well obviously. Just how do you think about free cash flow and your ability to impact that $1.1 billion of maturities coming in the next couple of years with cash flow versus terming them out?

[Jonathan Baksht, SVP & CFO]

Sure. I'll take that one. Sean, I think as I laid on the prepared remarks, we do have a bit of luxury with the position that we're in that we do have a very high cash position right now. We have a very flexible revolving credit facility and the maturity that we've got over the next 6 years of $1.1 billion. So to your point on the free cash flow and how does that fit into the mix, I mean, it's one of the sources or uses of capital depending on what we're talking very short-term or longer-term free cash flow and where those projections come in. But ultimately, we do have a lot of flexibility. And I think as we think about how we're going to manage the balance sheet, if you look at what we had done historically, we've been proactive managing the balance sheet due to the cycle. We're going to continue to do so. And the priorities, as I laid out earlier are going to be really focused on liquidity, on our maturity runway, reducing our long-term debt and lowering the cost of capital. And where that might fit today versus how we might think about 3 months from now, that does evolve. And so we'll continue to be proactive and we'll continue to monitor it based on looking at those priorities.

[Sean Meakim, JPMorgan Chase & Co.]

Okay. Fair enough. And one more on the synergies plan you laid out a lot of good parameters, where would you -- could you elaborate a bit? Where you see the biggest areas for upside versus points of concern? Or thing that you think will be longer and being able to procure?

[Thomas Burke, President, CEO & Director]

I'll comment on that, and Jon you can cover of anything I miss when I But I'd say on the synergies, we feel very confident about the 165 and so I'm not -- there isn't anything too worried about on the downside. On the upside, the areas that we have set for competitive reasons, we couldn't get into as much, it's certainly around supply chain is one big area, because we obviously could not share pricing with vendors, but we had two separate companies. So it's a little hard to work out what the opportunity was even what the spend was. And so we spent time on that now, and I think there is some opportunities there. And in fact, we were quite conservative, very conservative around the supply side -- on supply chain side. The other area is the offshore costs. Again for competitive reasons, we are -- the operating cost of rigs, what we're paying for labor, what we're paying for services offshore, again it's not something we could share even though mining of the of the rigs is something a little bit -- certainly can only be available in clean room as we did the deal. So that's a big opportunity and frankly we were very conservative on synergies in that area. And Jon, anything to add?

[Jonathan Baksht, SVP & CFO]

One thing just to clarify the word when 165 comes from, as I laid out earlier, a lot of that is back office synergies. And so coming out of G&A and just based expenses. So kind of field offices that type of thing that will run through line. And so when you look at the rig base, it's really -- there is really not much accounted for from that aspect. So that is in areas that we will continue to scrutinize.

[Thomas Burke, President, CEO & Director]

Yes. That's a really good point. So certainly our contract expense, our OpEx is broken into onshore and offshore and the majority of our synergies is planned synergies right now and 165 is from that onshore. So the offshore, really we've taken a conservative

[Operator]

And our next question comes from Howard Beale.

[Unidentified Analyst]

Congratulations on closing the deal. Just want to speak about what kind of jackup day rate improvement are you seeing in the market right now?

[Thomas Burke, President, CEO & Director]

It really depends by market, and it depends by the class of assets. So we have ultra harsh, harsh and benign assets and obviously those can also be categorized around the age of them and frankly capability. So I think that certain markets certainly tighter and would be one of those. But there are other markets we're also getting that we talk about the North Sea, because it is getting sizable but we also talk about North Sea because we're not really that excited about talking about what's happening in other markets because we're trying to keep that to ourselves. So -- but we are seeing an improvement and it varies a lot by who the competitive is and how many competitors and how the customer thinks about their contracting strategy. And so it varies, but generally, I would say, we're not seeing pricing go down in any market. In fact, it's going up in all markets, but just it's a relatively different places.

[Unidentified Analyst]

And just piggybacking on Sean's question. So you have about, call it, $1 billion of debt maturities between now and 2022, a peer of yours like refinancing calling in bonds and the refinancing Is that one of the strategies that you guys are thinking? Or can you help me just how to think about what you're thinking about any maturities between now and 2022?

[Thomas Burke, President, CEO & Director]

You just cut out slightly there. Could you just ask the question again.

[Unidentified Analyst]

Sorry about that. Just -- I was just wondering like how do you think about the debt maturities between now and 2022? Can we think about you guys calling those bonds? Or how should we think about those maturities?

[Thomas Burke, President, CEO & Director]

I got it. I'll give you similar answer to Sean. We're not -- I'm not going to give specific guidance on what actions we may or may not take just given that people confront on any transaction that we might talk about. So it's not appropriate for me to provide that specific guidance. But in terms of what are the things we might do and I'll just point back things we've done in the past and things and will be proactive, but historically you point our -- some of our peers, I think, will be less focused on our peers and more of how we would manage things. And in the past, we have called back that we've done over the market repurchases. We've also done tenders. Those are all tools in our toolkit that we can utilize if we were to look at moving some of those maturities -- I'm sorry, moving some of the or reduce that. I should say, reducing some of the maturities between now and 2024, and it's something that we'll evaluate in our overall financial strategy.

[Unidentified Analyst]

Can you say like how much of secured financing capacity you have? Is that we can think about it?

[Thomas Burke, President, CEO & Director]

I can be specific. It's all in our filings. We do have a lot of different debt at this point, I want to go, but the one which is the most significant clearly right now is the revolver. So on the revolver, our secured debt capacity is $1 billion, which we have not utilized. That is an increase from the legacy and scale revolver, which is $750 million. So that did go up as part of the upsizing process we did in conjunction with the merger.

[Unidentified Analyst]

And maybe last question from me on ARO jackups. So my understanding was those ARO jackups would be build in Saudi, the plus -- all 20 would be in Saudi. Is there any change in that strategy? And how should we think about the timing for the next 18 jackups? You mentioned should be anytime soon?

[Thomas Burke, President, CEO & Director]

Certainly, the plan for those jackups is to build in the Saudi, but they're building shipyard right now. And so contracting with IMI, which is shipyard that is being built in Saudi or the company that is building up shipyard in Saudi. And IMI for the first may or will has given those orders to another shipyard, which is and also a partner. And if you got a directing to website a press release, I think, it's December 27 that they received an order from IMI to build 2 jackups basically for -- and the majority of them will be in Saudi. So I think it's a public statement that IMI and have made. Now with that will be -- the first 2 will be built in -- was giving an order to IMI, and IMI is going to build those assets or it might subcontract out the first few, but it would only be the first few like certainly the first few and beyond that remain to be seen.

[Operator]

And ladies and gentlemen, this concludes our question-and-answer session. I'd like to turn the conference back over to Nick Georgas for any closing remarks.

[Nick Georgas, Senior Director, IR & Communications]

Thanks, and thank you to everyone on the call today, for your interest in EnscoRowan. We'll be following up with those of you, who are still in the question queue later today, and we look forward to speaking with you again when we report second quarter 2019 results. Have a great rest of your day.

[Operator]

Thank you. Today's conference has now concluded, and we thank you for attending today's presentation. You may now disconnect your lines, and have a wonderful day.