THE VALSPAR CORP INTRODUCTION
Our Business
We are a leading provider of offshore contract drilling services to the international oil and gas industry. Exclusive of two rigs under construction and one rig marked for retirement and classified as held-for-sale, we currently own and operate an offshore drilling rig fleet of 74 rigs, with drilling operations in almost every major offshore market across six continents. Inclusive of our rigs under construction, our rig fleet includes 16 drillships, eight dynamically positioned semisubmersible rigs, two moored semisubmersible rigs and 50 jackup rigs, nine of which are leased to our 50/50 joint venture with Saudi Aramco. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet. Our customers include many of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations spanning 24 countries on six continents. The markets in which we operate include theGulf of Mexico ,Brazil , the Mediterranean, theNorth Sea ,Norway , theMiddle East ,West Africa ,Australia andSoutheast Asia . We provide drilling services on a day rate contract basis. Under day rate contracts, we provide an integrated service that includes the provision of a drilling rig and rig crews for which we receive a daily rate that may vary between the full rate and zero rate throughout the duration of the contractual term, depending on the operations of the rig. We also may receive lump-sum fees or similar compensation for the mobilization, demobilization and capital upgrades of our rigs. Our customers bear substantially all of the costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well.
Rowan Transaction
OnOctober 7, 2018 , we entered into a transaction agreement (the "Transaction Agreement") with Rowan, and onApril 11, 2019 (the "Transaction Date"), we completed our combination with Rowan pursuant to the Transaction Agreement (the "Rowan Transaction") and changed our name toEnsco Rowan plc . OnJuly 30, 2019 , we changed our name toValaris plc . Rowan's financial results are included in our consolidated results beginning on the Transaction Date. As a result of the Rowan Transaction, Rowan shareholders received 2.750Valaris Class A ordinary shares for each Rowan Class A ordinary share, representing a value of$43.67 per Rowan share based on a closing price of$15.88 perValaris share onApril 10, 2019 , the last trading day before the Transaction Date. Total consideration delivered in the Rowan Transaction consisted of 88.3 millionValaris shares with an aggregate value of$1.4 billion . All share and 55 --------------------------------------------------------------------------------
per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split (as defined herein).
Prior to the Rowan Transaction, Rowan and Saudi Aramco formed a 50/50 joint venture to own, manage and operate drilling rigs offshoreSaudi Arabia ("Saudi Aramco Rowan Offshore Drilling Company " or "ARO"). ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and has plans to purchase up to 20 newbuild jackup rigs over an approximate 10 year period. InJanuary 2020 , ARO ordered the first two newbuild jackups scheduled for delivery in 2022. The rigs we lease to ARO are done so through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All nine jackup rigs leased to ARO and all seven ARO-owned jackup rigs are under long-term contracts with Saudi Aramco. For additional information about our ARO joint venture, see Note 4 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." The Rowan Transaction enhanced the market leadership of the combined company with a fleet of high-specification floaters and jackups and positions us well to meet increasing and evolving customer demand. The increased scale, diversification and financial strength of the combined company provides us advantages to better serve our customers. Exclusive of two older jackup rigs marked for retirement, Rowan's offshore rig fleet at the Transaction Date consisted of four ultra-deepwater drillships and 19 jackup rigs.
Reverse Stock Split
Upon closing of the Rowan Transaction, we effected a consolidation (being a reverse stock split under English law) whereby every four existing Valaris Class A ordinary shares, each with a nominal value of$0.10 , were consolidated into one Class A ordinary share, each with a nominal value of$0.40 (the "Reverse Stock Split"). Our shares began trading on a reverse stock split-adjusted basis onApril 11, 2019 . All share and per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split.
Our Industry
Operating results in the offshore contract drilling industry are highly cyclical and are directly related to the demand for drilling rigs and the available supply of drilling rigs. Low demand and excess supply can independently affect day rates and utilization of drilling rigs. Therefore, adverse changes in either of these factors can result in adverse changes in our industry. While the cost of moving a rig may cause the balance of supply and demand to vary somewhat between regions, significant variations between regions are generally of a short-term nature due to rig mobility.
Drilling Rig Demand
The decline in oil prices from 2014 highs led to a significant reduction in global demand for offshore drilling services. Customers significantly reduced their capital spending budgets, including the cancellation or deferral of existing programs, resulting in fewer contracting opportunities for offshore drilling rigs. Declines in capital spending levels, together with the oversupply of rigs from newbuild deliveries, resulted in significantly reduced day rates and utilization that led to one of the most severe downturns in the industry's history. More recently, oil prices have increased meaningfully from the decade lows reached during 2016, with Brent crude averaging nearly$55 per barrel in 2017 and more than$70 through most of 2018, leading to signs of a gradual recovery in demand for offshore drilling services. However, macroeconomic and geopolitical headwinds triggered a decline in Brent crude prices in late 2018, from more than$85 per barrel to approximately$50 per barrel. In 2019, oil prices experienced a gradual recovery from this decline with Brent crude prices averaging approximately$64 per barrel before falling near$55 per barrel in early 2020. While this market volatility will likely continue over the near-term, we expect long-term oil prices to remain at levels sufficient to support a continued gradual recovery in demand for offshore drilling services. However, uncertainty remains regarding global trade and other geopolitical tensions in theMiddle East andChina and their resulting impact on the global economy. Adverse changes in the macro-economic environment resulting from trade 56 -------------------------------------------------------------------------------- discussions, geopolitical events or other factors, including the impact of the coronavirus on global trade, could have a significant adverse impact on global economic growth and ultimately the demand for our offshore drilling services. We continue to observe improvements in the shallow-water market, particularly with respect to higher-specification rigs, as higher levels of customer demand and rig retirements have led to gradually increasing jackup utilization over the past year. Moreover, global floater utilization has increased as compared to a year ago due to a higher number of contracted rigs and lower global supply resulting from rig retirements. However, the floater recovery has lagged the jackup recovery as average contract durations remain relatively short-term and pricing improvements to date have been modest. Despite the increase in customer activity, contract awards remain subject to an extremely competitive bidding process, and the corresponding pressure on operating day rates in recent periods has resulted in low margin contracts, particularly for floaters. Therefore, our results from operations may continue to decline over the near-term as current contracts with above-market rates expire and new contracts are executed at lower rates. We believe further improvements in demand coupled with a reduction in rig supply are necessary to improve the commercial landscape for day rates.
Drilling Rig Supply
Drilling rig supply continues to exceed drilling rig demand for both floaters
and jackups. However, the decline in customer capital expenditure budgets over
the past several years has led to a lack of contracting opportunities resulting
in meaningful global fleet attrition. Since the beginning of the downturn,
drilling contractors have retired approximately 135 floaters and 100 jackups. As
demand for offshore drilling has slowly begun to improve, newer more capable
rigs have been the first to obtain new contract awards, increasing the
likelihood that older, less capable rigs do not return to the global active
fleet.
Approximately 20 floaters older than 30 years are idle, 10 additional floaters
older than 30 years have contracts expiring by the end of 2020 without follow-on
work and a further five floaters aged between 15 and 30 years have been idle for
more than two years. Operating costs associated with keeping these rigs idle as
well as expenditures required to re-certify these aging rigs may prove cost
prohibitive. Drilling contractors will likely elect to scrap or cold-stack some
or all of these rigs.
Approximately 90 jackups older than 30 years are idle, and 60 jackups that are
30 years or older have contracts expiring by the end of 2020 without follow-on
work. Expenditures required to re-certify these aging rigs may prove cost
prohibitive and drilling contractors may instead elect to scrap or cold-stack
these rigs. We expect jackup scrapping and cold-stacking to continue during
2020.
There are 26 newbuild drillships and semisubmersibles reported to be under
construction, of which 16 are scheduled to be delivered before the end of 2020.
Most newbuild floaters are uncontracted. Several newbuild deliveries have been
delayed into future years, and we expect that more uncontracted newbuilds will
be delayed or cancelled.
There are 51 newbuild jackups reported to be under construction, of which 41 are
scheduled to be delivered before the end of 2020. Most newbuild jackups are
uncontracted. Over the past year, some jackup orders have been cancelled, and
many newbuild jackups have been delayed. We expect that scheduled jackup
deliveries will continue to be delayed until more rigs are contracted.
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--------------------------------------------------------------------------------Liquidity, Debt Maturities and Backlog
We proactively manage our capital structure in an effort to most effectively execute our strategic priorities and maximize value for shareholders. In support of these objectives, we are focused on our liquidity, debt levels and maturity profile and cost of capital. Over the past several years we have executed a number of financing transactions to improve our financial statement position and manage our debt maturities, including theJuly 2019 tender offers discussed below. Based on our balance sheet, our contractual backlog and$1.6 billion available under our credit facility, we expect to fund our anticipated 2020 liquidity needs, including negative operating cash flows, debt service and other contractual obligations, anticipated capital expenditures, as well as working capital requirements, from cash and short-term investments and funds borrowed under our credit facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. Our credit facility is an integral part of our financial flexibility and liquidity. We also may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs. In addition, we may seek to extend our maturities and reduce the overall principal amount of our debt through exchange offers or other liability management transactions. We have significant financial flexibility within our capital structure, including the ability to issue debt that would be structurally senior to our currently outstanding debt, on both an unsecured and secured basis, subject to restrictions contained in our existing debt arrangements. Our liability management efforts, if undertaken, may be unsuccessful or may not improve our financial position to the extent anticipated. Our ability to maintain a sufficient level of liquidity to meet our financial obligations will also be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. For example, if we experience further deterioration in demand for offshore drilling, our ability to maintain a sufficient level of liquidity could be materially and adversely impacted, which could have a material adverse impact on our business, financial condition, results of operations, cash flows and our ability to repay or refinance our debt.
Cash and Debt
As ofDecember 31, 2019 , we had$6.5 billion in total principal debt outstanding, representing 41.2% of our total capitalization. We also had$97.2 million in cash and$1.6 billion undrawn capacity under our credit facility, which expires inSeptember 2022 . InDecember 2019 , we received$200.0 million in cash resulting from the settlement of a dispute with Samsung Heavy Industries. See Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Effective upon closing of the Rowan Transaction, we amended our credit facility to, among other changes, increase the borrowing capacity. Previously, our credit facility had a borrowing capacity of$2.0 billion throughSeptember 2019 that declined to$1.3 billion throughSeptember 2020 and$1.2 billion throughSeptember 2022 . Subsequent to the amendment our borrowing capacity is$1.6 billion throughSeptember 2022 . The credit agreement governing the credit facility includes an accordion feature allowing us to increase the future commitments by up to an aggregate amount not to exceed$250.0 million . As a result of the Rowan Transaction, we acquired the following debt: (1)$201.4 million in aggregate principal amount of 7.875% unsecured senior notes, which was repaid at maturity inAugust 2019 , (2)$620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022, (3)$398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024, (4)$500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025, (5)$400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 and (6)$400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044. Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities. 58 -------------------------------------------------------------------------------- OnJune 25, 2019 , we commenced cash tender offers for certain senior notes issued by us,Ensco International Incorporated andRowan Companies, Inc. , our wholly-owned subsidiaries. The tender offers expired onJuly 23, 2019 , and we repurchased$951.8 million aggregate principal amount of notes for a total purchase price of approximately$724.1 million , plus accrued interest.
As of
Backlog
As ofDecember 31, 2019 , our backlog was$2.5 billion as compared to$2.2 billion as ofDecember 31, 2018 . Our floater backlog declined$94.2 million and our jackup backlog increased$210.2 million . These changes resulted from the addition of backlog from the Rowan Transaction, new contract awards and contract extensions offset by revenues realized during the period. Our other segment backlog increased$154.4 million due to the addition of backlog from the Rowan Transaction related to the rigs leased to ARO. Contract backlog includes the impact of drilling contracts signed or terminated after each respective balance sheet date but prior to filing our annual reports onFebruary 21, 2020 andFebruary 28, 2019 , respectively.
BUSINESS ENVIRONMENT
Floaters
The floater contracting environment remains challenging due to limited demand and excess newbuild supply. Floater demand has declined significantly following the decline in commodity prices in 2014 which caused our customers to reduce capital expenditures, particularly for capital-intensive, long-lead deepwater projects, resulting in the cancellation and delay of drilling programs. During the past year, we have observed increased tendering activity that may translate into marginal improvements in near-term utilization; however, further improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized. During the first quarter of 2019, we executed a four-well contract forVALARIS DS-9 that commenced offshoreBrazil inJune 2019 and a six-month contract for VALARIS DS-7 that commenced offshoreEgypt inApril 2019 . Additionally, we executed a two-well contract for VALARIS DPS-1 that is expected to commence inMarch 2020 and a four-well contract forVALARIS 8503 that commenced inJuly 2019 .
During the second quarter of 2019, we executed a one-well contract for VALARIS
DS-18 in the
During the third quarter of 2019, we executed a four-well contract forVALARIS DS-12 that is expected to commence offshoreAngola inApril 2020 , a one-well contract for VALARIS DS-15 that is expected to commence in theU.S. Gulf of Mexico inJanuary 2020 and a one-well contract for VALARIS DS-4 that is expected to commence offshoreGhana inMarch 2020 . We also extended contracts forVALARIS DPS-1 by seven-wells with an estimated duration of 420 days,VALARIS 8505 by three-wells, VALARIS DS-16 by approximately 180 days and VALARIS DS-7 by approximately 165 days. Additionally, we began marketing theVALARIS 5006 for sale and classified the rig as held-for-sale. As a result, we recognized an impairment charge of$88.2 million in our consolidated statement of operations. During the fourth quarter of 2019, we executed a one-year contract extension for VALARIS DS-10. VALARIS DS-7 was awarded a five-well contract that is expected to commence in September and has an estimated duration of 320 days. VALARIS DS-18 was awarded a two-well contract that is expected to commence inJuly 2020 and has an estimated duration of 180 days. VALARIS DS-18 also had a contract extension due to the exercise of one-well option. VALARIS DS-15 was awarded two contracts, a one-well contract that commenced inNovember 2019 and a two-well 59 -------------------------------------------------------------------------------- contract expected to commence inMay 2020 . VALARIS DS-15 also had a contract extension due to the exercise of a one-well priced option, the contract has an estimated duration of 45 days and is expected to commence inMarch 2020 .VALARIS DS-12 and VALARIS MS-1 were awarded one-well contracts that are expected to commence inFebruary 2020 andJuly 2020 , respectively. We also executed a one-well contract for VALARIS DS-9 that is expected to commence inJuly 2020 . We also entered into a short-term contract extension forVALARIS 8503. During the fourth quarter of 2019, we soldVALARIS 5006 for scrap value resulting in an insignificant pre-tax gain. We also began marketing theVALARIS 6002 and classified the rig as held-for-sale on ourDecember 31, 2019 consolidated balance sheet. TheVALARIS 6002 was subsequently sold inJanuary 2020 resulting in an insignificant pre-tax gain.
Jackups
Demand for jackups has improved with increased contracting activity observed over the past year, leading to slight improvements in day rates.
During the first quarter of 2019, we executed a nine-well contract forVALARIS JU-100 that commenced inNovember 2019 . As a result, a previously disclosed contract for VALARIS JU-100 has been fulfilled by VALARIS JU-248. Additionally, we executed a three-well contract for VALARIS JU-121 that commenced inApril 2019 and three-well and one-well contracts for VALARIS JU-72 and VALARIS JU-68, respectively, that commenced duringMay 2019 . We also executed short-term contract extensions for VALARIS JU-101 and VALARIS JU-96.
With respect to the Rowan jackups, a six-month contract extension with a two-month option was executed for VALARIS JU-248 during the first quarter. Additionally, short-term contracts were executed for VALARIS JU-292, VALARIS JU-290 and VALARIS JU-144. The VALARIS JU-290 and VALARIS JU-292 contracts include four additional one-well priced options and two short-term option periods, respectively.
During the second quarter of 2019, we executed a two-year contract forVALARIS JU-120, a two-well contract for VALARIS JU-122, a forty-well P&A contract for VALARIS JU-72, a five-month contract for VALARIS JU-107, two one-well contracts for VALARIS JU-102 and a one-well contract for VALARIS JU-101. Additionally, we executed a two-year extension for VALARIS JU-109, a seven-month extension for VALARIS JU-104, a six-month extension for VALARIS JU-247, a three-month extension for VALARIS JU-96 and one-well extensions for VALARIS JU-118 and VALARIS JU-144.
During the second quarter of 2019, we scrapped ENSCO 97 and the Gorilla IV and recognized an insignificant pre-tax gain.
During the third quarter of 2019, we executed a four-well contract forVALARIS JU-248, an accommodation contract for VALARIS JU-290, a one-well contract for VALARIS JU-107 and a one-well contract for VALARIS JU-87 that commenced in September. We also extended the contracts for VALARIS JU-291 by two-wells, VALARIS JU-247 by approximately eight months and received short-term extensions for VALARIS JU-88, VALARIS JU-115, VALARIS JU-117, VALARIS JU-123 andVALARIS JU-248. During the fourth quarter of 2019, we executed a 200-day contract forVALARIS JU-249 and a 21-well contract for VALARIS JU-87, both of which commenced inNovember 2019 , and a one-well contract for VALARIS JU-75 that commenced inDecember 2019 . We also executed a 12-well contract for VALARIS JU-144 that is expected to commence inApril 2020 , a six-well contract for VALARIS JU-292 that is expected to commence inMay 2020 , and a three-well contract forVALARIS JU-101 that is expected to commence inMarch 2020 . VALARIS JU-107 had a contract extension due to the exercise of one-well option and was also warded a two-well contract that is expected to commence inJune 2020 . Additionally, we executed short-term contract extensions for VALARIS JU-115, VALARIS JU-117,VALARIS JU-122, and VALARIS JU-290. 60 -------------------------------------------------------------------------------- Additionally, in the fourth quarter of 2019, we sold VALARIS JU-42 for scrap value and recognized an insignificant gain. We also began marketing theVALARIS JU-68 and VALARIS JU-70 and classified the rigs as held-for-sale on ourDecember 31, 2019 consolidated balance sheet. We recognized a pre-tax impairment charge of$10.2 million on the VALARIS JU-70. The VALARIS JU-68 was subsequently sold inJanuary 2020 resulting in an insignificant pre-tax loss. InJuly 2019 , a well being drilled offshoreIndonesia by one of our jackup rigs experienced a well-control event requiring the cessation of drilling activities. The operator could seek to terminate the contract under certain circumstances. If this drilling contract were to be terminated for cause, it would result in an approximate$8.5 million decrease in our backlog as ofDecember 31, 2019 . See
Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."
RESULTS OF OPERATIONS
The following table summarizes our consolidated results of operations for each of the years in the three-year period endedDecember 31, 2019 (in millions): 2019 2018 2017 Revenues$ 2,053.2 $ 1,705.4 $ 1,843.0 Operating expenses Contract drilling (exclusive of depreciation) 1,806.0 1,319.4 1,189.5 Loss on impairment 104.0 40.3 182.9 Depreciation 609.7 478.9 444.8 General and administrative 188.9 102.7 157.8 Total operating expenses 2,708.6 1,941.3 1,975.0 Equity in earnings of ARO (12.6 ) - - Operating loss (668.0 ) (235.9 ) (132.0 ) Other income (expense), net 604.2 (303.0 ) (64.0 ) Provision for income taxes 128.4 89.6 109.2 Loss from continuing operations (192.2 ) (628.5 ) (305.2 ) Income (loss) from discontinued operations, net - (8.1 ) 1.0 Net loss (192.2 ) (636.6 ) (304.2 ) Net (income) loss attributable to noncontrolling interests (5.8 ) (3.1 ) .5 Net loss attributable to Valaris$ (198.0 ) $ (639.7 ) $ (303.7 ) Overview Year EndedDecember 31, 2019 Revenues increased by$347.8 million , or 20%, as compared to the prior year primarily due to$322.2 million of revenue earned by the Rowan rigs,$125.5 million due to revenues earned from our rigs leased to ARO and revenues earned from the Secondment Agreement and Transition Services Agreement, and$84.1 million due to the commencement of VALARIS DS-9, VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141 drilling operations. This increase was partially offset by the sale of ENSCO 6001,VALARIS 5006 and ENSCO 97, which operated in the prior-year period, and lower average day rates across the remaining fleet. Contract drilling expense increased by$486.6 million , or 37%, as compared to the prior year primarily due to$351.2 million of contract drilling expense incurred by the Rowan rigs,$57.0 million due to expenses incurred under the Secondment Agreement and by our rigs leased to ARO,$38.2 million due to the commencement of VALARIS DS-9, and$31.3 million due to the commencement of drilling operations for VALARIS JU-123, VALARIS JU-140 61 --------------------------------------------------------------------------------
and VALARIS JU-141. This increase was partially offset by the sale of ENSCO
6001,
General and administrative expenses increased by
Year Ended
Revenues declined by$137.6 million , or 7%, as compared to the prior year. The decline was primarily due to a decline in average day rates in both our floater and jackup fleets and the sale of several rigs during the year that operated in the year-ago period, partially offset by increased utilization and the addition of Atwood rigs to the fleet in late 2017. Contract drilling expense increased by$129.9 million , or 11%, as compared to the prior year. The increase was primarily due to addition of rigs to the fleet from the acquisition ofAtwood Oceanics, Inc. (Atwood) and the commencement of drilling operations for several of our newbuild rigs. This increase was partially offset by the sale of several rigs during the year that operated in the year-ago period and cost incurred during the prior year to settle a previously disclosed legal contingency. Excluding the impact of$7.5 million of transaction costs during 2018 and$51.6 million of transaction costs during 2017 from the Atwood acquisition, general and administrative expenses declined by$11.0 million , or 10%, as compared to the prior year. The decline was primarily due to lower compensation costs and the recovery of certain legal costs awarded to us in connection with the SHI litigation.
Rig Counts, Utilization and Average
The following table summarizes our offshore drilling rigs by reportable segment, rigs under construction and rigs held-for-sale as ofDecember 31, 2019 , 2018 and 2017: 2019 2018 2017 Floaters(1) 24 22 24 Jackups(2) 41 34 37 Other(3) 9 - - Under construction(4) 2 3 3 Held-for-sale(5) 3 - 1 Total Valaris 79 59 65 ARO(6) 7 - - (1) During 2019, we added VALARIS DS-18, VALARIS DS-17, VALARIS DS-16 and
VALARIS DS-15 from the Rowan Transaction, sold
VALARIS 6002 as held-for-sale. During 2018, we sold ENSCO 5005 and ENSCO 6001.
(2) During 2019, we added 10 jackups from the Rowan Transaction, exclusive of
rigs leased to ARO that are included in Other, accepted delivery of
VALARIS JU-123, classified VALARIS JU-68 and VALARIS JU-70 as
held-for-sale and sold VALARIS JU-96 and ENSCO 97. During 2018, we sold
ENSCO 80, ENSCO 81 and ENSCO 82.
(3) During 2019, we added nine jackups from the Rowan Transaction that are
leased to ARO.
(4) During 2019, we accepted the delivery of VALARIS JU-123.
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--------------------------------------------------------------------------------(5) During 2019, we classified VALARIS JU-68, VALARIS JU-70 andVALARIS 6002 as held-for-sale. During 2018, we sold ENSCO 7500.
(6) This represents the seven rigs owned by ARO.
The following table summarizes our and ARO's rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period endedDecember 31, 2019 . Rig utilization and average day rates include results for Rowan rigs and ARO from the transaction date throughDecember 31, 2019 : 2019 2018 2017 Rig Utilization(1) Floaters 47% 46% 45% Jackups 66% 63% 60% Other(2) 100% 100% 100% Total Valaris 63% 56% 55% ARO 93% -% -% AverageDay Rates (3) Floaters$ 218,837 $ 248,395 $ 327,736 Jackups 78,133 77,086 84,913 Other(2) 49,236 81,751 79,566 Total Valaris$ 108,313 $ 128,365 $ 153,306 ARO$ 71,170 $ - $ -
(1) Rig utilization is derived by dividing the number of days under contract by
the number of days in the period. Days under contract equals the total
number of days that rigs have earned and recognized day rate revenue,
including days associated with early contract terminations, compensated
downtime and mobilizations. When revenue is deferred and amortized over a
future period, for example when we receive fees while mobilizing to commence
a new contract or while being upgraded in a shipyard, the related days are
excluded from days under contract.
For newly-constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.
(2) Includes our two managed services contracts and our nine rigs leased to ARO
under bareboat charter contracts.
(3) Average day rates are derived by dividing contract drilling revenues,
adjusted to exclude certain types of non-recurring reimbursable
revenues, lump-sum revenues and revenues attributable to amortization ofdrilling contract intangibles, by the aggregate number of contract days,
adjusted to exclude contract days associated with certain mobilizations,
demobilizations and shipyard contracts.
Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below.
Operating Income by Segment
Prior to the Rowan Transaction, our business consisted of three operating segments: (1) Floaters, which included our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consisted only of our management services provided on rigs owned by third parties. Our Floaters and Jackups were also reportable segments.
As a result of the Rowan Transaction, we concluded that we would maintain the
aforementioned segment structure while adding ARO as a reportable segment for
the new combined company. We also concluded that the
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activities associated with our arrangements with ARO, consisting of our
Transition Services Agreement, Rig Lease Agreements and Secondment Agreement, do
not constitute reportable segments and are therefore included within Other in
the following segment disclosures. Substantially all of the expenses incurred
associated with our Transition Services Agreement are included in general and
administrative under "Reconciling Items" in the table set forth below.
General and administrative expense and depreciation expense incurred by our
corporate office are not allocated to our operating segments for purposes of
measuring segment operating income (loss) and are included in "Reconciling
Items." The full operating results included below for ARO (representing only
results of ARO from the Transaction Date) are not included within our
consolidated results and thus deducted under "Reconciling Items" and replaced
with our equity in earnings of ARO. See Note 4 to our consolidated financial
statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information on ARO and related arrangements.
Segment information for each of the years in the three-year period ended
Year Ended
Floaters Jackups ARO Other Reconciling Items Consolidated Total
Revenues $ 1,014.4 $ 834.6 $ 410.5 $ 204.2 $ (410.5 ) $ 2,053.2
Operating expenses
Contract drilling(exclusive of depreciation) 898.6 788.9 280.2 118.5
(280.2 ) 1,806.0
Loss on impairment 88.2 10.2 - - 5.6 104.0
Depreciation 378.6 212.4 40.3 - (21.6 ) 609.7
General and administrative - - 27.1 - 161.8 188.9
Equity in earnings of ARO - - - - (12.6 ) (12.6 )
Operating income (loss)
$ (288.7 ) $ (668.0 )
Year Ended
Floaters Jackups Other Reconciling Items Consolidated Total
Revenues $ 1,013.5 $ 630.9 $ 61.0 $ - $ 1,705.4
Operating expenses
Contract drilling(exclusive of depreciation) 737.4 526.5 55.5
- 1,319.4
Loss on impairment - 40.3 - - 40.3
Depreciation 311.8 153.3 - 13.8 478.9
General and administrative - - - 102.7 102.7
Operating income (loss) $ (35.7 ) $ (89.2 ) $ 5.5 $ (116.5 ) $ (235.9 )
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Year Ended
Floaters Jackups Other Reconciling Items Consolidated Total
Revenues $ 1,143.5 $ 640.3 $ 59.2 $ - $ 1,843.0
Operating expenses
Contract drilling(exclusive of depreciation) 624.2 512.1 53.2
- 1,189.5
Loss on impairment 174.7 8.2 - - 182.9
Depreciation 297.4 131.5 - 15.9 444.8
General and administrative - - - 157.8 157.8
Operating income (loss) $ 47.2 $ (11.5 ) $ 6.0 $ (173.7 ) $ (132.0 )
Floaters
During 2019, revenues were consistent with the prior year. The $109.3 million of
revenue earned by the Rowan rigs and $41.0 million due to the commencement of
VALARIS DS-9 drilling operations were offset by the sale of VALARIS 5006 and
ENSCO 6001, fewer days under contract and lower average day rates across the
remaining floater fleet.
Contract drilling expense increased by $161.2 million , or 22%, as compared to
the prior year primarily due to $142.4 million of contract drilling expense
incurred by the Rowan rigs and $38.2 million due to the commencement of VALARIS
DS-9 drilling operations. The increase was partially offset by the sale of
VALARIS 5006 and ENSCO 6001 and lower costs on idle rigs.
Depreciation expense increased by
During 2018, revenues declined by$130.0 million , or 11%, as compared to the prior year primarily due to lower average day rates resulting from the expiration of above-market, older contracts that were replaced with new market-rate contracts and sale of ENSCO 6001. The decline was partially offset by the addition of Atwood rigs to the fleet and commencement of VALARIS DS-10 drilling operations. Contract drilling expense increased by$113.2 million , or 18%, as compared to the prior year primarily due to the addition of Atwood rigs to the fleet and commencement of VALARIS DS-10 drilling operations. This increase was partially offset by the sale of ENSCO 6001, lower rig reactivation costs and costs incurred in the prior year to settle a previously disclosed legal contingency. Depreciation expense increased by$14.4 million , or 5%, compared to the prior year primarily due to the addition of Atwood rigs and commencement ofVALARIS DS-10 drilling operations. The increase was partially offset by lower depreciation expense on non-core assets that were impaired to scrap value during the fourth quarter of 2017. Jackups During 2019, revenues increased by$203.7 million , or 32%, as compared to the prior year primarily due to$212.9 million of revenue earned by the Rowan rigs and$43.1 million due to the commencement of VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141 drilling operations. This increase was partially offset by the sale of ENSCO 97 and ENSCO 80, which operated in the prior-year period.
Contract drilling expense increased by
65
--------------------------------------------------------------------------------of drilling operations for VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141. This increase was partially offset by the sale of ENSCO 97 and ENSCO 80.
Depreciation expense increased by
During 2018, revenues declined by$9.4 million , or 1%, as compared to the prior year primarily due to the sale of ENSCO 52 and ENSCO 80 and lower average day rates across the fleet. These declines were partially offset by more days under contract across the fleet, the commencement of VALARIS JU-140 and VALARIS JU-141 contracts and the addition of Atwood rigs to the fleet. Contract drilling expense increased by$14.4 million , or 3%, as compared to the prior year primarily due to more days under contract across the fleet, the addition of Atwood rigs and contract commencements for VALARIS JU-140 and VALARIS JU-141. These increases were partially offset by lower rig reactivation costs and the sale of ENSCO 52 and ENSCO 80. Depreciation expense increased by$21.8 million , or 17%, as compared to the prior year primarily due to the addition of Atwood rigs and VALARIS JU-140 and VALARIS JU-141 to the fleet. The increase was partially offset by lower depreciation expense on a non-core rig that was impaired to scrap value during the fourth quarter of 2017.ARO ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and plans to purchase up to 20 newbuild jackup rigs over an approximate 10 year period. InJanuary 2020 , ARO ordered the first two newbuild jackups with delivery scheduled in 2022. The rigs we lease to ARO are done so through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All nine jackup rigs leased to ARO are under three-year contracts with Saudi Aramco. All seven ARO-owned jackup rigs are under long-term contracts with Saudi Aramco. The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for the seven ARO-own jackup rigs and the nine rigs leased from us that operated during the period from the Transaction Date throughDecember 31, 2019 . The contract drilling, depreciation and general and administrative expenses are also for the period from the Transaction Date throughDecember 31, 2019 . Contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us and costs incurred under the Secondment Agreement. General and administrative expenses include costs incurred under the Transition Services Agreement and other administrative costs.
Other
Other revenues increased
Other contract drilling expenses increased$63.0 million , or 114%, for the year endedDecember 31, 2019 , respectively, as compared to the prior year period, primarily due to costs incurred for services provided to ARO under the Secondment Agreement and other costs for ARO rigs.
Impairment of Long-Lived Assets
See Note 6 and Note 14 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on impairment of long-lived assets.
66
--------------------------------------------------------------------------------Other Income (Expense), Net
The following table summarizes other income (expense), net, for each of the
years in the three-year period ended
2019 2018 2017
Interest income $ 28.1 $ 14.5 $ 25.8
Interest expense, net:
Interest expense (449.2 ) (345.3 ) (296.7 )
Capitalized interest 20.9 62.6 72.5
(428.3 ) (282.7 ) (224.2 )
Other, net 1,004.4 (34.8 ) 134.4
$ 604.2 $ (303.0 ) $ (64.0 )
Interest income increased during 2019 as compared to the respective prior year
period primarily due to interest income of $16.8 million earned on the
shareholder note from ARO (see Note 4 to our consolidated financial
statements included in "Item 8. Financial Statements and Supplementary Data" for
information on ARO) acquired in the Rowan Transaction. Interest income declined
during 2018 as compared to the respective prior-year period as a result of a
decrease in our average short-term investment balances.
Interest expense increased during 2019 by $103.9 million , or 30%, as compared to
the prior year due to interest expense incurred on Rowan's senior notes.
Interest expense increased during 2018 by $48.6 million , or 16%, as compared to
the prior year due to debt transactions we undertook during the first quarter of
2018 (see Note 7 to our consolidated financial statements included in "Item
8. Financial Statements and Supplementary Data" for information on debt).
Interest expense capitalized declined during 2019 and 2018 by $41.7 million , or
67%, and $9.9 million , or 14%, as compared to the prior year periods, due to a
decline in the amount of capital invested in newbuild construction resulting
from newbuild rigs being placed into service.
Other, net, during 2019 included a gain on bargain purchase recognized in
connection with the Rowan Transaction of
Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" and a pre-tax gain from debt extinguishment of$194.1 million related to the senior notes repurchased in connection with ourJuly 2019 tender offers. This increase was partially offset by settlement of a Middle East dispute discussed in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" as well as foreign currency losses as discussed below. Our functional currency is theU.S. dollar, and a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than theU.S. dollar. These transactions are remeasured inU.S. dollars based on a combination of both current and historical exchange rates. Net foreign currency exchange losses, inclusive of offsetting fair value derivatives, were$7.4 million ,$17.2 million and$5.1 million , and were included in other, net, in our consolidated statements of operations for the years endedDecember 31, 2019 , 2018 and 2017, respectively. Net foreign currency exchange losses incurred during 2019 included$3.3 million and$2.8 million , related to euros and Angolan kwanza, respectively. Net foreign currency exchange losses incurred during 2018 included$5.8 million ,$3.6 million and$2.0 million , related to Angolan kwanza, euros and Brazilian reals, respectively. During 2017, the net foreign currency exchange losses incurred were$2.1 million ,$1.9 million and$1.0 million , related to euros, Indonesian rupiahs and Brazilian reals, respectively.
Net unrealized gains of
67
--------------------------------------------------------------------------------
net, in our consolidated statements of operations for the years ended December
31, 2019 , 2018 and 2017, respectively. Information on the fair value measurement
of our marketable securities held in the SERP is presented in Note 5 to our
consolidated financial statements included in "Item 8. Financial Statements and
Supplementary Data."
Provision for Income Taxes
Valaris plc , our parent company, is domiciled and resident in the U.K. Our
subsidiaries conduct operations and earn income in numerous countries and are
subject to the laws of taxing jurisdictions within those countries. The income
of our non-U.K. subsidiaries is generally not subject to U.K. taxation. Income
tax rates imposed in the tax jurisdictions in which our subsidiaries conduct
operations vary, as does the tax base to which the rates are applied. In some
cases, tax rates may be applicable to gross revenues, statutory or negotiated
deemed profits or other bases utilized under local tax laws, rather than to net
income.
Our drilling rigs frequently move from one taxing jurisdiction to another to
perform contract drilling services. In some instances, the movement of drilling
rigs among taxing jurisdictions will involve the transfer of ownership of the
drilling rigs among our subsidiaries. As a result of frequent changes in the
taxing jurisdictions in which our drilling rigs are operated and/or owned,
changes in profitability levels and changes in tax laws, our annual effective
income tax rate may vary substantially from one reporting period to another. In
periods of declining profitability, our income tax expense may not decline
proportionally with income, which could result in higher effective income tax
rates. Further, we may continue to incur income tax expense in periods in which
we operate at a loss.
U.S. Tax Reform
The U.S. Tax Cuts and Jobs Act ("U.S. tax reform") was enacted on December 22,
2017 and introduced significant changes to U.S. income tax law, including a
reduction in the statutory income tax rate from 35% to 21% effective January 1,
2018 , a one-time transition tax on deemed repatriation of deferred foreign
income, a base erosion anti-abuse tax that effectively imposes a minimum tax on
certain payments to non-U.S. affiliates, new and revised rules relating to the
current taxation of certain income of foreign subsidiaries and revised rules
associated with limitations on the deduction of interest.
Due to the timing of the enactment of U.S. tax reform and the complexity
involved in applying its provisions, we made reasonable estimates of its effects
and recorded such amounts in our consolidated financial statements as of
December 31, 2017 on a provisional basis. Throughout 2018, we continued to
analyze applicable information and data, interpret rules and guidance issued by
the U.S. Treasury Department and Internal Revenue Service, and make adjustments
to the provisional amounts, as provided for in Staff Accounting Bulletin No.
118. The U.S. Treasury Department continued finalizing rules associated with
U.S. tax reform during 2018 and 2019.
During 2019, we recognized a tax expense of $13.8 million associated with final
rules issued related to U.S. tax reform. During 2018, we recognized a tax
benefit of $11.7 million associated with the one-time transition tax on deemed
repatriation of the deferred foreign income of our U.S. subsidiaries. We
recognized a net tax expense of $16.5 million during the fourth quarter of 2017
in connection with enactment of U.S. tax reform, consisting of a $38.5 million
tax expense associated with the one-time transition tax on deemed repatriation
of the deferred foreign income of our U.S. subsidiaries, a $17.3 million tax
expense associated with revisions to rules over the taxation of income of
foreign subsidiaries, a $20.0 million tax benefit resulting from the
re-measurement of our deferred tax assets and liabilities as of December 31,
2017 to reflect the reduced tax rate and a $19.3 million tax benefit resulting
from adjustments to the valuation allowance on deferred tax assets.
See Note 12 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
68
--------------------------------------------------------------------------------Effective Tax Rate
During the years endedDecember 31, 2019 , 2018 and 2017, we recorded income tax expense of$128.4 million ,$89.6 million and$109.2 million , respectively. Our consolidated effective income tax rates were (201.3)%, (16.6)% and (55.7)% during the same periods, respectively. Our 2019 consolidated effective income tax rate included$2.3 million associated with the impact of various discrete tax items, including$28.3 million of tax expense associated with final rules relating toU.S. tax reform, gains on repurchase of debt and settlement proceeds, partially offset by$26.0 million of tax benefit related to restructuring transactions, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and other resolutions of prior year tax matters and rig sales. Our 2018 consolidated effective income tax rate includes the impact of various discrete tax items, including$46.0 million of tax benefit associated with the utilization of foreign tax credits subject to a valuation allowance, the transition tax on deemed repatriation of the deferred foreign income of ourU.S. subsidiaries, and a restructuring transaction, partially offset by$21.0 million of tax expense related to recovery of certain costs associated with an ongoing legal matter, repurchase and redemption of senior notes and rig sales. Our 2017 consolidated effective income tax rate included$32.2 million associated with the impact of various discrete tax items, including$16.5 million of tax expense associated withU.S. tax reform and$15.7 million of tax expense associated with the exchange offers and debt repurchases, rig sales, a restructuring transaction, settlement of a previously disclosed legal contingency, the effective settlement of a liability for unrecognized tax benefits associated with a tax position taken in prior years and other resolutions of prior year tax matters. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years endedDecember 31, 2019 , 2018 and 2017 were (14.6)%, (24.8)% and (96.0)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-year period result primarily fromU.S. tax reform and changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and differences in tax rates in such taxing jurisdictions. Divestitures Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations that are not part of our long-term strategic plan or that no longer meet our standards for economic returns. Consistent with this strategy, we sold 12 jackup rigs, two dynamically positioned semisubmersible rigs and two moored semisubmersible rigs during the three-year period endedDecember 31, 2019 . We continue to focus on our fleet management strategy in light of the composition of our rig fleet. As part of this strategy, we may act opportunistically from time to time to monetize assets to enhance shareholder value and improve our liquidity profile, in addition to selling or disposing of older, lower-specification or non-core rigs. 69 --------------------------------------------------------------------------------
We sold the following rigs during the three-year period ended
Net Book Pre-tax
Rig Date of Sale Classification(1) Segment(1) Net Proceeds Value(2) Gain/(Loss)
VALARIS JU-96 December 2019 Continuing Jackups $ 1.9 $ .3 $ 1.6
VALARIS 5006 November 2019 Continuing Floaters 7.0 6.0 1.0
VALARIS JU-42 October 2019 Continuing Jackups 2.9 2.5 .4
Gorilla IV May 2019 Continuing Jackups 2.5 2.5 -
ENSCO 97 April 2019 Continuing Jackups 1.7 1.0 .7
ENSCO 80 August 2018 Continuing Jackups 1.0 .5 .5
ENSCO 5005 August 2018 Continuing Floaters 4.0 2.0 2.0
ENSCO 6001 July 2018 Continuing Floaters 2.0 .9 1.1
ENSCO 7500 April 2018 Discontinued Floaters 2.6 1.5 1.1
ENSCO 81 April 2018 Continuing Jackups 1.0 .3 .7
ENSCO 82 April 2018 Continuing Jackups 1.0 .3 .7
ENSCO 52 August 2017 Continuing Jackups .8 .4 .4
ENSCO 86 June 2017 Continuing Jackups .3 .3 -
ENSCO 90 June 2017 Discontinued Jackups .3 .3 -
ENSCO 99 June 2017 Continuing Jackups .3 .3 -
ENSCO 56 April 2017 Continuing Jackups 1.0 .3 .7
$ 30.3 $ 19.4 $ 10.9
(1) Classification denotes the location of the operating results and gain (loss)
on sale for each rig in our consolidated statements of operations. For rigs'
operating results that were reclassified to discontinued operations in our
consolidated statements of operations, these results were previously
included within the specified operating segment.
(2) Includes the rig's net book value as well as materials and supplies and
other assets on the date of the sale.
LIQUIDITY AND CAPITAL RESOURCES
We proactively manage our capital structure in an effort to most effectively execute our strategic priorities and maximize value for shareholders. In support of these objectives, we are focused on our liquidity, debt levels and maturity profile and cost of capital. Over the past several years, we have executed a number of financing transactions to improve our financial position and manage our debt maturities, including theJuly 2019 tender offers discussed below. Based on our balance sheet, our contractual backlog and$1.6 billion of undrawn capacity under our credit facility, we expect to fund our liquidity needs, including expected negative operating cash flows, contractual obligations, anticipated capital expenditures, as well as working capital requirements, from cash and funds borrowed under our credit facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. Our credit facility is an integral part of our financial flexibility and liquidity. We also may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs. In addition, we may seek to extend our maturities and reduce the overall principal amount of our debt through exchange offers or other liability management transactions. We have significant financial flexibility within our capital structure, including the ability to issue debt that would be structurally senior to our currently outstanding debt, on both an unsecured and secured basis, subject to restrictions contained in our existing debt arrangements. Our liability management efforts, if undertaken, may be unsuccessful or may not improve our financial position to the extent anticipated. 70 -------------------------------------------------------------------------------- Additionally, as a result of the Rowan Transaction, we acquired the following debt: (1)$201.4 million in aggregate principal amount of 7.875% unsecured senior notes, which was repaid at maturity inAugust 2019 , (2)$620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022, (3)$398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024, (4)$500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025, (5)$400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 and (6)$400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044. Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities. During the three-year period endedDecember 31, 2019 , our primary sources of cash were$1.4 billion from net maturities of short-term investments,$1.0 billion in proceeds from the issuance of senior notes, and Rowan cash acquired of$931.9 million . Our primary uses of cash during the same period included$2.2 billion for the repurchase and redemption of outstanding debt,$1.2 billion for the construction, enhancement and other improvement of our drilling rigs, including$813.7 million invested in newbuild construction,$871.6 million for the repayment of Atwood debt and$36.2 million for dividend payments.
Explanations of our liquidity and capital resources for each of the years in the
three-year period ended
Cash Flows and Capital Expenditures
Our cash flows from operating activities of continuing operations and capital expenditures on continuing operations for each of the years in the three-year period endedDecember 31, 2019 were as follows (in millions): 2019 2018
2017
Net cash provided by (used in) operating activities of continuing operations$ (276.9 ) $ (55.7 ) $ 259.4 Capital expenditures: New rig construction$ 42.8 $ 341.1 $ 429.8 Rig enhancements 114.9 45.2 45.1 Minor upgrades and improvements 69.3 40.4 61.8$ 227.0 $ 426.7 $ 536.7 During 2019, cash flows from continuing operations declined by$221.2 million as compared to the prior year due primarily to costs incurred related to the Rowan Transaction, interest on the debt assumed in the Rowan Transaction and declining margins. As our remaining above-market contracts expire and utilization increases with the execution of new market-rate contracts, coupled with the potential impact of rig reactivation costs, our operating cash flows will remain negative through at least 2020. During 2018, cash flows from continuing operations declined by$315.1 million , or 121%, as compared to the prior year due primarily to declining margins and higher cash interest expense due to the debt financing transactions we undertook during the first quarter of 2018. Based on our current projections, excluding integration-related capital expenditures, we expect capital expenditures during 2020 to approximate$160.0 million for newbuild construction, rig enhancement projects and minor upgrades and improvements. Approximately$30 million of our projected capital expenditures is reimbursable by our customers. Depending on market conditions and opportunities, we may reduce our planned expenditures or make additional capital expenditures to upgrade rigs for customer requirements or acquire additional rigs. 71 --------------------------------------------------------------------------------
Dividends
Our Board of Directors declared a$0.01 quarterly cash dividend, on a pre-reverse stock split basis, for the first quarter of 2019. Beginning in the second quarter of 2019, our Board of Directors determined that we will not pay a regular quarterly cash dividend. The declaration and amount of future dividends is at the discretion of our Board of Directors and could change in future periods. Our revolving credit facility prohibits us from paying dividends in excess of$0.01 per share per fiscal quarter. Dividends in excess of this amount would require the amendment or waiver of such provision.
Financing and Capital Resources
Debt to Capital
Our total debt, total capital and total debt to total capital ratios as of
2019 2018 2017
Total debt (1) $ 6,528.1 $ 5,161.0 $ 4,882.8
Total capital(2) $ 15,839.0 $ 13,252.4 $ 13,614.9 Total debt to total capital 41.2 % 38.9 % 35.9 %
(1)Total debt consists of the principal amount outstanding.
(2)Total capital consists of total debt and
During 2019, our total debt principal increased by$1.4 billion and total capital increased by$2.6 billion as a result of debt acquired and equity issued in connection with the Rowan Transaction (see Note 3 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data"). During 2018, our total debt increased by$278.2 million and total capital declined by$362.5 million . Our total debt increased as a result of the debt transactions we undertook during the first quarter of 2018 (see Note 7 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data") and our total capital declined as a result of our net loss incurred in that period, partially offset by the aforementioned increase in our total debt. Convertible Senior Notes InDecember 2016 ,Ensco Jersey Finance Limited , a wholly-owned subsidiary ofValaris plc , issued$849.5 million aggregate principal amount of unsecured 2024 Convertible Notes (the "2024 Convertible Notes") in a private offering. The 2024 Convertible Notes are fully and unconditionally guaranteed, on a senior, unsecured basis, byValaris plc and are exchangeable into cash, our Class A ordinary shares or a combination thereof, at our election. Interest on the 2024 Convertible Notes is payable semiannually onJanuary 31 andJuly 31 of each year. The 2024 Convertible Notes will mature onJanuary 31, 2024 , unless exchanged, redeemed or repurchased in accordance with their terms prior to such date. Holders may exchange their 2024 Convertible Notes at their option any time prior toJuly 31, 2023 only under certain circumstances set forth in the indenture governing the 2024 Convertible Notes. On or afterJuly 31, 2023 , holders may exchange their 2024 Convertible Notes at any time. The exchange rate is 17.8336 shares per$1,000 principal amount of notes, representing an exchange price of$56.08 per share, and is subject to adjustment upon certain events. The 2024 Convertible Notes may not be redeemed by us except in the event of certain tax law changes. The indenture governing the 2024 Convertible Notes contains customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contains certain restrictions, 72 --------------------------------------------------------------------------------
including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions. See Note 7 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.
Senior Notes
As a result of the Rowan Transaction, we acquired the following debt issued byRowan Companies, Inc. ("RCI") and guaranteed by Rowan: (1)$201.4 million in aggregate principal amount of 7.875% unsecured senior notes due 2019, which was repaid at maturity inAugust 2019 , (2)$620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022 (the "Rowan 2022 Notes"), (3)$398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024 (the "Rowan 2024 Notes"), (4)$500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025 (the "Rowan 2025 Notes"), (5)$400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 (the "Rowan 2042 Notes") and (6)$400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044 (the "Rowan 2044 Notes" and collectively, the "Rowan Notes"). Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities. OnFebruary 3, 2020 , Rowan and RCI transferred substantially all their assets on a consolidated basis toValaris plc ,Valaris plc became the obligor on the notes and Rowan and RCI were relieved of their obligations under the notes and the related indenture.
On
During 2017, we exchanged$332.0 million aggregate principal amount of unsecured 8.00% senior notes due 2024 (the "8% 2024 Notes") for certain amounts of our outstanding senior notes due 2019, 2020 and 2021. Interest on the 8% 2024 Notes is payable semiannually onJanuary 31 andJuly 31 of each year. During 2015, we issued$700.0 million aggregate principal amount of unsecured 5.20% senior notes due 2025 (the "2025 Notes") at a discount of$2.6 million and$400.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the "New 2044 Notes") at a discount of$18.7 million in a public offering. Interest on the 2025 Notes is payable semiannually onMarch 15 andSeptember 15 of each year. Interest on the New 2044 Notes is payable semiannually onApril 1 andOctober 1 of each year. During 2014, we issued$625.0 million aggregate principal amount of unsecured 4.50% senior notes due 2024 (the "2024 Notes") at a discount of$0.9 million and$625.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the "Existing 2044 Notes") at a discount of$2.8 million . Interest on the 2024 Notes and the Existing 2044 Notes is payable semiannually onApril 1 andOctober 1 of each year. The Existing 2044 Notes together with the New 2044 Notes, the "2044 Notes", are treated as a single series of debt securities under the indenture governing the notes. During 2011, we issued$1.5 billion aggregate principal amount of unsecured 4.70% senior notes due 2021 (the "2021 Notes") at a discount of$29.6 million in a public offering. Interest on the 2021 Notes is payable semiannually onMarch 15 andSeptember 15 of each year. Upon consummation of our acquisition ofPride International LLC ("Pride") during 2011, we assumed outstanding debt comprised of$900.0 million aggregate principal amount of unsecured 6.875% senior notes due 2020,$500.0 million aggregate principal amount of unsecured 8.5% senior notes due 2019 and$300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Acquired Notes" and together with the Rowan Notes, 2021 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, 2026 Notes and 2044 Notes, the "Senior Notes").Valaris plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes. See "Note 17 - Guarantee ofRegistered Securities " included in "Item 8. Financial Statements and Supplementary Data" for additional information on the guarantee of the Acquired Notes. 73
-------------------------------------------------------------------------------- We may redeem the Senior Notes in whole at any time, or in part from time to time, prior to maturity. If we elect to redeem the Rowan 2022 Notes, Rowan 2024 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, Rowan 2025 Notes and 2026 Notes before the date that is three months prior to the maturity date or the Rowan 2042 Notes, Rowan 2044 Notes and 2044 Notes before the date that is six months prior to the maturity date, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest and a "make-whole" premium. If we elect to redeem these notes on or after the aforementioned dates, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, but we are not required to pay a "make-whole" premium. We may redeem each series of the 2021 Notes and the Acquired Notes, in whole or in part, at any time at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. The indentures governing the Senior Notes contain customary events of default, including failure to pay principal or interest on such notes when due, among others. The indentures governing the Senior Notes also contain certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.
Debentures Due 2027
During 1997,Ensco International Incorporated issued$150.0 million of unsecured 7.20% Debentures due 2027 (the "Debentures"). Interest on the Debentures is payable semiannually onMay 15 andNovember 15 of each year. We may redeem the Debentures, in whole or in part, at any time prior to maturity, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. During 2009,Valaris plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures. See "Note 17 - Guarantee ofRegistered Securities " included in "Item 8. Financial Statements and Supplementary Data" for additional information on the guarantee of the Debentures. The Debentures and the indenture pursuant to which the Debentures were issued also contain customary events of default, including failure to pay principal or interest on the Debentures when due, among others. The indenture also contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.
Tender Offers and Open Market Repurchases
OnJune 25, 2019 , we commenced cash tender offers for certain series of senior notes issued by us andEnsco International Incorporated and RCI, our wholly-owned subsidiaries. The tender offers expired onJuly 23, 2019 , and we repurchased$951.8 million of our outstanding senior notes for an aggregate purchase price of$724.1 million . As a result of the transaction, we recognized a pre-tax gain from debt extinguishment of$194.1 million , net of discounts, premiums and debt issuance costs. Concurrent with the issuance of the 2026 Notes inJanuary 2018 , we launched cash tender offers for up to$985.0 million aggregate principal amount of certain series of senior notes issued by us and Pride, our wholly-owned subsidiary, and as a result we repurchased$595.4 million of our senior notes. Subsequently, we issued a redemption notice for the remaining principal amount of the$55.0 million principal amount of the 8.50% senior notes due 2019 and repurchased$71.4 million principal amount of our senior notes due 2020. As a result of these transactions, we recognized a pre-tax loss from debt extinguishment of$19.0 million , net of discounts, premiums, debt issuance costs and commissions. During 2017, we repurchased$194.1 million of our outstanding senior notes on the open market for an aggregate purchase price of$204.5 million with cash on hand and recognized an insignificant pre-tax loss, net of discounts, premiums and debt issuance costs. 74 --------------------------------------------------------------------------------
Our tender offers and open market repurchases during the three-year period ended
Aggregate
Aggregate Principal Repurchase
Amount Repurchased Price(1)
Year Ended December 31, 2019
4.50% Senior notes due 2024 $ 320.0 $ 240.0
4.75% Senior notes due 2024 79.5 61.2
8.00% Senior notes due 2024 39.7 33.8
5.20% Senior notes due 2025 335.5 250.0
7.375% Senior notes due 2025 139.2 109.2
7.20% Senior notes due 2027 37.9 29.9
$ 951.8 $ 724.1
Year Ended December 31, 2018
8.50% Senior notes due 2019 $ 237.6 $ 256.8
6.875% Senior notes due 2020 328.0 354.7
4.70% Senior notes due 2021 156.2 159.7
$ 721.8 $ 771.2
Year Ended December 31, 2017
8.50% Senior notes due 2019 $ 54.6 $ 60.1
6.875% Senior notes due 2020 100.1 105.1
4.70% Senior notes due 2021 39.4 39.3
$ 194.1 $ 204.5
(1) Excludes accrued interest paid to holders of the repurchased senior notes.
Exchange Offers
During 2017, we completed exchange offers to exchange our outstanding 2019, 2020 and 2021 notes for the 8% 2024 Notes and cash. The exchange offers resulted in the tender of$649.5 million aggregate principal amount of our outstanding notes that were settled and exchanged as follows (in millions): Aggregate Principal 8% Senior Notes Due
Cash
Amount Repurchased 2024 Consideration Consideration Total Consideration
8.50% Senior notes due 2019 $ 145.8 $ 81.6 $ 81.7 $ 163.3
6.875% Senior notes due 2020 129.8 69.3 69.4 138.7
4.70% Senior notes due 2021 373.9 181.1 181.4 362.5
$ 649.5 $ 332.0 $ 332.5 $ 664.5
During the year ended
75
--------------------------------------------------------------------------------Revolving Credit
Effective upon closing of the Rowan Transaction, we amended our credit facility to, among other changes, increase the borrowing capacity. Previously, our credit facility had a borrowing capacity of$2.0 billion throughSeptember 2019 that declined to$1.3 billion throughSeptember 2020 and$1.2 billion throughSeptember 2022 . Subsequent to the amendment, our borrowing capacity was$1.7 billion throughSeptember 2022 . Following the amendment, our borrowing capacity was reduced by$75 million to$1.6 billion . The reduction occurred after we became aware that a signatory for a purported lender was not an authorized representative of that lender and therefore concluded the$75 million was not binding. The credit agreement governing the credit facility includes an accordion feature allowing us to increase the future commitments by up to an aggregate amount not to exceed$250.0 million . Advances under the credit facility bear interest at Base Rate or LIBOR plus an applicable margin rate, depending on our credit ratings. We are required to pay a quarterly commitment fee on the undrawn portion of the$1.6 billion commitment, which is also based on our credit ratings. OnDecember 6, 2019 , Moody's downgraded our corporate family rating from B3 to Caa1 and our senior unsecured notes from Caa1 to Caa2. Previously, inSeptember 2019 ,Standard & Poor's downgraded our senior unsecured bonds from B to B- and our issuer rating from B- to CCC+. The rating actions did not impact the interest rates applicable to our borrowings and the quarterly commitment fee on the undrawn portion of the$1.6 billion commitment. The applicable margin rates are 3.25% per annum for Base Rate advances and 4.25% per annum for LIBOR advances. The quarterly commitment fee is 0.75% per annum on the undrawn portion of the$1.6 billion commitment. The credit facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to 60% and to provide guarantees from certain of our rig-owning subsidiaries sufficient to meet certain guarantee coverage ratios. The credit facility also contains customary restrictive covenants, including, among others, prohibitions on creating, incurring or assuming certain debt and liens (subject to customary exceptions, including a permitted lien basket that permits us to raise secured debt up to the lesser of$1 billion or 10% of consolidated tangible net worth (as defined in the credit facility)); entering into certain merger arrangements; selling, leasing, transferring or otherwise disposing of all or substantially all of our assets; making a material change in the nature of the business; paying or distributing dividends on our ordinary shares (subject to certain exceptions, including the ability to pay a quarterly dividend of$0.01 per share); borrowings, if after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of available cash (as defined in the credit facility) would exceed$200 million ; and entering into certain transactions with affiliates. The credit facility also includes a covenant restricting our ability to repay indebtedness maturing afterSeptember 2022 , which is the final maturity date of our credit facility. This covenant is subject to certain exceptions that permit us to manage our balance sheet, including the ability to make repayments of indebtedness (i) of acquired companies within 90 days of the completion of the acquisition or (ii) if, after giving effect to such repayments, available cash is greater than$250 million and there are no amounts outstanding under the credit facility. As ofDecember 31, 2019 , we were in compliance in all material respects with our covenants under the credit facility. We expect to remain in compliance with our credit facility covenants during 2020. We had no amounts outstanding under the credit facility as ofDecember 31, 2019 and 2018. As ofJanuary 31, 2020 , we had$90 million of total outstanding borrowings under our credit facility. Our access to credit and capital markets is limited because of our credit rating. Our current credit ratings, and any additional actual or anticipated downgrades in our corporate credit ratings or the credit rating of our notes will limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. In addition, future financings or refinancings will result in higher borrowing costs and may require collateral and/or more restrictive terms and covenants, which may further restrict our operations. Limitations on our ability to access credit and capital markets could have a material adverse impact on our financial position, operating results or cash flows. 76
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Maturities
The descriptions of our senior notes above reflect the original principal
amounts issued, which have subsequently changed as a result of our tenders,
repurchases, exchanges, redemptions and new debt issuances such that the
maturities of our debt at
2016 Tenders, 2019 Tender
Original Repurchases and 2017 Exchange Offers 2018 Tender Offers and Remaining
Senior Notes Principal Equity Exchange and Repurchases Offers, Redemption Acquired Debt Principal
6.875% due 2020 $ 900.0 $ (219.2 ) $ (229.9 ) $ (328.0 ) $ - $ 122.9
4.70% due 2021 1,500.0 (817.0 ) (413.3 ) (156.2 ) - 113.5
4.875% due 2022 (1) - - - - 620.8 620.8
3.00% Exchangeable
senior notes due 2024 849.5 - - - - 849.5
4.50% due 2024 625.0 (1.7 ) - - (320.0 ) 303.3
4.75% due 2024 (1) - - - - 318.6 318.6
8.00% due 2024 - - 332.0 - (39.7 ) 292.3
5.20% due 2025 700.0 (30.7 ) - - (335.5 ) 333.8
7.375% due 2025 (1) - - - - 360.8 360.8
7.75% due 2026 - - - 1,000.0 - 1,000.0
7.20% due 2027 150.0 - - - (37.9 ) 112.1
7.875% due 2040 300.0 - - - 300.0
5.40% due 2042 (1) - - - - 400.0 400.0
5.75% due 2044 1,025.0 (24.5 ) - - - 1,000.5
5.85% due 2044 (1) - - - - 400.0 400.0
Total $ 6,549.5 $ (1,155.1 ) $ (511.6 ) $ 278.2 $ 1,367.1 $ 6,528.1 (1) These senior notes were acquired in the Rowan Transaction.
Other Financing Arrangements
We filed an automatically effective shelf registration statement on Form S-3 with theU.S. Securities and Exchange Commission onNovember 21, 2017 , which provides us the ability to issue debt securities, equity securities, guarantees and/or units of securities in one or more offerings. The registration statement expires inNovember 2020 . During 2018, our shareholders approved our current share repurchase program. Subject to certain provisions under English law, including the requirement of the Company to have sufficient distributable reserves, we may repurchase shares up to a maximum of$500 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 16.3 million shares. The program terminates inMay 2023 . As ofDecember 31, 2019 , there had been no share repurchases under this program. Our credit facility prohibits us from repurchasing our shares, except in certain limited circumstances. Any share repurchases, outside of such limited circumstances, would require the amendment or waiver of such provision. From time to time, we and our affiliates may repurchase our outstanding senior notes in the open market, in privately negotiated transactions, through tender offers, exchange offers or otherwise, or we may redeem senior notes, pursuant to their terms. In connection with any exchange, we may issue equity, issue new debt (including debt that is structurally senior to our existing senior notes) and/or pay cash consideration. Any future repurchases, exchanges or redemptions will depend on various factors existing at that time. There can be no assurance as to which, if any, of these alternatives (or combinations thereof) we may choose to pursue in the future or, if any such alternatives are pursued, that they will be successful. There can be no assurance that an active trading market will exist for our outstanding senior notes following any such transaction. 77 --------------------------------------------------------------------------------
Investment in ARO and Notes Receivable from ARO
We consider our investment in ARO to be a significant component of our investment portfolio and an integral part of our long-term capital resources. We expect to receive cash from ARO in the future both from the maturity of our long-term notes receivable and from the distribution of earnings from ARO. The long-term notes receivable earn interest at LIBOR plus two percent and mature during 2027 and 2028. The distribution of earnings to the joint-venture partners is at the discretion of the ARO Board of Managers, consisting of 50/50 membership of managers appointed by Saudi Aramco and managers appointed by us, with approval required by both shareholders. The timing and amount of any cash distributions to the joint-venture partners cannot be predicted with certainty and will be influenced by various factors, including the liquidity position and long-term capital requirements of ARO. ARO has not made a cash distribution of earnings to its partners since its formation. See Note 4 included in "Item 8. Financial Statements and Supplementary Data" for additional information on our investment in ARO and notes receivable from ARO. The following table summarizes the maturity schedule of our notes receivable from ARO as ofDecember 31, 2019 (in millions): Maturity Date Principal amount October 2027 $ 275.2 October 2028 177.7 Total $ 452.9 Contractual Obligations We have various contractual commitments related to our new rig construction and rig enhancement agreements, long-term debt and operating leases. We expect to fund these commitments from existing cash and short-term investments and funds borrowed under our credit facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. The actual timing of our new rig construction and rig enhancement payments may vary based on the completion of various milestones, which are beyond our control. The following table summarizes our significant contractual obligations as ofDecember 31, 2019 and the periods in which such obligations are due (in millions): Payments due by period 2020 2021 and 2022 2023 and 2024 Thereafter Total Principal payments on long-term debt$ 122.9 $ 734.3$ 1,763.7 $ 3,907.2 $ 6,528.1 Interest payments on long-term debt 377.4 714.8 634.7 2,536.1 4,263.0 New rig construction agreements(1) (2) - 248.9 - - 248.9 Operating leases 25.4 31.0 18.8 17.2 92.4 Total contractual obligations(3)$ 525.7 $ 1,729.0 $ 2,417.2 $ 6,460.5 $ 11,132.4 (1)During 2019, we entered into amendments to our construction agreements with the shipyard for VALARIS DS-13 and VALARIS DS-14 to provide for, among other things, two-year extensions of the delivery date of each rig in exchange for payment of all accrued holding costs throughMarch 31, 2019 , totaling approximately$23 million . The new delivery dates for the VALARIS DS-13 and VALARIS DS-14 areSeptember 30, 2021 andJune 30, 2022 , respectively. We can elect to request earlier delivery in certain circumstances. The interest rate on the final milestone payments increased from 5% to 7% per annum fromOctober 1, 2019 , for the VALARIS DS-13, and fromJuly 1, 2020 , for the VALARIS DS-14, until the actual delivery dates. The final milestone payments and applicable interest are due at the new delivery dates (or, if accelerated, the actual delivery dates) and are estimated to be approximately$313.3 million in aggregate for both rigs, inclusive of interest, assuming we take delivery on the new delivery date. In lieu 78 -------------------------------------------------------------------------------- of making the final milestone payments, we have the option to take delivery of the rigs and issue a promissory note for each rig to the shipyard owner for the amount due. If we issue the promissory note to the shipyard owner, we would also be required to provide a guarantee fromValaris plc . (2)Total commitments are based on fixed-price shipyard construction contracts, exclusive of our internal costs associated with project management, commissioning and systems integration testing. Total commitments also exclude holding costs and interest. a (3)Contractual obligations do not include$323.1 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as ofDecember 31, 2019 . We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts. In addition, we have a potential obligation to fund ARO for newbuild jackup rigs. In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of$1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. See Note 3 and Note 4 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." for additional information on the Rowan Transaction and our joint venture with ARO, respectively. Other Commitments We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include letters of credit to guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As ofDecember 31, 2019 , we had not been required to make collateral deposits with respect to these agreements. The following table summarizes our other commitments as ofDecember 31, 2019 (in millions): Commitment expiration by period 2020 2021 and 2022 2023 and 2024 Thereafter Total Letters of credit$ 82.7 $ 10.6 $ -$ 6.2 $ 99.5 Liquidity
Our liquidity position as of
2019 2018 2017
Cash and cash equivalents $ 97.2 $ 275.1 $ 445.4
Short-term investments - 329.0 440.0
Available credit facility borrowing capacity 1,622.2 2,000.0 2,000.0
Total liquidity $ 1,719.4 $ 2,604.1 $ 2,885.4
Working capital $ 233.7 $ 781.2 $ 853.5
Current ratio 1.3 2.5 2.1
We expect to fund our liquidity needs, including contractual obligations and
anticipated capital expenditures, as well as working capital requirements, from
our cash, and funds borrowed under our credit facility or future financing
arrangements, including available shipyard financing options for our two
drillships under construction. We may rely on the issuance of debt and/or equity
securities in the future to supplement our liquidity needs. As of December 31,
2019 , we had no amounts drawn under our credit facility and $1.6 billion in
remaining borrowing capacity.
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Our credit facility is an integral part of our financial flexibility and
liquidity. We also may rely on the issuance of debt and/or equity securities in
the future to supplement our liquidity needs. In addition, we may seek to extend
our maturities and reduce the overall principal amount of our debt through
exchange offers or other liability management transactions. We have significant
financial flexibility within our capital structure, including the ability to
issue debt that would be structurally senior to our currently outstanding debt,
on both an unsecured and secured basis, subject to restrictions contained in our
existing debt arrangements. Our liability management efforts, if undertaken, may
be unsuccessful or may not improve our financial position to the extent
anticipated.
Our ability to maintain a sufficient level of liquidity to meet our financial
obligations will also be dependent upon our future performance, which will be
subject to general economic conditions, industry cycles and financial, business
and other factors affecting our operations, many of which are beyond our
control. For example, if we experience further deterioration in demand for
offshore drilling, our ability to maintain a sufficient level of liquidity could
be materially and adversely impacted, which could have a material adverse impact
on our business, financial condition, results of operations, cash flows and our
ability to repay or refinance our debt.
Our access to credit and capital markets is limited because of our credit
rating. Our current credit ratings, and any additional actual or anticipated
downgrades in our corporate credit ratings or the credit rating of our notes
will limit our ability to access credit and capital markets, or to restructure
or refinance our indebtedness. In addition, future financings or refinancings
will result in higher borrowing costs and may require collateral and/or more
restrictive terms and covenants, which may further restrict our operations.
Limitations on our ability to access credit and capital markets could have a
material adverse impact on our financial position, operating results or cash
flows.
Recent Tax Assessments
During 2019, we received income tax assessments totaling approximately €142.0
million (approximately $159.0 million converted using the current period-end
exchange rates) and A$101 million (approximately $70.9 million converted at
current period-end exchange rates) from taxing authorities in Luxembourg and
Australia , respectively. We are contesting these assessments and have filed
applications for appeal. During the third quarter of 2019, we made a A$42
million payment (approximately $29 million at then-current exchange rates) to
the Australian tax authorities to litigate the assessment. We may make a payment
to the Luxembourg tax authorities in advance of the final resolution of these
assessments. Although the outcome of such assessments cannot be predicted with
certainty, unfavorable outcomes could have a material adverse effect on our
liquidity. We have recorded a $119.0 million liability for these assessments as
of December 31, 2019. See Note 12 included in "Item 8. Financial Statements
and Supplementary Data" for additional information on recent tax assessments.
Effects of Climate Change and Climate Change Regulation
Greenhouse gas ("GHG") emissions have increasingly become the subject of
international, national, regional, state and local attention. At the December
2015 Conference of the Parties to the United Nations Framework Convention on
Climate Change held in Paris , an agreement was reached that requires countries
to review and "represent a progression" in their intended nationally determined
contributions to the reduction of GHG emissions, setting GHG emission reduction
goals every five years beginning in 2020. This agreement, known as the Paris
Agreement, entered into force on November 4, 2016 and, as of February 2019 , had
been ratified by 187 of the 197 parties to the United Nations Framework
Convention on Climate Change , including the United Kingdom , the United States
and the majority of the other countries in which we operate. However, in 2019,
the United States formally initiated the process of withdrawing from
participation in the Paris Agreement, with such withdrawal taking place no
earlier than November 4, 2020 . In response to the announced withdrawal plan, a
number of state and local governments in the United States have expressed
intentions to take GHG-related actions by implementing their own programs to
reduce GHG emissions. The United Nations Climate Change Conference held in
Katowice, Poland in December 2018 adopted further rules regarding the
implementation of the Paris Agreement and, in connection with this conference,
numerous countries issued commitments to increase their GHG emission reduction
targets.
80-------------------------------------------------------------------------------- In an effort to reduce GHG emissions, governments have implemented or considered legislative and regulatory mechanisms to institute carbon pricing mechanisms, such as theEuropean Union's Emission Trading System, and to impose technical requirements to reduce carbon emissions. The Companies Act 2006 (Strategic and Directors' Reports) Regulations 2013 now requires all quotedU.K. companies, includingValaris plc , to report their annual GHG emissions in the Company's directors' report. During 2009, theUnited States Environmental Protection Agency (the "EPA ") officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to theEPA , contributing to warming of the earth's atmosphere and other climatic changes. These findings allowed the agency to proceed with the adoption and implementation of regulations to restrict GHG emissions under existing provisions of the Clean Air Act that establish permitting requirements, including emissions control technology requirements, for certain large stationary sources that are potential major sources of GHG emissions. These requirements for stationary sources took effect onJanuary 2, 2011 ; however, inJune 2014 theU.S. Supreme Court reversed aD.C. Circuit Court of Appeals decision upholding these rules and struck down theEPA 's greenhouse gas permitting rules to the extent they impose a requirement to obtain a federal air permit based solely on emissions of greenhouse gases. Large sources of other air pollutants, such as VOC or nitrogen oxides, could still be required to implement process or technology controls and obtain permits regarding emissions of greenhouse gases. TheEPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in theU.S. , including, among others, certain onshore and offshore oil and natural gas production facilities. Although a number of bills related to climate change have been introduced in theU.S. Congress in the past, comprehensive federal climate legislation has not yet been passed byCongress . If such legislation were to be adopted in theU.S. , such legislation could adversely impact many industries. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap and trade programs. Future regulation of GHG emissions could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. Depending on the particular program, we, or our customers, could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. It is uncertain whether any of these initiatives will be implemented. If such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our financial condition, operating results and cash flows in a manner different than our competitors. Restrictions on GHG emissions or other related legislative or regulatory enactments could have an indirect effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. We are currently unable to predict the manner or extent of any such effect. Furthermore, one of the long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs in general and in theGulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could ultimately interfere with our business activities and operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company's causation of or contribution to the asserted damage, or to other mitigating factors. 81
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MARKET RISK
We use derivatives to reduce our exposure to foreign currency exchange rate risk. Our functional currency is theU.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated inU.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than theU.S. dollar. We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. We utilize cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk on future expected contract drilling expenses and capital expenditures denominated in various foreign currencies. We predominantly structure our drilling contracts inU.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. As ofDecember 31, 2019 , we had cash flow hedges outstanding to exchange an aggregate$199.1 million for various foreign currencies. We have net assets and liabilities denominated in numerous foreign currencies and use various strategies to manage our exposure to changes in foreign currency exchange rates. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities, thereby reducing exposure to earnings fluctuations caused by changes in foreign currency exchange rates. We do not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the carrying value of the underlying hedged items. As ofDecember 31, 2019 , we held derivatives not designated as hedging instruments to exchange an aggregate$47.1 million for various foreign currencies. If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities as ofDecember 31, 2019 would approximate$27.1 million . Approximately$1.6 million of these unrealized losses would be offset by corresponding gains on the derivatives utilized to offset changes in the fair value of net assets and liabilities denominated in foreign currencies. We utilize derivatives and undertake foreign currency exchange rate hedging activities in accordance with our established policies for the management of market risk. We mitigate our credit risk relating to counterparties of our derivatives through a variety of techniques, including transacting with multiple, high-quality financial institutions, thereby limiting our exposure to individual counterparties and by entering intoInternational Swaps and Derivatives Association, Inc. ("ISDA") Master Agreements, which include provisions for a legally enforceable master netting agreement, with our derivative counterparties. The terms of the ISDA agreements may also include credit support requirements, cross default provisions, termination events or set-off provisions. Legally enforceable master netting agreements reduce credit risk by providing protection in bankruptcy in certain circumstances and generally permitting the closeout and netting of transactions with the same counterparty upon the occurrence of certain events. We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to foreign currency exchange rate risk and does not expose us to material credit risk or any other material market risk. All our derivatives mature during the next 18 months. See Note 8 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our derivative instruments. 82 --------------------------------------------------------------------------------
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted inthe United States of America requires us to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Our significant accounting policies are included in Note 1 to our consolidated financial statements. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results and that require the most difficult, subjective and/or complex judgments regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of long-lived assets, income taxes and pensions.
Property and Equipment
As ofDecember 31, 2019 , the carrying value of our property and equipment totaled$15.1 billion , which represented 89% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate our estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs. We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires estimates, judgments and assumptions relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. The judgments and assumptions used in determining the useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different asset carrying values and operating results. The useful lives of our drilling rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability and market and economic factors.
Property and equipment held-for-sale is recorded at the lower of net book value or fair value less cost to sell.
During 2019, we recorded a pre-tax, non-cash loss on impairment of$98.4 million related to one floater and one jackup rig, both of which are older, less capable, non-core assets in our fleet. We estimate the aforementioned impairment will cause a decline in depreciation expense of approximately$8.6 million for the year endedDecember 31, 2020 . Our fleet of 24 floater rigs, excluding two rigs under construction, represented 64% of the gross cost and 63% of the net carrying amount of our depreciable property and equipment as ofDecember 31, 2019 . Our floater rigs are depreciated over useful lives ranging from 10 to 35 years. Our fleet of 50 jackup rigs, represented 31% of both the gross cost and of the net carrying amount of our depreciable property and equipment as ofDecember 31, 2019 . Our jackup rigs are depreciated over useful lives ranging from 10 to 30 years. 83 -------------------------------------------------------------------------------- The following table provides an analysis of estimated increases and decreases in depreciation expense from continuing operations that would have been recognized for the year endedDecember 31, 2019 for various assumed changes in the useful lives of our drilling rigs effectiveJanuary 1, 2019 : Increase (decrease) in Estimated (decrease) increase in useful lives of our depreciation expense that would drilling rigs have been recognized (in millions) 10%$(50.8) 20% (93.2) (10%) 61.9 (20%) 138.6
Impairment of Property and Equipment
We recorded pre-tax, non-cash losses on impairment of long-lived assets of$98.4 million ,$40.3 million and$182.9 million during 2019, 2018 and 2017, respectively. See Note 6 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our property and equipment. We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization levels, day rates, expense levels and capital requirements, as well as cash flows generated upon disposition, for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.
Our judgments and assumptions about future cash flows to be generated by our drilling rigs are highly subjective and based on consideration of the following:
• global macroeconomic and political environment,
• historical utilization, day rate and operating expense trends by asset class,
• regulatory requirements such as surveys, inspections and recertification
of our rigs,
• remaining useful lives of our rigs,
• expectations on the use and eventual disposition of our rigs,
• weighted-average cost of capital,
• oil price projections,
• sanctioned and unsanctioned offshore project data,
• offshore economic project break-even data,
• global rig supply and construction orders,
• global rig fleet capabilities and relative rankings, and
• expectations of global rig fleet attrition.
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We collect and analyze the above information to develop a range of estimated
utilization levels, day rates, expense levels and capital requirements, as well
as estimated cash flows generated upon disposition. The most subjective
assumptions that impact our impairment analyses include projections of future
oil prices and timing of global rig fleet attrition, which, in large part,
impact our estimates on timing and magnitude of recovery from the current
industry downturn. However, there are numerous judgments and assumptions unique
to the projected future cash flows of each rig that individually, and in the
aggregate, can significantly impact the recoverability of its carrying value.
The highly cyclical nature of our industry cannot be reasonably predicted with a
high level of accuracy and, therefore, differences between our historical
judgments and assumptions and actual results will occur. We reassess our
judgments and assumptions in the period in which significant differences are
observed and may conclude that a triggering event has occurred and perform a
recoverability test. We recognized impairment charges in recent periods upon
observation of significant unexpected changes in our business climate and
estimated useful lives of certain assets.
There are numerous factors underlying the highly cyclical nature of our industry
that are reasonably likely to impact our judgments and assumptions including,
but not limited to, the following:
• changes in global economic conditions,
• production levels of the
("OPEC"),
• production levels of non-
• advances in exploration and development technology,
• offshore and onshore project break-even economics,
• development and exploitation of alternative fuels,
• natural disasters or other operational hazards,
• changes in relevant law and governmental regulations,
• political instability and/or escalation of military actions in the areas
we operate,
• changes in the timing and rate of global newbuild rig construction, and
• changes in the timing and rate of global rig fleet attrition.
There is a wide range of interrelated changes in our judgments and assumptions that could reasonably occur as a result of unexpected developments in the aforementioned factors, which could result in materially different carrying values for an individual rig, group of rigs or our entire rig fleet, materially impacting our operating results.
Income Taxes
We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As ofDecember 31, 2019 , our consolidated balance sheet included a$72.4 million net deferred income tax liability, a$45.6 million liability for income taxes currently payable and a$323.1 million liability for unrecognized tax benefits, inclusive of interest and penalties. The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies and are based on estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.
We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we may be subject to additional income taxes.
The carrying values of liabilities for income taxes currently payable and
unrecognized tax benefits are based on our interpretation of applicable tax laws
and incorporate estimates, judgments and assumptions regarding the use of tax
planning strategies in various taxing jurisdictions. The use of different
estimates, judgments and assumptions
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--------------------------------------------------------------------------------in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.
We operate in several jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations.
Tax returns are routinely subject to audit in most jurisdictions and tax liabilities occasionally are finalized through a negotiation process. In some jurisdictions, income tax payments may be required before a final income tax obligation is determined in order to avoid significant penalties and/or interest. While we historically have not experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:
• During recent years, the number of tax jurisdictions in which we conduct
operations has increased, and we currently anticipate that this trend will
continue.
• In order to utilize tax planning strategies and conduct operations
efficiently, our subsidiaries frequently enter into transactions with
affiliates that are generally subject to complex tax regulations and are
frequently reviewed and challenged by tax authorities.
• We may conduct future operations in certain tax jurisdictions where tax
laws are not well developed, and it may be difficult to secure adequate
professional guidance.
• Tax laws, regulations, agreements, treaties and the administrativepractices and precedents of tax authorities change frequently, requiring
us to modify existing tax strategies to conform to such changes.
Pension and Other Postretirement Benefits
Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions atDecember 31, 2019 , included (i) a weighted average discount rate of 3.16% to determine pension benefit obligations, (ii) a weighted average discount rate of 3.82% to determine net periodic pension cost and (iii), an expected long-term rate of return on pension plan assets of 6.48%. The assumed discount rate is based upon the average yield for Moody's Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately$108.8 million , while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately$4.0 million . To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans' other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which was 6.48% atDecember 31, 2019 .
NEW ACCOUNTING PRONOUNCEMENTS
See Note 1 to our consolidated financial statements included in "Item 8.
Financial Statements and Supplementary Data" for information on new accounting
pronouncements.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information required under Item 7A. has been incorporated into "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."
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