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Good day, everyone, and welcome to Ensco Plc's fourth quarter 2017 financial results conference call. All participants will be in listen-only mode. Please note this event is being recorded. I will now turn the call over to Mr. Nick Georgas, Director of Investor Relations, who will moderate the call. Please go ahead, sir.
Welcome, everyone, to Ensco's fourth quarter 2017 conference call. With me today are Carl Trowell, CEO; Carey Lowe, our Chief Operating Officer; Jon Baksht, CFO; as well as other members of our executive management team. We issued our earnings release, which is available on our website at enscoplc.com.
Any comments we make about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our earnings 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 earnings release and supplement to our fourth quarter and full-year 2017 earnings release on our website for additional information. As a reminder, we issued our most recent Fleet Status Report on February 20. An updated investor presentation is also available on our website.
Now let me turn the call over to Carl Trowell, CEO and President.
Thanks, Nick, and good morning, everyone. Before Carey takes us through our recent contract awards and Jon gives an overview of our financial results and outlook, I will discuss 2017 highlights and provide some context on the current state of the offshore drilling market.
Beginning with highlights from last year, we completed our acquisition of Atwood in October, adding 11 high-specification assets to our fleet at bottom-of-cycle prices. By purchasing Atwood, we took a critical step forward in enhancing the capabilities of our fleet and positioning Ensco to meet future customer demand.
Over the past few years, customers have demonstrated a preference for the highest specification assets, particularly when contracting ultra-deepwater floaters. And we expect this trend to continue in the years ahead. With the addition of the Atwood fleet, we are better equipped to meet more stringent technical requirements from customers and, in doing so, solidify our position as a key offshore service provider.
Integration efforts continue to progress as planned. And we have completed 80% of our integration work plan. We remain on track to meet our synergy targets of $60 million in 2018 and $80 million annually beginning in 2019. As part of our fleet review following the Atwood transaction, we've decided to retire floater ENSCO 5005 and recognize a noncash impairment charge primarily related to noncore floaters based upon our assessment of the remaining useful lives of these rigs. We will continue evaluating our fleet structure and acting opportunistically to streamline our fleet.
During 2017 we improved our operational and safety performance, further differentiating Ensco's service offering from the competition. Operational uptime for the year was 99% for our contracted rigs, the second consecutive year we have performed at this level. With respect to safety, we achieved new company records for total recordable and lost-time incident rates, both of which were significantly better than the industry averages. Importantly, we continued to improve our safety results whilst the industry performance worsened year over year. These results contributed to our customers rating Ensco number one in total satisfaction for the eighth consecutive year in the leading independent industry survey. Along with total satisfaction, Ensco earned the top rating in 11 other categories.
Delivering operational and safety performance at these levels strengthens our relationship with customers, which improves our ability to win new work for our rigs. To this end, we won 15% of new rig years awarded globally in 2017, more than any other offshore driller, and double that of the nearest independent competitor. Investments in systems, processes, and training aimed at making our rigs safer and more efficient also benefited our results. In particular, investment in our Ensco asset management system led to increased reliability and lower cost to service our equipment. We recently launched a predictive maintenance initiative, the Ensco Predictive Intelligence Center, and we'll continue to implement this system across our fleet as we move from traditional time-based maintenance to a reliability-centered maintenance model. We are also merging several operational systems into an integrated digital platform that we expect will create additional efficiencies in our daily operations.
We continue to advance our research and development with a focus on innovations that can be retrofitted to our existing rigs and make the drilling process more efficient. These efforts have expanded our intellectual property library, which now includes 30 patent filings since the beginning of 2015. We plan to pilot some of these new technologies on rigs during 2018 and expect to provide more details on our progress and results in the future.
In terms of our financial position, we completed a debt offering in January, issuing $1 billion of senior notes and a subsequent tender and redemption that reduced our nearest-term maturities by $650 million. As a result, we now have just $308 million of debt maturing over the next six years, giving us the financial flexibility to persevere through the market cycle and continue positioning Ensco to capitalize on opportunities as the offshore sector recovers. In summary, these actions have increased the capabilities of our rig fleet, improved our operational and safety performance, and strengthened the balance sheet, which has contributed to our contracting success as we bridge our high-specification assets through to better market conditions.
Moving to the broader market environment, we see positive signs for the offshore sector, including constructive commodity prices, attractive breakeven economics for offshore projects, and rig retirement. These factors have created a more favorable backdrop for the supply-and-demand dynamics for the offshore drilling rigs, and we believe the early stages of a recovery are taking hold.
The shallow-water jackup segment is further along this process. We expect several longer-term contracts in the Middle East will be finalized in the coming months, including multiyear contracts for ENSCO 140 and 141. We have seen increased activity in the North Sea and the Gulf of Mexico for shorter-term work that is expected to improve 2018 utilization prospects for our jackups in these regions. In Asia, we see several opportunities. And while we expect conditions remain competitive, we currently have just one marketed high-spec jackup in the region without a contract. With several rigs expected to commence new contracts by the middle of the year, we anticipate utilization for our marketed jackups will improve in the back half of 2018.
Floater market is also improving. Though given the longer lead time for projects in the deeper water, the recovery for this segment of the market is in a much earlier phase. Recently, lease rounds in Brazil and Mexico drew high levels of interest from many IOC customers, with six pre-salt blocks awarded offshore Brazil and 19 deepwater blocks awarded offshore Mexico. We anticipate these regions will drive additional floater demand in the coming years, and we are participating in tenders in these markets that require rigs for work commencing in the second half of 2018 and into 2019. Furthermore, two large IOCs recently announced major deepwater discoveries in the U.S. Gulf of Mexico, underscoring the economic potential of this basin. And several independent operators have short-term opportunities that we expect will lead to contracts, both of which bode well for future rig demand.
While the longer-term demand prospects have improved for the floater market, the primary issue is that of rig supply. As a result, a more sustained recovery for this segment of the market is not expected until 2019, when we expect to see utilization improve before pricing power returns thereafter. It is important to note that despite a higher oil price and increasing customer demand, the market for both jackups and floaters remains extremely competitive. We expect these conditions will persist through 2018, and in most cases new contracts signed for work beginning during the year will provide limited cash margin.
In addition to these industry dynamics, our 2018 financial results will be influenced by the expiration of current contracts with above-market rates and gaps in utilization as rigs complete contracts. As a result of these factors, we expect our full-year 2018 revenues will be between $1.72 billion and $1.8 billion. Jon will provide a more detailed outlook for the first quarter later in the call.
While we expect that 2018 will be another challenging year from an earnings standpoint, we believe that customer activity has bottomed and the market is recovering. This recovery will be protracted and phased, and we have a way to go before supply and demand balances to a point that pricing power returns. But we've seen the first steps in this process. As this process unfolds, we will continue to focus on improving operational and safety performance, executing on our digital transformation and innovation initiatives, and winning new work for marketed high-specification rigs. By executing on these strategic objectives, we ensure that we are prepared for higher levels of customer demand as the market recovers, and we solidify our position as the leading provider of offshore drilling services.
Now I'll turn the call over to Carey.
Thanks, Carl. I'd like to start by detailing a couple of points that Carl touched on. 2017 marked another year of significant achievements for Ensco, most notably in operational and safety performance. Our offshore crews and onshore personnel delivered near-perfect operational utilization of 99% across the fleet for a second consecutive year. In addition to high levels of operational performance, our crews continued to be laser-focused on safety, improving our total recordable incident rate by 42%, establishing a new company record and beating the industry average by nearly 60%.
Our customers continue to recognize Ensco as the leader in offshore drilling, rating us number one in total satisfaction in the annual EnergyPoint survey for the eighth year in a row. In addition to total satisfaction, customers rated Ensco the top offshore driller in 11 other categories, including safety and environment, performance and reliability, job quality, technology, plus several other technical and geographical categories.
In addition to improving our safety and operational performance, we continue to selectively invest in innovations and technologies capable of improving the efficiency of our customers' drilling programs. Recently we expanded our intellectual property library by filing five patent applications for innovative technologies, and we plan to pilot some of our IP on rigs soon, starting with ENSCO 123. We have elected to defer the rig's delivery to first quarter 2019 in order to outfit it with the necessary equipment for this pilot program, which is aimed at reducing the amount of time spent tripping pipe while drilling. We have been encouraged by our progress to-date and expect to provide you with updates on this project later this year.
Customers also recognized Ensco by awarding us new contracts during 2017. These contracts and extensions added more than $750 million of backlog during the year as we continued to leverage our competitive advantages to win new work and position our fleet to meet higher levels of customer demand. We won several contracts and extensions during the fourth quarter that contributed to these full-year results. In addition, we are in advanced contracting discussions with a customer in the Middle East for ENSCO 140 and 141, and both rigs are undergoing preparations with the expectation that they commence multiyear contracts in the region later this year. Also, in the Middle East, ENSCO 104 received a 16-month contract for a repeat customer, as the rig's operational history with the customer, including 99% uptime during its previous contract, were factors that contributed to us winning this work.
The Middle East continues to be the most resilient jackup market worldwide and an important region for Ensco, with 10 rigs in the market, all of which are expected to be under contract during 2018. As disclosed in our previous earnings call, ENSCO 109 received a one-year extension offshore Angola. As part of this extension agreement, the rig went on a five-month standby rate beginning in mid-October 2017, followed by a 30-day special periodic survey, and is expected to return to work from April of this year through July 2019. In Australia, jackup ENSCO 107 was awarded a five-well contract that is expected to start in May and end in fourth quarter 2018. Floater ENSCO 8504 won a five-well contract offshore Vietnam that is scheduled to begin in April and end in October.
ENSCO DS-10, our recently delivered drillship, is currently mobilizing to Nigeria in advance of its maiden contract, which is scheduled to begin next month. When preparing a newbuild for its initial contract, we follow detailed operational plans and perform rigorous acceptance testing so the rig delivers high levels of operational performance when commencing operations. We take a similar approach when we reactivation of preservation stacked rigs, as was the case with our reactivation of ENSCO DS-4. Our crews successfully returned the rig to the active fleet on-time and on-budget. And it has since delivered outstanding performance for its customer offshore Nigeria, with operational utilization in excess of 99% and its initial wells completed ahead of the customer's drilling curve.
Moving to the North Sea, ENSCO 121 and 122 received short-term extensions that will keep the rigs on contract through the middle of 2018. And we are encouraged by opportunities to contract these rigs' remaining available days in 2018. And, finally, in the Gulf of Mexico, several of our rigs received short-term contracts, including floaters ENSCO 8503 and 8505, as well as jackups ENSCO 68, 75, and 87. Additional details can be found in the Fleet Status Report issued last week. As Carl mentioned, recent developments are supportive of increased future drilling activity in the Gulf of Mexico, including two large deepwater discoveries by major operators and Mexico's second deepwater licensing auction, which saw 19 blocks awarded and commitments for 23 additional deepwater exploration wells.
Moving to global rig supply, offshore drillers have now retired more than 100 floaters since the beginning of the downturn, roughly 34% of the supply at the time. And 40 jackups have been permanently removed from the global fleet over this same period. While a great deal of rig attrition has already occurred, we continue to believe this trend will continue, as a substantial number of older, less-capable rigs remain idled or will see their contracts expire in 2018 without follow-on work. We have identified approximately 60 additional floaters and 190 jackups in the global supply that are at risk of being retired in the coming years. These rigs are relatively disadvantaged as compared to more modern, technically capable units, and will be increasingly challenged to find new work. Idle rigs over 30 years of age are particularly susceptible to higher reactivation costs, as the maintenance is deferred during uncontracted periods, making it increasingly difficult to meet the economic hurdles required for reactivation.
On the demand side, indicators of increased customer activity in both the short and long-term continue to track higher compared to a year ago. In the shorter-term, the number of rig years awarded globally through new contracts has doubled as compared to a year ago. Furthermore, operators ended 2017 having sanctioned 29 offshore projects, more than twice that of 2016, while significant recent discoveries in the Gulf of Mexico and successful licensing rounds in Brazil and Mexico also point to increased drilling activity in the future. While further rig retirements and increased customer demand are required for the offshore rig markets to balance, we are seeing gradual improvements in both the supply and demand sides of this equation.
Meanwhile, Ensco continues to consistently deliver the highest levels of service quality and operational excellence, leveraging our strengths to win new contracts. We are committed to increasing the efficiency of our customers' offshore programs through improvements in the drilling process and investments in innovation and technology. We believe these efforts will help us remain the offshore driller of choice among customers and improve our ability to win more work as the demand for offshore drilling rigs increases.
Now I'll turn it over to Jon.
Thanks, Carey. Before I begin, I'd like to note that my prepared remarks will be somewhat longer than usual, as in addition to providing a review of our fourth quarter financial results and 2018 outlook, I'll discuss some recent developments, including the Atwood acquisition, enactment of new U.S. tax legislation, and our recent financing transactions. To help facilitate this, we prepared a supplementary slide presentation that I will reference during the call, which provides additional color on these items. This supplement, along with our earnings press release, can be found on the Investor page of our website. As a reminder, we closed the Atwood acquisition on October 6, 2017, and the fourth quarter represents the first quarter of results for the combined company.
Starting with fourth quarter results versus prior year, we reported a loss of $0.49 per share compared to earnings per share of $0.13 in the year-ago period. Please refer to our press release and slide 2 of our supplement for a list of the items influencing these comparisons. Excluding these items, an adjusted loss from continuing operations of $0.23 per share compared to adjusted earnings from continuing operations of $0.09 per share a year ago. Total fourth quarter revenue was $454 million versus $505 million last year.
In the Floaters segment, revenue was $303 million, equal to a year ago, as the decline in the average day rate to $307,000 from $358,000 was offset by an increase in the number of operating days, primarily due to the acquisition of Atwood. Operational utilization for the Floaters segment, which adjusts for uncontracted days and planned downtime, was 97% compared with 98% a year ago.
In the Jackup segment, revenue was $137 million, compared to $187 million a year ago, mostly due to a decline in the average day rate to $76,000 from $101,000 in fourth quarter 2016. Operational utilization for the jackup fleet was 98%, compared with 96% a year ago. Revenue from the acquired Atwood rigs was $23 million and is reported net of intangible asset amortization of $16 million. Under purchase accounting rules, the drilling contracts that were acquired are measured at fair value based on market rates at the date of acquisition. Since we acquired drilling contracts that were above current market rates, we established a contract intangible asset that will be amortized against revenue over the remaining term of those contracts. Excluding this noncash amortization, day-rate revenue for the former Atwood rigs was $39 million during the fourth quarter. The remaining amount of contracted tangible asset amortization is $17 million and will be spread over 2018 and 2019. Please refer to slide 3 of our supplementary slides for an estimate of contracted tangible asset amortization by quarter going forward.
Moving down the income statement, total contract drilling expense increased to $334 million in fourth quarter 2017 from $289 million a year ago. A $53 million of legacy Atwood rig costs and $7 million of integration-related transaction costs were partly offset by disciplined cost management including savings from more efficient stacking of rigs. In fourth quarter 2017, we recognized a noncash asset impairment charge of $183 million. We evaluate our fleet for a triggering event on a quarterly basis, and if our assumptions regarding an asset's marketability and useful life is significantly changed in light of our business outlook, we may perform an impairment test that results in significant impairment charges. As Carl mentioned earlier, the impairment charge primarily relates to changes in our useful-life assumption for two noncore floaters.
Fourth quarter depreciation expense increased to $120 million from $110 million a year ago due to the addition of 11 Atwood rigs. Excluding Atwood-related transaction costs, general and administrative expense increased to $29 million in fourth quarter 2017 from $25 million a year ago, primarily due to $4 million of corporate support costs from Atwood. Transaction costs of $49 million were $11 million lower than fourth quarter guidance due to the deferral of $8 million of integration costs to 2018 and $3 million of cost savings. A breakdown of actual transaction costs to date and expected future impacts by quarter, as well as the split of transaction costs between contract drilling expense and G&A, are presented on slide 4 of the supplement to our earnings press release.
Interest expense was $57 million, net of $18 million of interest that was capitalized, compared to interest expense of $56 million in fourth quarter 2016, net of $9 million of interest that was capitalized. Fourth quarter 2017 other income included a $140 million bargain purchase gain recognized upon closing the Atwood acquisition, representing the excess of the estimated fair value of assets and liabilities acquired over and above the aggregate value of merger consideration. Please refer to slide 5 of the supplement for a rundown of the net assets acquired, which are now included in our consolidated balance sheet.
Effective December 22, 2017, the U.S. enacted significant changes to tax law, including a reduction in the statutory income tax rate from 35% to 21%, the introduction of a minimum tax on certain payments to non-U.S. affiliates, new and revised rules related to the taxation of certain income from foreign subsidiaries, and a one-time transition tax on deemed repatriation and deferred foreign income of U.S. subsidiaries. Some of these changes impacted our fourth quarter 2017 results, contributing to our increase in tax expense to $42 million from $4 million a year ago.
The fourth quarter 2017 tax provision included $19 million of discrete tax expense compared to $7 million of discrete expense in the year-ago period. Fourth quarter 2017 discrete tax expense included $17 million related to the enactment of U.S. tax reform, consisting of a $39 million one-time tax expense associated with the repatriation of unremitted earnings of foreign subsidiaries of our U.S. companies; a $17 million expense resulting from revised rules for the taxation of income from foreign subsidiaries applied retroactively from January 1, 2017; a $20 million tax benefit due to the measurement of deferred tax assets and liabilities at the reduced U.S. tax rate of 21%; and a $19 million tax benefit resulting from adjustments to the valuation allowance on deferred tax assets.
While tax expense for the fourth quarter increased as a result of these changes, there will be no cash taxes to pay in connection of these items, as we have tax losses available to offset these charges. However, as a consequence of the changes in tax law, particularly provisions regarding the taxation of certain income from foreign subsidiaries and a base-erosion anti-abuse tax that imposes a minimum tax on certain payments to non-U.S. affiliates, or BEAT, as it is more commonly referred, it is likely that we'll be subject to increased taxation in the U.S. beginning in 2018 despite a reduction in the tax rate from 35% to 21%. We continue to analyze the changes in U.S. tax law and expect to provide additional guidance on the impact to our full-year 2018 tax provision on our first quarter conference call.
Before I move to the sequential quarter comparisons, I would note that we have begun reporting adjusted EBITDA figures beginning with our fourth quarter results. We have started reporting this metric, as we believe it will be useful for investors when analyzing our core operating performance and cash flows. Adjusted EBITDA for fourth quarter 2017 was $93 million. A reconciliation of net loss to adjusted EBITDA is presented on slide 6 of our supplement presentation.
Now let's compare our fourth quarter 2017 to third quarter 2017 sequentially. Revenue decreased by $6 million, primarily due to ENSCO DS-7 completing its contract offshore Ivory Coast and ENSCO 109 moving to a lower standby rate. This was partially offset by $23 million of revenue from the newly acquired Atwood rigs. As mentioned previously, revenue from the Atwood rigs was recognized net of contract intangible asset amortization of $16 million. The average day rate decreased to $157,000 from $166,000, and utilization declined 5 percentage points to 50%. Contract drilling expense increased by $48 million sequentially, primarily due to the addition of Atwood. Excluding $7 million of integration costs, contract drilling expense of $327 million for fourth quarter 2017 was lower than the prior guidance of $335 million, due to disciplined expense management that included lower support costs resulting from the timely realization of synergies, lower daily operating expenses, and stacking costs, due to continued focus on cost control and further rationalization of maintenance projects. As mentioned previously, we recognized an impairment charge of $183 million during the fourth quarter, compared with no impairment charge in the prior quarter.
Depreciation expense increased by $11 million sequentially due to the addition of the Atwood rigs. And G&A expense, excluding transaction costs, increased to $29 million in fourth quarter 2017 from $25 million in the prior quarter, primarily due to the addition of corporate support costs from Atwood. Fourth quarter G&A was $1 million lower than our prior guidance due to the timely realization of synergies. Transaction costs for the Atwood acquisition increased by $44 million sequentially, as the majority of these costs were recognized upon closing in October. Interest expense increased by $9 million due to a decline in capitalized interest and higher fees for the extended revolving credit facility. As mentioned previously, fourth quarter 2017 other income included a $140 million bargain purchase gain related to the Atwood acquisition. Tax expense increased to $42 million in the fourth quarter from $23 million in the prior quarter, primarily due to discrete tax items related to the enactment of new U.S. tax legislation.
Moving to our outlook for first quarter 2018. We anticipate that revenue will decline by approximately 8% from fourth quarter levels of $454 million, primarily due to lower revenue from ENSCO DS-7, which completed its contract during fourth quarter 2017, and ENSCO DS-6, which is expected to complete its current contract later this quarter. Excluding integration-related transaction costs, we anticipate that first quarter contract drilling expense will be approximately $320 million, a decrease of $7 million from fourth quarter 2017. This is mostly due to a $9 million decline in maintenance costs, primarily related to ENSCO DPS-1 contract preparation and a $3 million decline in reactivation expenses related to various rigs startups, partially offset by a $5 million increase in stacking costs and the commencement of the holding period with the shipyard for ENSCO DS-14. The decline in expenses from contract roll-offs is offset by startups in a number of contracts, as detailed in our Fleet Status Report.
Depreciation expense is expected to decline by approximately $5 million to $115 million due to the impairment charges recognized in fourth quarter 2017. G&A expense after excluding transaction costs is expected to decline to $27 million from $29 million during the prior quarter, primarily due to the realization of synergies from the Atwood acquisition. We now anticipate total transaction costs of $98 million, inclusive of severance costs, professional fees, and lease termination expenses. While the majority of these costs were incurred in 2017, we expect $12 million of expense in first quarter 2018 declining to $4 million in the second quarter, and a nominal amount in the second half of the year, as outlined in slide 4 of our supplement presentation. We expect that interest expense will increase to approximately $66 million from $57 million in the fourth quarter, primarily due to higher interest expense from the issuance of new senior notes earlier this year. We anticipate the first quarter tax provision will be approximately $16 million. As previously mentioned, we expect to provide a full-year 2018 estimate on our first quarter earnings conference call.
Turning now to a summary of our financial position. In January 2018, we opportunistically issued $1 billion of 7.75% unsecured senior notes that mature in 2026, and launched a tender offer for outstanding senior notes due between 2019 and 2021. In February, we repurchased $650 million of principal for $693 million of cash consideration. As a result of these actions, we now have only $308 million of debt maturities due through 2023 and have retired all of the outstanding 2019 senior notes. We expect to recognize a pre-tax loss on debt extinguishment of $18 million during first quarter 2018. And we anticipate the annual cash interest expense will increase by approximately $32 million to $303 million. Most importantly, the net impact of these actions reduced our nearest-term maturities by $650 million and increased our cash balance by $276 million. Adjusted for these recent financing transactions, our pro forma liquidity at year-end was $3.2 billion, including approximately $1.2 billion of cash and short-term investments and $2 billion available under our revolving credit facility. Please refer to slide 7 of the supplement to our earnings press release, which sets out our actual and pro forma liquidity and capital resources.
Under the extended revolver, we have borrowing capacity of $2 billion through September 2019, $1.3 billion from October 2019 to September 2020, and $1.2 billion from October 2020 through September 2022. Importantly, the revolver has no covenants based on operating cash flows, and we maintain the flexibility to raise additional capital through asset sales and a secured debt basket of $750 million. In addition to this liquidity, we have $2.8 billion of contracted revenue backlog, to which we added more than $750 million during 2017. Our pro forma net debt is approximately $3.9 billion, and we have a net debt to capital ratio of 31%. Since the beginning of the downturn, we have completed several transactions that have helped to increase liquidity by approximately $1 billion and reduced our near- and medium-term maturities from $4 billion to just $308 million. These capital management actions have significantly improved our liquidity and extended our runway, giving us increased financial flexibility and a competitive advantage as we look to capitalize on improving market conditions.
Moving to our capital expenditure outlook, we expect total CapEx for 2018 will be approximately $475 million, including $95 million of expenditures previously outlooked for 2017 that were deferred to 2018, approximately $100 million of sustaining and minor upgrade CapEx, and $20 million of capitalized interest. The addition of Atwood increased 2018 CapEx by approximately $25 million, inclusive of a milestone payment of $15 million for ENSCO DS-14 that is payable in the second quarter. In January 2018, we paid $208 million of the $217 million unpaid balance for ENSCO 123. We agreed to delay delivery of the jackup until first quarter 2019 as we install and pilot patented technologies on the rig while it remains in the shipyard. The outstanding balance will be due upon delivery.
Beyond 2018, our only remaining newbuild capital commitments are for drillships ENSCO DS-13 and DS-14, which total approximately $250 million, excluding interest and holding costs. As a reminder, these rigs are scheduled for delivery in 2019 and 2020, respectively. The remaining milestone payments for these drillships bear interest at 4.5% per year, which accrues during the holding period until delivery. Upon delivery, the final milestone payments, along with accrued interest charges, may be converted into a promissory note bearing interest at 5% per year with the December 22 maturity, providing us with added flexibility as we manage our liabilities. If we were to elect to pay for these two drillships with the financing option, payment to the shipyard, including accrued interest for both rigs, would total $316 million in December 2022.
In closing, we believe that 2017 will prove to have been a pivotal year for Ensco. While we expect that the recovery is likely to be protracted and phased, we believe that the offshore sector has entered a different point in the cycle and that the actions we have taken position us to thrive as this recovery process plays out.
Now I'll turn the call back over.
Thanks, Jon. Laura, at this time, please open the line for questions.
Thank you. And our first question will come from Gregory Lewis of Credit Suisse.
Yes. Thank you and good morning. I guess, Carl – I mean it's been out in the market now for over a month, regarding the DS-8. You kind of laid out pretty clearly what types of options that contract is looking at. Realize that you probably can't say much. Can we think about – is this something that is going to be an overhang for an extended period of time, or is there something where, one way or another, we would expect Total and Ensco to come to a resolution around the DS-8 sooner rather than later?
Yeah. Morning, Greg. I think, first of all, probably to put it in some context, this is not the first time we've been through these conversations. We've entered into discussions with the client in this particular case, and with other ones where we have longstanding relic contracts, quite frequently. So it's not unusual in that context. We specifically called it out because, of course, we were in the capital markets in January, and it was an element that we felt that we needed to disclose. But it wasn't that it was a particularly unique situation.
I can't go into the exact details. I think that it will probably be resolved one way or the other during Q2. And I don't think it's out of the ordinary to the type of conversations we've had in the past. And, as we've said before, if there is an agreement to be had here that's mutually beneficial such as a sensible blend-and-extend or some form of extension onto the contract, then we will happily entertain that with the client if we can come up with a win-win. If not, we have good, strong contract protections on that contract, as we've announced. So I think it will be resolved one way or the other within probably the next quarter.
Okay, great. And then just – you mentioned that, and clearly this contract was signed in better times – wow, seems like forever ago. As we think about – it clearly sounds like customer inquiries are getting better. You guys on prepared remarks mentioned, hey, maybe we're starting to turn a corner. While pricing still remains something that seems to be in the far-off distance, from a contract negotiation standpoint, is the language in the contracts starting to return maybe to a normal world where the drillers are a little bit more protected? Is that something that's at least starting to take hold in some of these contract negotiations?
No, I think – clearly as we've gone through the cycle the last couple years, and the weight of negotiating position has swung towards the customers, we've seen a deterioration in the protections in the contract, principally around early termination. As we've said before, what we haven't done is had to sacrifice anything around legal protections, transferring excessive risk, or liabilities. But the principal reason has been around, often, termination protection, being paid for mobilization, and in some cases upgrades that's required to get the rigs there.
I think what we are seeing – and those haven't materially changed in the contracts that are leading at the moment. What has been changing a bit is our ability to walk away from contracts if we think that they're too onerous, or that we can't get a little bit of better language because the feeling is something else will be coming around the corner. So we haven't seen anything materially change in the current contracts, but what we have seen is a little bit of a change in psychology from ourselves and from some of our competitors about picking and choosing which contracts to enter and under what terms.
Okay, perfect. Hey, thank you, guys, very much for the time.
Thanks, Greg.
The next question comes from Haithum Nokta of Clarksons Platou Securities.
Hi. Good morning, guys. And I want to say congrats on executing with the bond offering and all the financial management you've done recently. I did want to ask on the fleet mix. In prior calls, you've talked about a comprehensive fleet review following the Atwood acquisition. Can you give a status of where we are there? And I guess specifically around your older jackups, do you feel – where do those fit in the Ensco fleet over the coming couple of years?
Okay. So, yes, we did say that post-Atwood, we would sit back and have a look at the broader fleet. We now have 62 rigs in that structure, makes us the largest offshore driller by fleet size, which means that that gives a degree of flexibility about being able to continue to manage the fleet, make changes on the edges without fundamentally changing our platform, our footprint, and the mix of assets that we have. On the back of that, I think, the two major decisions that we did take was to decide to retire 5005. And I think that's indicative of the future of some of these older, less capable floaters that exist out there. And we decided that that was a rig where we couldn't justify any further investment in capital. What we also did, as you saw, is that we took a look at the future life of some of the rigs that we have currently on contract and decided that that was probably shorter and therefore we took an impairment on two other of our older, noncore floaters.
With respect to the jackups, we've already taken a lot of hard decisions and removed a lot of the older jackups from the fleet. Ones that we currently have in, we think, have got viability going forward. But clearly, there are several rigs there in the older category which we are going to let run through their current contracts, use them to generate cash, and then when they come to the end of their current contracts, we're going to take very careful, judicial looks at them. And if we can recontract them without them requiring major – further capital spending, then we'll keep running them. Otherwise, some of them we may retire at the end of their contracts. But we're talking about a very small number.
Okay. Thanks for that. And then second question is around the newbuilds DS-13 and DS-14. Just wanted to get a couple of questions related to those rigs. If I understand, are you most likely to take the yard financing that's provided for those rigs? And I'm curious how having those units in the hopper kind of impacts your M&A decisions, and kind of also do you expect to upgrade these units in any way or add different capabilities that you would like to take that opportunity to do?
Maybe I'll answer a little bit on the last questions. And then Jon can talk a little bit on the financing issue. Firstly, those rigs we have a good -
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Okay. I'm sorry. I think we lost the line. So let me just backtrack where we were. So I'll just answer a little bit on the ships, and I'll let Jon talk about the financing. So, first of all, just to reiterate, DS-13 and DS-14 are some of the most capable rigs in the entire global fleet. So there is very little that we need to do to actually bring them out. And so at this point there is no major plan to upgrade them in any way. Now, we have talked about some of the technologies we've been trialing. If for instance some of those proved to be really successful, and that we have big client uptake for them, then we could consider retrofitting some of those to DS-13 and -14. But that's not currently in the plans.
We also have a strong agreement with the shipyards, which means that we can keep them there at low cost, and we have no intention to market those rigs at this point. So what that means is that our main high-capacity drillships that are market facing at the moment are DS-9 and DS-11 and they're the ones that we are primarily marketing for the current deepwater drillship contracts. Jon?
Yeah. And from a financing standpoint, fortunately we do have a lot of flexibility on those, so we don't have to declare whether we're going to convert those into the promissory notes until those rigs are scheduled to delivery, which is one and two years out, respectively. And so, for the time being, the base case is still that we would pay those, but we can convert those to the promissory notes with 5% interest with a maturity of December 2022, which if you look at some of even the financing we just did, which was at attractive rates, the 5% is still a fairly attractive rate. So it does provide us a lot of flexibility. And at the time of delivery, we would contemplate using that option to roll those over.
Great. Appreciate the thoughts.
Thank you.
And our next question comes from Ian Macpherson of Piper Jaffray.
Hi. Thanks. Just a quick guidance follow-up. Carl, you opened up with some revenue guidance for the year, and then we got the corresponding cost guidance just on a Q1 basis. So I know if you'd wanted to guide the full year on costs, you would have. But just thinking directionally, I would envision more rig days in the second half of the year, or just more rig days progressively through the year to think about the volume trend of operating costs from Q1 into later quarters. Is that fair?
Broadly, yes, Ian. And just to give a little bit more outline on that, we're still in the mode of not giving full-year guidance just because of where we find ourselves in the market and how quickly things are changing. But we did give a revenue guidance partially because we felt that some of the market commentators have probably built too much revenue in for this year. And as such, the consensus was a little bit high from what our predictions were. And that's largely driven by the fact that I think people have just got a little bit ahead about how fast some of these new contracts will come into place. We do anticipate winning more. We have built into our forecast new work coming for the second half the year, and we do anticipate winning some more contracts over the next few months. But several of those probably won't mobilize or become active until the tail end of the year. And as such they don't have a great influence on 2018 revenue as much as they do 2019.
So that's the reason we gave the revenue guidance, just to kind of align that a little bit. But the general essence of the market trajectory we agree with. And we do anticipate – if we stay in the type of market conditions we see today, we do anticipate more rig days and utilization beginning to pick up in the second half of the year.
Okay. Thanks. And then for a follow-up question, just maybe you could compare the pricing broadly, the pricing environment for premium jackups versus ultra-deepwater, specifically rigs in your 120s class, your 140s class, where you had some contracts pending. Is it fair for us to think about day rates there that are still historically low – and I would think that's under $100,000 a day easily – but at probably better cash margins than is typical for most asset classes right now? Is that a correct way to think about it?
Okay. So, again, we're not going to give a tight guidance on this. But. So, first of all, there is a difference between pricing between the jackup segment and the floater segment. In the jackup segment, it does look like pricing has bottomed out at still, in most cases, quite reasonable cash-generative levels. Most contracts being signed today, we haven't seen too much pricing movement. But what we have seen – there are a few geographies around the world where it does look like pricing has come off bottom, or beginning to. And the higher-capability, harsher-environment jackups is one of those. The North Sea in that area for heavy-duty jackups is beginning to improve, look better. And we see some other geographies where we're beginning to test a little bit of pricing. I think it will be modest in 2018 and, as we said in the prepared statements, that we will be looking really into 2019 before we began to feel that we would see any real pricing changes in the jackups. But we are beginning to see things come off bottom in a few places. And the cash generation in the segment you called out is still pretty good.
The floaters are different. And I think as we said in the pre-prepared statement, that most contracts that are going to be put in place and start in 2018 are at close to or limited cash margin. We need to see a bit more of a pickup in customer demand and we need to see a little bit more of attrition before we can start to see a position where we would feel that you could test pricing. But we do think that based on the current tender and inquiry levels that we're going to start to see utilization pick up in 2019. Now, what we are doing is we are – been getting more selective now, particularly in the floaters segment, about which contracts we bid on and at what pricing levels we bid on them, mainly under the view that there's more options now, so you don't have to chase every single thing that's out there.
Well, that's something. Very helpful as always. Thanks.
And the next question comes from Waqar Syed of Goldman Sachs.
Hi, Waqar.
Hi. How are you?
Very good.
My question relates to 5004 floater. You're retiring the sister rig. This rig's contract ends kind of midyear. Do you see the future for this rig, or after the contract ends, you think that this may be stacked or retired?
Waqar, I maybe missed that, but are you referring to 5004?
That is correct. Yes.
Yeah. Yes, I think at this stage, we see opportunities around the Med area for that rig potentially to work on. We also have a replacement strategy to upgrade it with another rig if we don't find the new contracts for it. So I think 5004 for us is a little bit of a swing rig, depending on how quickly we see the market recover.
Okay. And then some questions on your 8500 Series rigs that have the capability for conventional mooring. Just from my understanding, when you're bidding them for conventional mooring work, do you maintain the DP certification and the subsea engineers on the rigs, or you let those people come off and you go into complete concessional mooring more and maybe reduce costs substantially?
Waqar, this is Carey. We do keep our personnel onboard. There are some natural cost savings that come from not running all of your DP equipment, let's say, and your power system. But some of those rigs are actually going from one well that's moored, and the next well could be DP'd. So we keep them onboard.
Yeah. We keep them onboard. We keep them in certification, because, as Carey said, there's often flexibility between the – the real niche that those rigs have found is where they're working between moored and DP contracts on different wells. I'll just use the opportunity to explain a little bit more of our fleet strategy around the 8500s. We don't intend bringing out any of the other rigs that are stacked at the moment until we see market conditions improve. We are going to market the ones – the three that we have out, and we'll look for better utilization and longer-term contracts on those rigs before we bring out any of the further 8500s. So we're going to maintain quite a difference between what is our marketed fleet and what is our stacked fleet. And then secondarily on that issue, it's very likely that as we bring out those additional 8500s, we will bring them out with mooring adaptions.
Great. Very helpful. Thank you very much. That's all I have.
Thank you.
The next question comes from Colin Davies of Bernstein.
Good morning. The conversation around evolving contract structures and the dynamics of the negotiation with customers is very interesting. But the piece I'm quite curious about is we've heard from others of potential longer-term tenders may be starting to come forward in the floater market. So, firstly, are you also seeing that, and how do those conversations go? Is it simply customers trying to lock in their rig portfolio at low cost long-term, or is there some reasonable conversation starting to occur around inflation in the sort of 2019, maybe even 2020 period, of inflation on priced options, and those types of structures?
Yeah, Colin. Broadly, we are seeing an increased number of tenders and inquiries now for longer-term floaters, which is something that's really developed over the last two or three quarters. That's been driven by two things. The first is that several of our customers have deferred out projects that they really need to do for as long as they can, and are beginning to need to – now to contract rigs for those. The second one is what you referred to, which is actually customers' beginning to see that they might have bottoms in pricing, and beginning to try and lock in pricing.
The discussions around how you tender those, and the negotiations with clients, are very mixed. And I think you've probably hit upon one of the hardest decision processes that we have at the moment, which is exactly how to price the out-years. In general, we are trying to price increased stepped pricing, not locking in at one low future rate – certainly for those contracts that are longer – or to bid differential pricing structures depending on whether it's for one to two years or three-plus years. And it's somewhat different in each case. But, quite clearly, if you're on the customer side of the table and you do have the ability to go award a long-term contract, they are trying to lock them in at the lowest rates that they can.
Yeah. That's helpful and understandable. And then in terms of some of the conversations that were occurring at the time of the Atwood transaction, the push, obviously – and I think you'd articulated, the priority – was to really build up the backlog on those Atwood rigs given the quality. Perhaps you can give us a little bit of an update on the strategy there vis-à -vis trying to get exposure to lock into some longer-term business, or whether it's really just a scramble to get that backlog filled in on a bunch of shorter-term opportunities.
No – firstly I think we have split our fleet into a marketed and effectively non-marketed fleet at the moment. And a lot of the rigs that are in the non-marketed fleet or are stacked, we are going to keep them stacked for a while and only release them into the market in a very controlled manner as we see better conditions. So that means our focus is on our market-facing marketed rigs, and our priority is to win contracts on those. And in the ultra-deepwater or the drillship market, as we said earlier, our two major rigs that we are looking to try and market now as we go through the remainder of this year are DS-9 and DS-11. But what we are doing is doing a little bit of a portfolio effect, which is we are relatively comfortable with putting some rigs away on quite low pricing to have them there, secured, in a key market, warm, and generating some cash. And then to maybe hold back a proportion of the fleet that we're waiting to try and place into probably a little bit better price or more attractive contracts.
And to give you a little bit more color on that, what makes a contract attractive is not necessarily just the headline day rate. The things that we are looking at is where is the contract, with which customer, whether there is follow-on work in that particular area. But what has become increasingly important has been that several customers – that some contracts are coming out with quite ridiculous wish lists for upgrades, improvements in technology, all at the rig contractor's expense. Now, those don't make sense if then the day rate is not attractive. And so some of those contracts we're choosing not to pursue under that type of tender, and we're either bidding as is, and therefore making it more attractive, or choosing to place into other contracts where the upfront capital outlay is much more limited.
That's very interesting and makes perfect sense. Thanks very much.
Thank you.
And next we have a follow-up question from Ian Macpherson of Piper Jaffray Simmons.
Hey. Thanks for the follow-up. This is going back – it's sort of more backward-looking than forward. But for your lengthy reconciliation of adjusted EBITDA for Q4, we're not adding back the Atwood contract amortization. And I wonder if it would be fair to think of that as an additional cash add-back to cash EBITDA. It's less material going forward, but nonetheless more than a rounding error. So just thoughts on that?
Sure, Ian. I'm just looking at the supplement. Are you walking down the EBITDA reconciliation from that schedule?
Yeah.
Okay. So tell me again, what's the line item you're asking about?
In Q4, $16 million of kind of contract amortization from the Atwood revenues, right?
Right.
Is your net income at the top of that reconciliation not suppressed by that contract amortization?
It is. But it also shows up on the schedule later down. So you see the $15.8 million amortization net – it's included in that item.
It's in there. Sorry. Okay. Sorry to waste your time.
No, and there's more than just that in there. I just quoted the Q1 2018 number, but in the Q4 number, there are several ins and outs, but it is included in that amortization line.
All right. Thanks for straightening me out on that, Jon.
Sure.
It's far from straightforward, Ian.
Hence the supplemental schedules.
Yeah. Okay.
And at this time, we have no further questions. I'll hand the call back to Nick.
Thanks, Laura, and thank you, everyone, for your participation on today's call. We look forward to speaking with you again when we report our first quarter 2018 results. Have a great day.
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