Item 1. Business
General
Ensco plc is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Ensco," "Company," "we," "us" and "our" refer to Ensco plc together with all its subsidiaries and predecessors.
We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We currently own and operate an offshore drilling rig fleet of 70 rigs, including seven rigs currently under construction, with drilling operations in most of the strategic markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, five moored semisubmersible rigs and 42 jackup rigs. Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is one of the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.
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 and drilling contracts spanning approximately 20 countries on six continents in nearly every major offshore basin around the world. The markets in which we operate include the U.S. Gulf of Mexico, Mexico, Brazil, the Mediterranean, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.
We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide a drilling rig and rig crews and receive a fixed amount per day for each day we are performing drilling or related services. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.
Acquisitions
We have grown our rig fleet through corporate acquisitions and new rig construction. A total of seven drillships, ten semisubmersible rigs and 25 jackup rigs in our current fleet were obtained through the acquisitions of Penrod Holding Corporation during 1993, Dual Drilling Company during 1996, Chiles Offshore Inc. during 2002 and Pride International, Inc. ("Pride") during 2011. Through the acquisition of Pride, we added drillships to our asset base and increased our presence in Angola and Brazil.
Drilling Rig Construction and Delivery
We remain focused on our long-established strategy of high-grading our fleet. We will continue to invest in the expansion of our fleet where we believe strategic opportunities exist. During the three-year period ended December 31, 2014, we invested $3.3 billion in the construction of new drilling rigs.
During the second quarter, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs. ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTorneau Super 116E jackup design and will incorporate Ensco's patented Canti-Leverage AdvantageSM technology. These rigs are scheduled for delivery during the second quarter and the third quarter of 2016, respectively. Both of these rigs are currently uncontracted.
During 2013, we entered into agreements with KFELS to construct a premium jackup rig (ENSCO 110) and an ultra-premium harsh environment jackup rig (ENSCO 123). These rigs are scheduled for delivery during the first quarter of 2015 and the second quarter of 2016, respectively. Both of these rigs are currently uncontracted.
We previously entered into agreements with KFELS to construct three ultra-premium harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122). ENSCO 122 was delivered during the third quarter of 2014 and commenced drilling operations under a long-term contract in the North Sea during the fourth quarter of 2014. ENSCO
121 was delivered during the fourth quarter of 2013 and commenced drilling operations under a long-term contract in the North Sea during the second quarter. ENSCO 120 was delivered during the third quarter of 2013 and commenced drilling operations under a long-term contract in the North Sea during the first quarter.
We currently have three ultra-deepwater drillships under construction (ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10). ENSCO DS-9 and ENSCO DS-8 are committed under long-term contracts and currently scheduled for delivery during the first quarter and second quarter of 2015, respectively. ENSCO DS-10 is currently uncontracted and scheduled to be delivered by the shipyard during the third quarter of 2015.
We expect that cash flow generated during 2015 will primarily be used to fund capital expenditures, most notably milestone payments for newbuild rigs. Based on our balance sheet and contractual backlog of $9.7 billion, we believe future capital projects, debt service and dividend payments will primarily be funded from cash and cash equivalents, future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital, refinance existing debt or increase liquidity as necessary.
Divestitures
Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Consistent with this strategy, we sold eleven jackup rigs, two moored semisubmersible rigs and our last remaining barge rig during the three-year period ended December 31, 2014. We are currently marketing for sale an additional seven rigs, which were classified as "held for sale" in our financial statements as of December 31, 2014.
Redomestication
Our predecessor, ENSCO International Incorporated ("Ensco Delaware"), was formed as a Texas corporation during 1975 and reincorporated in Delaware during 1987. During 2009, we completed a reorganization of the corporate structure of the group of companies controlled by Ensco Delaware, pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company incorporated under the Laws of England and Wales (the "redomestication").
The redomestication was accounted for as an internal reorganization of entities under common control and, therefore, Ensco Delaware's assets and liabilities were accounted for at their historical cost basis and not revalued in the transaction. We remain subject to the U.S. Securities and Exchange Commission ("SEC") reporting requirements, the mandates of the Sarbanes-Oxley Act of 2002, as amended, and the applicable corporate governance rules of the New York Stock Exchange ("NYSE"). We continue to report our consolidated financial results in U.S. dollars and in accordance with U.S. generally accepted accounting principles ("U.S. GAAP"), but must also comply with reporting requirements under English law.
Our principal executive office is located at 6 Chesterfield Gardens, London W1J5BQ, England, United Kingdom, and our telephone number is +44 (0) 20 7659 4660. Our website is www.enscoplc.com. Information contained on our website is not included as part of, or incorporated by reference into, this report.
Contract Drilling Operations
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
We currently own and operate an offshore drilling rig fleet of 70 rigs, including seven rigs under construction. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, five moored semisubmersible rigs and 42 jackup rigs. Of our 70 rigs, 17 are currently located in North and South America (excluding Brazil), 17 are located in the Middle East and Africa (including two rigs under construction), 17 are located in the Asia Pacific rim (including five rigs under construction), 15 are located in Europe and the Mediterranean and four are located in Brazil.
Our drilling rigs drill and complete oil and natural gas wells. Demand for our drilling services is based upon many factors beyond our control. See “Item 1A.
Item 1A. Risk Factors
Risks Related to Our Business
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.
The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.
Brent crude oil prices have fallen during the last five months, from $95 per barrel to $60 per barrel on February 23, 2015. Operators have announced significant declines in capital spending in their 2015 budgets, including the cancellation or deferral of existing programs. These declines in capital spending levels, coupled with additional newbuild supply, have put significant pressure on day rates and utilization. The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production. Oil and natural gas prices, and market expectations of potential changes in these prices, may continue to significantly affect the level of drilling activity. The decline, or the perceived risk of a further decline, in oil and/or natural gas prices could cause oil and gas companies to further reduce their overall level of activity or spending, in which case demand for our services may further decline and revenues may continue to be adversely affected through lower rig utilization and/or lower day rates. Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:
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oil and natural gas supply and demand,
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expectations regarding future energy prices,
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the ability of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain production levels and pricing,
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capital allocation decisions by our customers, including the relative economics of offshore development versus onshore prospects,
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the level of production by non-OPEC countries,
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U.S. and non-U.S. tax policy,
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laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, or materially increase the cost of such exploration and development,
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advances in exploration and development technology,
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disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof,
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the cost of exploring for, developing, producing and delivering oil and natural gas,
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rate of discovery of new reserves,
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local and international political, economic and weather conditions,
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the development and exploitation of alternative fuels,
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the worldwide military or political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism, and
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global economic conditions.
Any prolonged reduction in oil and natural gas prices will depress the levels of exploration, development and production activity. In addition, continued hostilities in foreign countries and the occurrence or threat of terrorist attacks against the United States or other countries could create downward pressure on the economies of the United States and other countries. Moreover, even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. Advances in onshore exploration and development technologies, particularly with respect to onshore shale plays, could result in our customers allocating more of their capital expenditure budgets to onshore exploration and production activities and less to offshore activities. These factors could cause our revenues and margins to decline, as a result of declines in utilization and day rates, and limit our future growth prospects. Any significant decrease in day rates or utilization of our rigs, particularly our high-specification floaters, could materially reduce our revenues and profitability. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain insurance coverage that we consider adequate or are otherwise required by our contracts.
Deterioration of the global economy and/or a continued decline in oil and natural gas prices could cause our customers to reduce spending on exploration and development drilling. These conditions also could cause our customers and/or vendors to fail to fulfill their commitments and/or fund their future operations and obligations, which could have a material adverse effect on our business.
The success of our business largely depends on the level of activity in offshore oil and natural gas exploration and development drilling worldwide. Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling activity.
A continued decline in oil and natural gas prices, whether caused by OPEC, economic conditions, international or national climate change and/or environmental regulations or other factors, could cause oil and gas companies to reduce their overall level of drilling activity and spending. Disruption in the capital markets could also cause oil and gas companies to reduce their overall level of drilling activity and spending. These conditions could cause our customers and vendors to fail to fulfill their commitments to us.
Historically, when drilling activity and spending decline, utilization and day rates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. The oversupply of drilling rigs will be exacerbated by the entry of newbuild rigs into the market. When idled or stacked, drilling rigs do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items.
A further decline in oil and natural gas prices, together with a deterioration of the global economy, could substantially reduce demand for drilling rigs and result in a material adverse effect on our financial position, operating results or cash flows.
The offshore contract drilling industry historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.
Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical capabilities also can be significant factors in the determination. In addition, consolidations within the oil and gas industry have reduced the number of available customers, resulting in increased competition for projects. If we are not able to compete successfully, our revenues and profitability may be reduced.
Financial operating results in the offshore contract drilling industry historically have been very cyclical and are primarily related to the demand for drilling rigs and the available supply of drilling rigs. Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.
The supply of offshore drilling rigs has increased in recent years. There are 200 newbuild drillships, semisubmersibles and jackup rigs reported to be on order or under construction with delivery expected by the end of 2020. Approximately 90 of these rigs are scheduled for delivery during 2015, representing an approximate 11% increase in the total worldwide fleet of offshore drilling rigs. There are no assurances that the market in general or a geographic region in particular will be able to fully absorb the supply of new rigs in future periods.
The increase in supply of offshore drilling rigs during 2014 and early 2015 resulted in an oversupply of offshore drilling rigs and a decline in utilization and/or day rates, a situation which, if it persists for the next few years, could be exacerbated by a prolonged decline in demand for drilling rigs. Lower utilization and/or day rates in one or more of the regions in which we operate could adversely affect our revenues and profitability.
Certain events, such as limited availability or non-availability of insurance for certain perils in some geographic areas, rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events, may also impact the supply of rigs in a particular market and cause rapid fluctuations in utilization and day rates.
Future periods of reduced demand and/or excess rig supply may require us to idle additional rigs or enter into lower day rate contracts or contracts with less favorable terms. There can be no assurance that the current demand for drilling rigs will not decline in future periods. A decline in demand for drilling rigs or an oversupply of drilling rigs could adversely affect our financial position, operating results and cash flows.
Our business will be adversely affected if we are unable to secure contracts on economically favorable terms.
Our ability to renew expiring contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the day rates under any new contracts may be substantially below the existing day rates, which could adversely affect our revenues and profitability.
Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities resulting from operations under the contract.
Certain of our customers are subject to liquidity risk and such risk could lead them to seek to repudiate, cancel or renegotiate our drilling contracts for various reasons. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. Our drilling contracts also provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to loss or damage to property and injury or death to persons arising from the drilling operations we perform. Under our drilling contracts, liability with respect to personnel and property customarily is generally allocated so that we and our customers each assume liability for our respective personnel and property. Our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination, including clean-up and removal, third-party damages, and fines and penalties arising from operations
under the contract when the source of the pollution originates from the well or reservoir, including those resulting from blow-outs or cratering of the well. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to assume their responsibility, or honor their indemnity to us, for such losses. In addition, under the laws of certain jurisdictions, such indemnities are not enforceable if the cause of the damage was our gross negligence or willful misconduct. This could result in our having to assume liabilities not otherwise contemplated in our contracts due to customer balance sheet or liquidity issues.
We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.
Our drilling contracts often are subject to termination without cause upon notice by the customer. Although contracts may require the customer to pay an early termination payment in the event of a termination for convenience (without cause), such payment may not fully compensate for the loss of the contract, and some of our contracts permit termination by the customer without an early termination payment. In periods of rapid market downturn similar to the current environment, our customers may not be able to honor the terms of existing contracts (including contracts for new rigs under construction), may terminate contracts even where there may be onerous termination fees, or may seek to renegotiate contract day rates and terms in light of depressed market conditions.
Drilling contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.
If a customer cancels a contract or if we elect to terminate a contract due to the customer’s nonperformance and, in either case, we are unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is disputed or suspended for an extended period of time or renegotiated, it could materially and adversely affect our financial condition, results of operations and cash flows.
The loss of a significant customer could adversely affect us.
We provide our services to major international, government-owned and independent oil and gas companies. During 2014, our five largest customers accounted for 49% of our consolidated revenues in the aggregate, with our largest customer representing 16% of our consolidated revenues. Our financial position, operating results and cash flows may be materially adversely affected if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.
Our current backlog of contract drilling revenue may not be fully realized, which may have a material adverse effect on our financial position, results of operations or cash flows.
As of December 31, 2014, our contract backlog was approximately $9.7 billion. This amount reflects the remaining contractual terms multiplied by the applicable contractual day rate. The contractual revenue may be higher than the actual revenue we receive because of a number of factors, including rig downtime or suspension of operations. Several factors could cause rig downtime or a suspension of operations, many of which are beyond our control, including:
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breakdowns of equipment;
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work stoppages, including labor strikes;
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shortages of material and skilled labor;
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surveys by government and maritime authorities;
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periodic classification surveys;
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severe weather, strong ocean currents or harsh operating conditions;
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the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat;
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the early termination of contracts; and
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force majeure events.
Liquidity issues could lead our customers to go into bankruptcy or could encourage our customers to seek to repudiate, cancel or renegotiate our drilling contracts for various reasons. Some of our drilling contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice to us and in some cases without making an early termination payment to us. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.
The recent decline in oil prices, the perceived risk of a further decline in oil prices, and the resulting downward pressure on utilization is causing some customers to consider early termination of select contracts despite having to pay onerous early termination fees in some cases. We are currently in discussions with some of our customers regarding these issues. Customers may request to re-negotiate the terms of existing contracts, or they may request early termination in some circumstances. Therefore, revenues recorded in future periods could differ materially from our current backlog. Our inability to realize the full amount of our contract backlog may have a material adverse effect on our financial position, results of operations or cash flows.
We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage may not protect us against all of the risks and hazards we face, including those specific to offshore operations.
Our operations are subject to hazards inherent in the offshore drilling industry, such as blow-outs, reservoir damage, loss of production, loss of well control, uncontrolled formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punchthroughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Additionally, a security breach of our information systems or other technological failure could lead to a material disruption of our operations, information systems, and/or loss of business information, which could result in an adverse impact to our business. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks.
We generally identify the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost of coverage, the requirements of our customer contracts and applicable legal requirements. Although we maintain what we believe to be an appropriate level of insurance covering hazards and risks we currently encounter during our operations, no assurance can be given that we will be able to obtain insurance against all potential risks and hazards.
Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes.
If we are unable to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable, we may choose to forgo insurance coverage and retain the associated risk of loss or damage.
If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position, results of operations or cash flows.
The potential for U.S. Gulf of Mexico hurricane related windstorm damage or liabilities could result in uninsured losses and may cause us to alter our operating procedures during hurricane season, which could adversely affect our business.
Certain areas in and near the U.S. Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the U.S. Gulf of Mexico are located in areas that could cause them to be susceptible to damage and/or total loss by these storms, and we have a larger concentration of jackup rigs in the U.S. Gulf of Mexico than most of our competitors. We currently have eight jackup rigs and nine floaters in the U.S. Gulf of Mexico. Damage caused by high winds and turbulent seas could result in rig loss or damage, termination of drilling contracts for lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. Our drilling operations in the U.S. Gulf of Mexico have been impacted by hurricanes, including the total loss of one jackup rig during 2004, one platform rig during 2005 and two jackup rigs during 2008, with associated losses of contract revenues and potential liabilities.
Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the U.S. Gulf of Mexico during 2004, 2005 and 2008. Accordingly, insurance companies have substantially reduced the nature and amount of insurance coverage available for losses arising from named tropical storm or hurricane damage in the U.S. Gulf of Mexico ("windstorm damage") and have dramatically increased the cost of available windstorm coverage. The tight insurance market not only applies to coverage related to U.S. Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for any potential liabilities to third parties associated with property damage, personal injury or death and environmental liabilities, as well as coverage for removal of wreckage and debris associated with hurricane losses. We have no assurance that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will not continue into the foreseeable future.
We decided not to purchase windstorm insurance for hull and machinery losses to our floaters arising from windstorm damage in the U.S. Gulf of Mexico upon renewal of our annual insurance policies effective May 31, 2014, due to the significant premium, high deductible and limited coverage for windstorm damage. We opted out of windstorm insurance for our jackups in the U.S. Gulf of Mexico during 2009 and have not since renewed that insurance. We believe it is no longer customary for drilling contractors with similar size and fleet composition to purchase windstorm insurance for rigs in the U.S. Gulf of Mexico, for the aforementioned reasons. Accordingly, we have retained the risk of loss or damage for our eight jackup rigs and our nine floaters arising from windstorm damage in the U.S. Gulf of Mexico.
We have established operational procedures designed to mitigate risk to our jackup rigs in the U.S. Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, our procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. These procedures may result in a decision to decline to operate on a customer-designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the U.S. Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm-related risks, may result in a significant reduction in the utilization of our jackup rigs in the U.S. Gulf of Mexico.
Our annual insurance policies are up for renewal effective May 31, 2015, and any retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with U.S. Gulf of Mexico tropical storms or hurricanes could have a material adverse effect on our financial position, operating results and cash
flows if we sustain significant uninsured or underinsured losses or liabilities as a result of U.S. Gulf of Mexico tropical storms or hurricanes.
We may incur asset impairments as a result of future declines in demand for offshore drilling rigs.
During the year ended December 31, 2014, we recorded a pre-tax, non cash loss on impairment of long-lived assets of $2,463.1 million, of which $1,220.8 million was included in (loss) income from continuing operations and $1,242.3 million was included in (loss) income from discontinued operations, net in our consolidated statement of operations. See "Note 3 - Property and Equipment" to our consolidated financial statements for additional information on our property and equipment. As of December 31, 2014, the carrying value of our property and equipment totaled $12.5 billion, which represented 78% of our total assets.
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. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until day rates increase when the supply/demand balance is restored. However, if the global economy were to deteriorate and/or the offshore drilling industry were to incur a significant prolonged downturn, additional impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.
During the year ended December 31, 2014, we recorded a $3.0 billion non-cash loss on impairment of our Floaters reporting unit goodwill. See "Note 8 - Goodwill and Other Intangible Assets and Liabilities" to our consolidated financial statements for additional information on our goodwill. As of December 31, 2014, the carrying value of our goodwill totaled $276.1 million, which represented 2% of total assets.
We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units, perform a qualitative assessment of the likelihood that a reporting unit’s carrying value exceeds its estimated fair value, and in certain circumstances estimate each reporting unit's fair value as of the testing date. In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including expected utilization, day rates, expense levels, capital requirements and terminal values for each of our rigs. If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium. If we determine the implied control premium is not reasonable, we adjust the discount rate or other assumptions used in our discounted cash flow model and reduce the estimated fair values of our reporting units.
If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, our expectations of future cash flows may decline and could ultimately result in additional goodwill impairment. Additionally, a significant decline in the market value of our shares could result in additional goodwill impairment.
Our non-U.S. operations involve additional risks not associated with U.S. operations.
Revenues from non-U.S. operations were 62%, 61% and 65% of our total revenues during 2014, 2013 and 2012, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:
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terrorist acts, war and civil disturbances,
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expropriation, nationalization, deprivation or confiscation of our equipment,
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expropriation or nationalization of a customer's property or drilling rights,
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repudiation or nationalization of contracts,
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assaults on property or personnel,
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piracy, kidnapping and extortion demands,
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significant governmental influence over many aspects of local economies,
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unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,
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work stoppages, often due to strikes over which we have little or no control,
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complications associated with repairing and replacing equipment in remote locations,
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limitations on insurance coverage, such as war risk coverage, in certain areas,
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imposition of trade barriers,
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wage and price controls,
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import-export quotas,
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exchange restrictions,
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currency fluctuations,
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changes in monetary policies,
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uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,
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changes in the manner or rate of taxation,
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limitations on our ability to recover amounts due,
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increased risk of government and vendor/supplier corruption,
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increased local content requirements,
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the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat;
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changes in political conditions, and
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other forms of government regulation and economic conditions that are beyond our control.
We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Moreover, we may initiate a self-insurance program through one or more captive insurance subsidiaries. In circumstances where we have insurance protection for some or all of the risks associated with non-U.S. operations, such insurance may be subject to cancellation on short notice, and it is unlikely that we would be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured, underinsured or self-insured, or for which we have not received an enforceable contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results and cash flows.
We are subject to various tax laws and regulations in substantially all countries in which we operate or have a legal presence. We evaluate applicable tax laws and employ various business structures and operating strategies to
obtain the optimal level of taxation on our revenues, income, assets and personnel. Actions by tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of any of the foregoing, changes in the administrative practices and precedents of tax authorities, adverse rulings in connection with audits or otherwise, or other challenges may substantially increase our tax expense.
As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.
Our non-U.S. operations also face the risk of fluctuating currency values, which may impact our revenues, operating costs and capital expenditures. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Generally, we have contractually mitigated these risks by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting our acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, not all of our contracts contain these terms and there is no assurance that our contracts will contain such terms in the future.
A portion of the costs and expenditures incurred by our non-U.S. operations, including a portion of the construction payments for new rigs, are settled in local currencies, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency forward contracts to reduce this exposure in certain cases.. However, a relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.
Our non-U.S. operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirements for equipment. We may be required to make significant capital expenditures to operate in such countries, which may not be reimbursed by our customers. Governments in some non-U.S. countries have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding concessions, the exploration of oil and natural gas and other aspects of the oil and gas industry in their countries. In addition, government action, including initiatives by OPEC, may continue to cause oil and/or natural gas price volatility. In some areas of the world, government activity has adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures or impose specific quotas for local goods and services, which can increase our operational costs and place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our future operations.
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by specific customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, exclusion from government contracts, seizure of shipments and loss of import and export privileges.
Our employees, contractors and agents may take actions in violation of our policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate. Any such violation, even if prohibited by our policies, could have a material adverse effect on our financial position, operating results or cash flows.
Rig construction, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could have a material adverse effect on our operating results. The risks are concentrated because our three ultra-deepwater drillships currently under construction are at a single shipyard in South Korea and our four jackup rigs currently under construction are at two shipyards in Dubai and Singapore.
There are 200 new offshore drilling rigs reported to be on order or under construction with expected delivery dates through 2020. As a result, shipyards and third-party equipment vendors are under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays and/or equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction work or other unexpected difficulties including equipment failures, design or engineering problems that could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.
We currently have three ultra-deepwater drillships and four jackup rigs under construction. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. Some of these expenditures are unplanned.
Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:
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failure of third-party equipment to meet quality and/or performance standards,
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delays in equipment deliveries or shipyard construction,
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shortages of materials or skilled labor,
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damage to shipyard facilities or construction work in progress, including damage resulting from fire, explosion, flooding, severe weather, terrorism, war or other armed hostilities,
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unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment,
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unanticipated actual or purported change orders,
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strikes, labor disputes or work stoppages,
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financial or operating difficulties of equipment vendors or the shipyard while constructing, enhancing, upgrading, improving or repairing a rig or rigs,
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unanticipated cost increases,
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foreign currency exchange rate fluctuations impacting overall cost,
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inability to obtain the requisite permits or approvals,
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client acceptance delays,
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disputes with shipyards and suppliers,
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latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions,
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claims of force majeure events, and
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additional risks inherent to shipyard projects in a non-U.S. location.
Our risks are concentrated because our seven rigs currently under construction are at three shipyards.
Two of our seven rigs currently under construction, ENSCO DS-8 and ENSCO DS-9, have secured drilling contracts upon completion of construction and are scheduled to be delivered during the first half of 2015. ENSCO DS-10, ENSCO 110, ENSCO 123, ENSCO 140 and ENSCO 141 are scheduled to be delivered beginning in the first half of 2015 through the second half of 2016. There is no assurance that we will secure drilling contracts for these rigs, or future rigs we construct, or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contractual commitments for these rigs at rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results and cash flows. With respect to our rigs under construction, we are subject to the risk of delays and other hazards that could impact the viability of the contracts and could have a material adverse effect on our financial position, operating results and cash flows.
Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.
We currently own and operate 16 rigs and manage four rigs contracted with national oil companies. The terms of these contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. We can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.
Legal and regulatory proceedings could affect us adversely.
We are involved in litigation, including various claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to intellectual property, commercial, operational, employment, regulatory, or other activities.
We operate in a number of countries throughout the world, including countries known to have a reputation for corruption and are subject to the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”), the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") regulations, the U.K. Bribery Act ("UKBA"), other U.S. laws and regulations governing our international operations and similar laws in other countries.
In 2010, Pride and its subsidiaries resolved with the U.S. Department of Justice (“DOJ”) and the SEC their previously disclosed investigations into potential violations of the FCPA. However, Pride has received preliminary inquiries from governmental authorities of certain of the countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of our rigs or other assets. At this stage of such inquiries, we are unable to determine what, if any, legal liability may result. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our Company. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.
Any violation of the FCPA, OFAC regulations, the UKBA or other applicable anti-corruption laws, by us, our affiliated entities or their respective officers, directors, employees and agents could result in substantial fines, sanctions,
civil and/or criminal penalties and curtailment of operations in certain jurisdictions and could adversely affect our financial condition, results of operations, cash flows or our availability of funds under our revolving credit facility. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations.
Increases in regulatory requirements, particularly in the U.S. Gulf of Mexico, could significantly increase our costs. In recent years, we have seen several significant regulatory changes that have affected the way we operate in the U.S. Gulf of Mexico.
Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. The U.S. Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"), and one of its successor agencies, the Bureau of Safety and Environmental Enforcement ("BSEE"), have issued guidelines for jackup rig fitness requirements during hurricane seasons, which have been in effect through November 2014. As a result of these BOEMRE guidelines, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig's hull) during hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and gas companies operating in the U.S. Gulf of Mexico. BSEE may take other steps that could increase the cost of operations or reduce the area of operations. Implementation of BSEE guidelines and regulations may subject us to increased costs and limit the operational capabilities of our rigs.
Similarly, as a result of the Macondo well incident in the U.S. Gulf of Mexico, the U.S. Department of the Interior issued Notices to Lessees (“NTLs"), implementing new regulations applicable to drilling operations in the U.S. Gulf of Mexico. Current or future NTLs or other rules, directives and regulations may further impact our customers' ability to obtain permits and commence or continue deep or shallow water operations in the U.S. Gulf of Mexico. Future legislative or regulatory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.
Also as a result of the Macondo well incident, BOEMRE and BSEE have promulgated regulations regarding safety and environmental management systems ("SEMS"). In 2013, BSEE adopted a final rule modifying the SEMS requirements. Although the SEMS requirements are directed primarily at operators, they have an indirect impact on contractors, including requirements for personnel training, written safe work practices and written agreements with operators regarding the application of the operators' and contractors' safety and environmental policies at the worksite. In addition, BSEE has stated that it is considering requiring contractors to have their own SEMS programs and that it might address that possibility in future rulemaking. The current SEMS regulations and the possibility of additional SEMS rules for contractors could expose us to increased costs.
In 2012, BSEE also issued an interim policy document for use by BSEE inspectors in issuing incidents of noncompliance (“INCs”) to contractors conducting operations under BSEE jurisdiction on the Outer Continental Shelf of the U.S. Gulf of Mexico. The stated purpose of the policy is to provide for consistency in application of BSEE enforcement authority by establishing guidelines for issuance of INCs to contractors in addition to operators. The policy indicates that BSEE's enforcement actions will continue to focus primarily on lessees and operators, but makes it clear that BSEE will “in appropriate circumstances” also issue INCs to contractors for "serious violations" of BSEE regulations. Further, the industry has adopted new standards, including API Standard 53 relating to the maintenance, inspection and testing of well control equipment. The imposition of INCs on contractors exposes us to fines and penalties for violation of BSEE regulations and the new standards expose us to increased costs and loss of revenue.
New regulatory, legislative, permitting or certification requirements in the U.S., including laws and regulations that have or may impose increased financial responsibility, oil spill abatement contingency plan capability requirements, or additional operational requirements and certifications, could materially adversely affect our financial condition, operating results or cash flows.
We anticipate that government regulation in other countries where we operate may follow the U.S. in regard to enhanced safety and environmental regulation, which could also result in governments imposing sanctions on contractors for operators not complying with regulations that impact drilling operations. Even if not a requirement in these countries, most international operating companies, and many others, are voluntarily complying with some or all of the U.S. inspections and safety and environmental guidelines when operating outside the U.S. Such additional governmental regulation and voluntary compliance by operators could increase the cost of our operations and expose us to greater liability.
Laws and governmental regulations may add to costs, limit our drilling activity or reduce demand for our drilling services.
Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including initiatives to limit greenhouse gas emissions. The offshore contract drilling industry is dependent on demand for services from the oil and gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could reduce the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs.
Geopolitical events, terrorist attacks, piracy and military action could affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.
Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses. Military action by the United States or other nations could escalate, and acts of terrorism, piracy, kidnapping, extortion, acts of war, violence, civil war, or general disorder may initiate or continue. Such acts could be directed against companies such as ours. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could affect the markets for our products and services. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could have a material adverse effect on our financial position, operating results or cash flows.
Failure to recruit and retain skilled personnel could adversely affect our operations and financial results.
We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Competition for skilled and other labor has intensified as additional, more technically advanced, rigs are added to the worldwide fleet. There are 200 newbuild offshore drilling rigs reported to be on order or under construction with delivery expected by the end of 2020. These rigs will require more workers with specialized training and skills to operate. In periods of high utilization, it is more difficult and costly to recruit and retain qualified employees, especially in foreign countries that require a certain percentage of national employees. Competition for such personnel could increase our future operating expenses, with a resulting reduction in net income, or impact our ability to fully staff and operate our rigs. We may also incur additional costs to provide training for prospective employees for skilled positions on our newer rigs.
We may be required to maintain or increase existing levels of compensation to retain our skilled workforce, especially if our competitors raise their wage rates. Much of the skilled workforce is nearing retirement age, which may impact the availability of skilled personnel. We also are subject to potential legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs and create the potential for more work stoppages, which may be beyond our control.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
A large percentage of our employees in non-U.S. markets are protected by collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel expenses and other benefits. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.
Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial condition, operating results or cash flows.
Compliance with or breach of environmental laws can be costly and could limit our operations.
Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment. However, the legislative, judicial and regulatory response to a well incident could substantially increase our and our customers' liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.
The International Convention on Oil Pollution Preparedness, Response and Cooperation, Marpol 73/78, the U.K. Merchant Shipping Act 1995, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998, and other related legislation and regulations and Oil Pollution Act of 1990 ("OPA 90"), the Clean Water Act and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Although the OPA 90 provides for certain limits of liability, such limits are not applicable where there is any safety violation or where gross negligence is involved. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows. Further, remedies under the Clean Water Act and related legislation and the OPA 90 do not preclude claims under state regulations or civil claims for damages to third parties under state laws.
Events in recent years, including the Macondo well incident, have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. We are adversely affected by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the adoption of associated new safety requirements and policies regarding the approval of drilling permits, restrictions on development and production activities in the U.S. Gulf of Mexico and associated rules, directives and regulations that have and may further impact our operations. If new laws are enacted or other government action is taken that restrict or prohibit offshore drilling in our principal
areas of operation or impose environmental protection requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, our financial position, operating results and cash flows could be materially adversely affected.
Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2014, we had $5.9 billion in total debt outstanding, representing approximately 42% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including:
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a portion of our cash flows from operations will be dedicated to the payment of principal and interest;
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covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and
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our ability to obtain additional financing to fund working capital requirements, capital expenditures, acquisitions, dividend payments and general corporate or other cash requirements may be limited.
Our ability to maintain a sufficient level of liquidity to meet our financial obligations will 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. Our future cash flows may be insufficient to meet all of our working capital requirements, debt obligations and contractual commitments, and any insufficiency could negatively impact our business.
To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, or if available, such additional indebtedness or equity financing may not be available on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell additional assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.
In addition, our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. A decrease in our credit ratings would increase our borrowing costs and adversely affect our ability to raise capital. In addition, we may not be able to obtain favorable credit terms from our suppliers or they may require us to provide collateral, letters of credit, or other forms of security, which would increase our operating costs. As a result, a downgrade in our credit ratings, particularly below investment grade, could have a material adverse impact on our financial position, results of operations, and liquidity.
We have historically made substantial capital expenditures to maintain our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness, to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, each of which could adversely affect our financial condition, result of operations and cash flows.
We have historically made substantial capital expenditures to maintain our fleet. These expenditures could increase as a result of changes in:
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offshore drilling technology;
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the cost of labor and materials;
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customer requirements;
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fleet size;
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the cost of replacement parts for existing drilling rigs;
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the geographic location of the drilling rigs;
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length of drilling contracts;
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governmental regulations and maritime self-regulatory organization and technical standards relating to safety, security or the environment; and
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industry standards.
Changes in offshore drilling technology, customer requirements for new or upgraded equipment and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. In addition, changes in governmental regulations, relating to safety or equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. As a result, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic lives.
Additionally, in order to expand our fleet, we may require additional capital in the future. If we are unable to fund capital with cash flows from operations or sales of non-core assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations (or interpretation thereof) and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. If we raise funds by issuing equity securities, existing shareholders may experience dilution. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business and on our financial condition, results of operations and cash flows.
Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier
quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to potential volatility in the quality, prices and availability of such items. Certain high-specification parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Recent industry consolidation has reduced the number of available suppliers. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, thus adversely impacting our operations and revenues or increase our operating costs.
Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability.
In general, our costs increase as the demand for contract drilling services and skilled labor increases. While many of our contracts include cost escalation provisions that allow changes to our day rate based on stipulated cost increases or decreases, the timing and amount earned from these day rate adjustments may differ from our actual increase in costs and certain contracts do not allow for such day rate adjustments. During times of reduced demand, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses
fluctuate depending upon the type of activity a drilling rig is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required.
Our information technology systems are subject to cybersecurity risks and threats.
We depend on technologies, systems, and networks to conduct our offshore and onshore operations, to collect payments from customers and to pay vendors and employees. The risks associated with cyber incidents and attacks to our information technology systems could include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations; loss of intellectual property, proprietary information or customer data; disruption of our customers' operations; and increased costs to prevent, respond to or mitigate cybersecurity events. If we were to experience a cyber-attack or incident, it could adversely affect our financial position, results of operations and cash flows.
Tax authorities may challenge our tax positions, and we may not be able to realize expected tax benefits.
Our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations or their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our positions, we may incur significant expenses in defending our position and contesting claims or positions asserted by tax authorities. If we are unsuccessful in defending them, such audits could significantly impact our consolidated effective income tax rate in past or future periods.
We cannot provide any assurances as to what our consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. If we are unable to mitigate the negative consequences of any change in law, audit or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.
Governments may pass laws that subject us to additional taxation or may challenge our tax positions, which could adversely affect our financial position, results of operations and cash flows.
There is increasing uncertainty with respect to tax laws, regulations and treaties, and the interpretation and enforcement thereof that may affect our business. In July 2014, the U.K. government enacted tax reforms to ensure that more of the profits generated by offshore drilling contractors in the U.K. are subject to U.K. taxation. The reforms limit the amount of certain types of lease payments that can be deducted for U.K. tax purposes. In addition, the reforms prohibit taxable profits from operations on the U.K. Continental Shelf from being reduced by unrelated losses or expenses. Other countries are evaluating legislative and regulatory reforms that would subject us to additional taxation or otherwise challenge our tax positions. Further, our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations or their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our positions, we may incur significant expenses in defending our position and contesting claims or positions asserted by tax authorities. If we are unsuccessful in defending them, such audits could significantly impact our consolidated effective income tax rate in past or future periods.
As a result of these uncertainties, as well as changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements, we cannot provide any assurances as to what our consolidated effective income tax rate will be in future periods. If we are unable to mitigate the negative consequences of any change in law, audit or other matter, this could cause our
consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.
Risks Related to Our Redomestication to the U.K.
There are risks associated with the issuance and trading of our Class A ordinary shares that were not associated with our American Depositary Shares ("ADS").
In connection with the May 2012 termination of our ADS facility and the conversion of our outstanding ADSs into Class A ordinary shares, we entered into arrangements with The Depository Trust Company ("DTC") whereby DTC has accepted such shares for deposit, book entry and clearing services. The facilities of DTC are widely-used for rapid electronic transfers of securities between participants within the DTC system, which include numerous major international financial institutions and brokerage firms.
We entered into this structure in part so that transfers of our shares held in book entry form through DTC will not be subject to a charge for stamp duty or stamp duty reserve tax (“SDRT”) in the U.K. Generally, stamp duty and/or SDRT are imposed in the U.K. on certain transfers of chargeable securities (which include shares in companies incorporated in the U.K.) at a rate of 0.5% of the consideration paid for the transfer. Certain transfers of shares to depositaries or into clearance systems, such as DTC, are charged at a higher rate of 1.5%. Eligibility for acceptance of foreign securities for deposit, book entry, clearing or other services is at the discretion of DTC and may be revoked by DTC under the terms of our agreement and in accordance with the rules, procedures and bylaws of DTC. A condition for continued eligibility of our shares is that DTC and its affiliates will not be liable for stamp duty or SDRT. We have indemnified DTC for any liability arising from stamp duty or SDRT.
We have obtained a favorable ruling from Her Majesty's Revenue & Customs ("HMRC") in respect of stamp duty and SDRT in relation to both the conversion and also our arrangement with DTC. Furthermore, following decisions of the European Court of Justice and the U.K. First-tier Tax Tribunal, HMRC has announced that they will not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into depository receipt or clearance systems, such as DTC. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT in response to this decision, which could have a material effect on the cost of trading in our shares. If DTC determines at any time that our shares are not eligible for continued deposit and clearance within its facilities, our shares may become ineligible for continued listing on a U.S. securities exchange or inclusion in the S&P 500, and trading in such shares would be disrupted. In this event, DTC has agreed it will provide us advance notice and assist us, to the extent possible, with efforts to mitigate adverse consequences. While we would pursue alternative arrangements to preserve our listing and maintain trading, any such disruption could have a material adverse effect on the trading price of our Class A ordinary shares and a resulting adverse effect on our financial position, operating results and/or cash flows.
We have not requested a ruling from HMRC on the U.K. tax aspects of the redomestication, and HMRC may disagree with our conclusion.
We believe that our redomestication to the U.K. in December 2009 did not result in any material U.K. corporation tax liability to Ensco plc, based on relevant U.K. corporation tax law and the current U.K.-U.S. income tax treaty. Further, we believe that we have satisfied all SDRT payment and filing obligations in connection with the issuance and deposit of our Class A ordinary shares into the ADS facility pursuant to the deposit agreement governing the ADS facility.
However, if HMRC disagrees with this view, it may take the position that material U.K. corporation tax or SDRT liabilities or amounts on account thereof are payable by Ensco plc as a result of the redomestication, in which case we expect that we would contest such assessment. If we were unsuccessful in disputing the assessment, the implications could be materially adverse to our financial position, operating results and/or cash flows. We have not requested an HMRC ruling on the U.K. tax aspects of the redomestication, and there can be no assurance that HMRC will agree with our interpretations of U.K. corporation tax law or any related matters associated therewith.
Expected financial, logistical and operational benefits of our redomestication to the U.K. may not be realized.
We cannot be assured that all of the goals of the redomestication will be achieved, particularly as achievement of our goals is in many important respects subject to factors that we do not control. These factors include the reactions of U.K. and U.S. tax authorities, the reactions of third parties with whom we enter into contracts and conduct business and the reactions of investors and analysts.
Whether we realize other expected financial benefits of the redomestication will depend on a variety of factors, many of which are beyond our control. These factors include changes in the relative rate of economic growth in the U.K. compared to the U.S., our financial performance in jurisdictions with lower tax rates, foreign currency exchange rate fluctuations, and significant changes in trade, monetary or fiscal policies of the U.K. or the U.S., including changes in taxation or interest rates. It is difficult to predict or quantify the effect of these factors, individually and in the aggregate, in part because the occurrence of any of these events or circumstances may be interrelated. If any of these events or circumstances occur, we may not be able to realize the expected financial benefits of the redomestication, and our expenses may increase to a greater extent than if we had not completed the redomestication.
Realization of the logistical and operational benefits of the redomestication is also dependent on a variety of factors including the geographic regions in which our drilling rigs are deployed, the location of the business unit offices that oversee our global offshore contract drilling operations, the locations of our customers' corporate offices and principal areas of operation and the location of our investors. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to realize the expected logistical and operational benefits of the redomestication.
Investor enforcement of civil judgments against us may be more difficult.
Because our parent company is now a public limited company incorporated under the Laws of England and Wales, investors could experience more difficulty enforcing judgments obtained against us in U.S. courts than would have been the case for U.S. judgments obtained against us prior to the redomestication. In addition, it may be more difficult (or impossible) to bring some types of claims against us in courts in England than it would be to bring similar claims against a U.S. company in a U.S. court.
We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements.
Directors of Delaware and other U.S. corporations may issue, without further shareholder approval, shares of common stock authorized in their certificates of incorporation that were not already issued or reserved. The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors may only allot shares with the prior authorization of an ordinary resolution of the shareholders, which authorization must state the maximum amount of shares that may be allotted under it and specify the date on which it will expire, which must not be more than five years from the date on which the shareholder resolution is passed. An ordinary resolution was passed by shareholders at our last annual meeting in 2014 to authorize the allotment of additional shares for a one-year term. As this authority will expire in May 2015, an ordinary resolution will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to allot shares for an additional one-year term.
English law also generally provides shareholders pre-emption rights over new shares that are issued for cash. However, it is possible, where the board of directors is generally authorized to allot shares, to exclude pre-emption rights by a special resolution of the shareholders or by a provision in the articles of association. Such exclusion of pre-emption rights will cease to have effect when the general allotment authority to which it relates is revoked or expires. If the general allotment authority is renewed, the authority excluding pre-emption rights may also be renewed by a special resolution of the shareholders. A special resolution was passed, in conjunction with an allotment authority at our last annual shareholder meeting in 2014, to exclude pre-emption rights for a one-year term. As this authority will expire
in May 2015, a special resolution will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to exclude pre-emption rights for an additional one-year term.
English law prohibits us from conducting "on-market purchases" as our shares will not be traded on a recognized investment exchange in the U.K. English law also generally prohibits a company from repurchasing its own shares by way of "off-market purchases" without the approval by a special resolution of the shareholders of the terms of the contract by which the purchase(s) is affected. Such approval may only last for a maximum period of five years after the date on which the resolution is passed. A special resolution was passed at the Company's annual shareholder meeting in May 2013 to permit the Company to make "off-market" purchases of its own shares pursuant to certain purchase agreements for a five-year term.
We have no assurances that situations will not arise where such shareholder approval requirements for any of these actions would deprive our shareholders of substantial benefits.
Our articles of association contain anti-takeover provisions.
Certain provisions of our articles of association have anti-takeover effects, such as the ability to issue shares under the Rights Plan (as defined therein). These provisions are intended to ensure that any takeover or change of control of the Company is conducted in an orderly manner, all members of the Company are treated equally and fairly and receive an optimum price for their shares and the long-term success of the Company is safeguarded. Under English law, it may not be possible to implement these provisions in all circumstances.
The Company is not subject to the U.K.'s Code on Takeovers and Mergers (the “Code”).
The Code only applies to an offer for a public company that is registered in the U.K. (or the Channel Islands or the Isle of Man) and securities of which are not admitted to trading on a regulated market in the U.K. (or the Channel Islands or the Isle of Man) if the company is considered by the Takeover Panel to have its place of central management and control in the U.K. (or the Channel Islands or the Isle of Man). This is known as the "residency test." The test for central management and control under the Takeover Code is different from that used by the U.K. tax authorities. Under the Takeover Code, the Panel will look to where the majority of the directors of the company are themselves resident for the purposes of determining where the company has its place of central management and control. Accordingly, the Code does not currently apply to the Company and the Company therefore does not have the benefit of the protections the Code affords, including, but not limited to, the requirement that a person who acquires an interest in shares carrying 30% or more of the voting rights in the Company must make a cash offer to all other shareholders at the highest price paid in the 12 months before the offer was announced.
English law requires that we meet certain additional financial requirements before we declare dividends and return funds to shareholders.
Under English law, we are only able to declare dividends and return funds to our shareholders out of the accumulated distributable reserves on our statutory balance sheet. Distributable reserves are a company’s accumulated, realized profits, so far as not previously utilized by distribution or capitalization, less its accumulated, realized losses, so far as not previously written off in a reduction or reorganization of capital duly made. Realized profits are created through the remittance of profits of certain subsidiaries to our parent company in the form of dividends.
English law also provides that a public company can only make a distribution if, among other things (a) the amount of its net assets (that is, the total excess of assets over liabilities) is not less than the total of its called up share capital and non-distributable reserves and (b) if, and to the extent that, the distribution does not reduce the amount of its net assets to less than that total.
We may be unable to remit the profits of our subsidiaries in a timely or tax efficient manner. If at any time we do not have sufficient distributable reserves to declare and pay quarterly dividends, we may undertake a reduction in the capital of the Company, in addition to the reduction in capital taken in 2014, to reduce the amount of our share
capital and non-distributable reserves and to create a corresponding increase in our distributable reserves out of which future distributions to shareholders can be made. To comply with English law, a reduction of capital would be subject to (a) approval of shareholders at the annual shareholder meeting by special resolution; (b) confirmation by an order of the English Courts and (c) the Court order being delivered to and registered by the Registrar of Companies in England. If we were to pursue a reduction of capital of the Company as a course of action, and failed to obtain the necessary approvals from shareholders and the English Courts, we may undertake other efforts to allow the Company to declare dividends and return funds to shareholders.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Contract Drilling Fleet
The following table provides certain information about the rigs in our drilling fleet by reportable segment as of March 2, 2015:
(1)
ENSCO DS-9 is currently scheduled for delivery during the first quarter of 2015 and is committed under a long-term contract in the U.S. Gulf of Mexico. ENSCO DS-8 is currently scheduled for delivery during the second quarter of 2015 and is committed under a long-term contract in Angola.
(2)
We currently are marketing ENSCO DS-10, ENSCO 110, ENSCO 123, ENSCO 140 and ENSCO 141. For additional information on our rigs under construction, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
(3)
Rig currently is under construction. The "year built" provided is based on the current construction schedule.
The equipment on our drilling rigs includes engines, drawworks, derricks, pumps to circulate drilling fluid, well control systems, drill string and related equipment. The engines power a top-drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended water depth, well depth and geological conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling project.
Floater rigs consist of drillship rigs and semisubmersible rigs. Drillship rigs are maritime vessels that have been outfitted with drilling apparatus. Drillships are self-propelled and can be positioned over a drill site through the use of a computer-controlled propeller or "thruster" (dynamic positioning) system. Our drillships are capable of drilling in water depths of 10,000 feet or less and are suitable for deepwater drilling in remote locations because of their mobility
and large load-carrying capacity. Although drillships are most often used for deepwater drilling and exploratory well drilling, drillships can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.
Semisubmersible rigs are mobile offshore drilling units with pontoons and columns that are partially submerged at the drilling location to provide added stability during drilling operations. Semisubmersible rigs are held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains (moored semisubmersible rig) or dynamically positioned by computer-controlled propellers or "thrusters" (dynamically positioned semisubmersible rig) similar to that used by our drillships. Moored semisubmersible rigs are most commonly used for drilling in water depths of 4,499 feet or less. However, ENSCO 5006, which is a moored semisubmersible rig, is capable of deepwater drilling in water depths greater than 5,000 feet. Dynamically positioned semisubmersible rigs generally are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling.
Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water well control equipment. Our jackup rigs are of the independent leg design where each leg can be fixed into the ocean floor at varying depths and equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling safer drilling of both exploratory and development wells. The jackup rig hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.
Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. We believe all our rigs are in good condition. As of March 2, 2015, we owned all rigs in our fleet. We also manage the drilling operations for six rigs owned by third-parties.
We lease our executive offices in London, England in addition to office space in Houston, Texas, Angola, Australia, Denmark, Dubai, Indonesia, Korea, Malaysia, Mexico, Saudi Arabia, Scotland, Singapore, Switzerland and several additional international locations. We own offices and other facilities in Louisiana and Brazil.
Item 3.
Item 3. Legal Proceedings
Pride FCPA Investigation
During 2010, Pride and its subsidiaries resolved their previously disclosed investigations into potential violations of the FCPA with the DOJ and SEC. The settlement with the DOJ included a deferred prosecution agreement (the "DPA") between Pride and the DOJ and a guilty plea by Pride Forasol, S.A.S., one of Pride’s subsidiaries, to FCPA-related charges. During 2012, the DOJ moved to (i) dismiss the charges against Pride and end the DPA one year prior to its scheduled expiration; and (ii) terminate the unsupervised probation of Pride Forasol, S.A.S. The Court granted the motions.
Pride has received preliminary inquiries from governmental authorities of certain countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. At this stage of such inquiries, we are unable to determine what, if any, legal liability may result. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our business. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our Company. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.
We cannot currently predict what, if any, actions may be taken by any other applicable government or other authorities or our customers or other third parties or the effect any such actions may have on our financial position, operating results or cash flows.
Asbestos Litigation
We and certain subsidiaries have been named as defendants, along with numerous third-party companies as co-defendants, in multi-party lawsuits filed in Illinois, Mississippi, Texas, Louisiana and the UK by approximately 125 plaintiffs. The lawsuits seek an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the 1960s through the 1980s.
During 2013, we reached an agreement in principle with 58 of the plaintiffs to settle lawsuits filed in Mississippi for a nominal amount. A special master reviewed all 58 cases and made an allocation of settlement funds among the parties. The District Court Judge reviewed the allocations and accepted the special master’s recommendations and approved the settlements. The settlement documents and final documentation for the individual plaintiffs are being processed.
We intend to vigorously defend against the remaining claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.
In addition to the pending cases in Illinois, Mississippi, Texas, Louisiana and the UK, we have other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect final disposition of these asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.
Environmental Matters
We are currently subject to pending notices of assessment relating to spills of drilling fluids, oil, chemicals, grease or fuel from drilling rigs operating offshore Brazil from 2008 to 2014, pursuant to which the governmental authorities have assessed, or are anticipated to assess, fines in an aggregate amount of approximately $250,000. We have contested these notices and appealed certain adverse decisions and are awaiting decisions in these cases. Although we do not expect final disposition of these assessments to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $250,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2014.
We currently are subject to a pending administrative proceeding initiated during 2009 by a Spanish government authority seeking payment in an aggregate amount of approximately $4.0 million for an alleged environmental spill originating from ENSCO 5006 while it was operating offshore Spain. Our customer has posted guarantees with the Spanish government to cover potential penalties. Additionally, we expect to be indemnified for any payments resulting from this incident by our customer under the terms of the drilling contract. A criminal investigation of the incident was initiated during 2010 by a prosecutor in Tarragona, Spain, and the administrative proceedings have been suspended pending the outcome of this investigation. We do not know at this time what, if any, involvement we may have in this investigation.
We intend to vigorously defend ourselves in the administrative proceeding and any criminal investigation. At this time, we are unable to predict the outcome of these matters or estimate the extent to which we may be exposed to any resulting liability. Although we do not expect final disposition of this matter to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of the proceedings.
We received a notice of assessment from the Bureau of Safety and Environmental Enforcement ("BSEE") in June 2014 relating to an unintended disconnect on ENSCO 8500, pursuant to which BSEE assessed a fine in the amount of $330,000. Following an August 2014 meeting with BSEE representatives to discuss and review the penalty notice and underlying facts, BSEE reduced the civil penalty assessment from $330,000 to $70,000. The $70,000 was paid and included in contract drilling expense in our consolidated statement of operations for the year ended December 31, 2014.
Other Matters
In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
The following table provides the high and low sales price of our Class A ordinary share, par value U.S. $0.10 per share, for each period indicated during the last two fiscal years:
Our Class A ordinary shares are traded on the NYSE under the ticker symbol "ESV." Many of our shareholders hold shares electronically, all of which are owned by a nominee of The Depository Trust Company. We had 75 shareholders of record on February 1, 2015.
Dividends
The following table provides the quarterly cash dividend per share declared and paid during the last two fiscal years:
To improve capital management flexibility in light of market conditions, our Board of Directors declared a $0.15 quarterly cash dividend per Class A ordinary share for the first quarter of 2015, a $0.60 reduction from the prior level. Dividend payments are subject to approval by our Board of Directors and could change in future periods. When evaluating dividend payment timing and amounts, our Board of Directors considers several factors, including our profitability, liquidity, financial condition, reinvestment opportunities and capital requirements.
Exchange Controls
There are no U.K. government laws, decrees or regulations that restrict or affect the export or import of capital, including but not limited to, foreign exchange controls on remittance of dividends on our ordinary shares or on the conduct of our operations.
U.K. Taxation
The following paragraphs are intended to be a general guide to current U.K. tax law and what is understood to be HMRC practice applying as of the date of this report (both of which are subject to change at any time, possibly with retrospective effect) in respect of the taxation of capital gains, the taxation of dividends paid by us and stamp duty and SDRT on the transfer of our shares. In addition, the following paragraphs relate only to persons who for U.K. tax purposes are beneficial owners of the shares (“shareholders”).
These paragraphs may not relate to certain classes of holders or beneficial owners of shares, such as our employees or directors, persons who are connected with us, insurance companies, charities, collective investment schemes, pension schemes, trustees or persons who hold shares other than as an investment, or U.K. resident individuals who are not domiciled in the U.K. or who are subject to split-year treatment.
These paragraphs do not describe all of the circumstances in which shareholders may benefit from an exemption or relief from taxation. It is recommended that all shareholders obtain their own taxation advice. In particular, any shareholders who are non-U.K. resident or domiciled are advised to consider the potential impact of any relevant double tax treaties, including the Convention between the United States of America and the United Kingdom for the Avoidance of Double Taxation with respect to Taxes on Income, to the extent applicable.
U.K. Taxation of Dividends
U.K. Withholding Tax - Dividends paid by us will not be subject to any withholding or deduction for, or on account of, U.K. tax, irrespective of the residence or the individual circumstances of the shareholders.
U.K. Income Tax - An individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us. An individual shareholder who is not resident in the U.K. will not be subject to U.K. income tax on dividends received from us, unless that shareholder carries on (whether alone or in partnership) any trade, profession or vocation through a branch or agency in the U.K. and shares are used by, or held by or for, that branch or agency. In these circumstances, the non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us.
The rate of U.K. income tax payable with respect to dividends received by higher rate taxpayers in the tax year 2014/2015 is 32.5%. Individuals whose total income subject to income tax exceeds £150,000 will be subject to income tax in respect of dividends in excess of that amount at the rate of 37.5% in the tax year 2014/2015. An individual's dividend income is treated as the top slice of his or her total income subject to income tax. Individual shareholders who are resident in the U.K. will be entitled to a tax credit equal to one-ninth of the amount of the dividend received from us, which will be taken into account in computing the gross amount of the dividend subject to income tax. The tax credit will be credited against the relevant shareholder's liability (if any) to income tax on the gross amount of the dividend. An individual shareholder who is not subject to U.K. income tax on dividends received from us will not be entitled to claim payment of the tax credit in respect of such dividends. The right to a tax credit for an individual shareholder who is not resident in the U.K. will depend on his or her individual circumstances.
U.K. Corporation Tax - Unless an exemption is available (as discussed below), a corporate shareholder that is resident in the U.K. will be subject to U.K. corporation tax on dividends received from us. A corporate shareholder that is not resident in the U.K. will not be subject to U.K. corporation tax on dividends received from us, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares are used by, for or held by or for, the permanent establishment. In these circumstances, the non-U.K. resident corporate shareholder may, depending on its individual circumstances (and if no exemption is available), be subject to U.K. corporation tax on dividends received from us.
The main rate of corporation tax payable with respect to dividends received from us in the financial year 2015 is 20%. If dividends paid by us fall within any of the exemptions from U.K. corporation tax set out in Part 9A of the U.K. Corporation Tax Act 2009, the receipt of the dividend by a corporate shareholder generally will be exempt from U.K. corporation tax. Generally, the conditions for one or more of those exemptions from U.K. corporation tax on dividends paid by us should be satisfied, although the conditions that must be satisfied in any particular case will depend on the individual circumstances of the relevant corporate shareholder.
Shareholders that are regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us, unless the dividends are received as part of a tax advantage scheme. Shareholders that are not regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us on the basis that the shares should be regarded as non-redeemable ordinary shares. Alternatively, shareholders that are not small companies should also generally be exempt from U.K. corporation tax on dividends received from us if
they hold shares representing less than 10% of our issued share capital, would be entitled to less than 10% of the profits available for distribution to our equity-holders and would be entitled on a winding up to less than 10% of our assets available for distribution to such equity-holders. In certain limited circumstances, the exemption from U.K. corporation tax will not apply to such shareholders if a dividend is made as part of a scheme that has a main purpose of falling within the exemption from U.K. corporation tax.
U.K. Taxation of Capital Gains
U.K. Withholding Tax - Capital gains accruing to non-U.K. resident shareholders on the disposal of shares will not be subject to any withholding or deduction for or on account of U.K. tax, irrespective of the residence or the individual circumstances of the relevant shareholder.
U.K. Capital Gains Tax - A disposal of shares by an individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, give rise to a taxable capital gain or an allowable loss for the purposes of U.K. capital gains tax (“CGT”). An individual shareholder who temporarily ceases to be resident or ordinarily resident in the U.K. for a period of less than five years and who disposes of his or her shares during that period of temporary non-residence may be liable to CGT on a taxable capital gain accruing on the disposal on his or her return to the U.K. under certain anti-avoidance rules.
An individual shareholder who is not resident in the U.K. will not be subject to CGT on capital gains arising on the disposal of their shares, unless that shareholder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the shares were acquired, used in or for the purposes of the branch or agency or used in or for the purposes of the trade, profession or vocation carried on by the shareholder through the branch or agency. In these circumstances, the relevant non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to CGT on chargeable gains arising from a disposal of his or her shares. The rate of CGT in the tax year 2014/2015 is 18% for basic rate taxpayers and 28% for higher and additional rate taxpayers.
U.K. Corporation Tax - A disposal of shares by a corporate shareholder resident in the U.K. may give rise to a chargeable gain or an allowable capital loss for the purposes of U.K. corporation tax. A corporate shareholder not resident in the U.K. will not be liable for U.K. corporation tax on chargeable gains accruing on the disposal of its shares, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares were acquired, used in or for the purposes of the permanent establishment or used in or for the purposes of the trade carried on by the shareholder through the permanent establishment. In these circumstances, the relevant non-U.K. resident shareholder may, depending on its individual circumstances, be subject to U.K. corporation tax on chargeable gains arising from a disposal of its shares.
The financial year for U.K. corporation tax purposes runs from April 1 to March 31. The main rate of U.K. corporation tax on chargeable gains is 21% in the financial year 2014 and 20% in the financial year 2015. Corporate shareholders will be entitled to an indexation allowance in computing the amount of a chargeable gain accruing on a disposal of the shares, which will provide relief for the effects of inflation by reference to movements in the U.K. retail price index.
If the conditions of the applicable shareholding exemption are satisfied in relation to a chargeable gain accruing to a corporate shareholder on a disposal of its shares, the chargeable gain will be exempt from U.K. corporation tax. The conditions of the substantial shareholding exemption that must be satisfied will depend on the individual circumstances of the relevant corporate shareholder. One of the conditions of the substantial shareholding exemption that must be satisfied is that the corporate shareholder must have held a substantial shareholding in the Company throughout a twelve-month period beginning not more than two years before the day on which the disposal takes place. Ordinarily, a corporate shareholder will not be regarded as holding a substantial shareholding in us, unless it (whether alone, or together with other group companies) directly holds not less than 10% of our ordinary share capital.
U.K. Stamp Duty and SDRT
The discussion below relates to shareholders wherever resident but not to holders such as market makers, brokers, dealers and intermediaries, to whom special rules apply. Special rules also apply in relation to certain stock lending and repurchase transactions.
Transfer of Shares held in book entry form via DTC - A transfer of shares held in book entry (i.e., electronic) form within the facilities of the DTC will not be subject to U.K. stamp duty or SDRT.
Transfers of Shares out of, or outside of, DTC - Subject to an exemption for certain low value transactions, a transfer of shares from within the DTC system out of that system or any transfer of shares that occurs entirely outside the DTC system generally will be subject to a charge to ad valorem U.K. stamp duty (normally payable by the transferee) at 0.5% of the purchase price of the shares (rounded up to the nearest multiple of £5). SDRT generally will be payable on an unconditional agreement to transfer such shares at 0.5% of the amount or value of the consideration for the transfer. However, such liability for SDRT generally will be cancelled and any SDRT paid will be refunded if the agreement is completed by a duly-stamped transfer within six years of either the date of the agreement or, if the agreement was conditional, the date when the agreement became unconditional.
We have put in place arrangements to require that shares held outside the facilities of DTC cannot be transferred into such facilities (including where shares are re-deposited into DTC by an existing shareholder) until the transferor of the shares has first delivered the shares to a depository we specified, so that SDRT may be collected in connection with the initial delivery to the depository. Before such transfer can be registered in our books, the transferor will be required to put in the depository funds to settle the resultant liability for SDRT, which will be 1.5% of the value of the shares, and to pay the transfer agent such processing fees as may be established from time to time.
Following a decision of the European Court of Justice in 2009 and a decision of the U.K. First-Tier Tax Tribunal in 2012, HMRC has announced that it will not seek to apply the 1.5% charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into depository receipt or clearance systems, such as DTC. Thus, the 1.5% U.K. stamp duty or SDRT charge will apply only to the transfer of existing shares to clearance services or depositary receipt systems in circumstances where the transfer is not integral to the raising of new capital (for example, where shares are re-deposited into DTC by an existing shareholder). Investors should, however, be aware that this area may be subject to further developments in the future.
The above statements are intended only as a general guide to the current U.K. stamp duty and SDRT position. Transfers to certain categories of persons are not liable to U.K. stamp duty or SDRT and transfers to others may be liable at a higher rate than discussed above.
Equity Compensation Plans
For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."
Issuer Purchases of Equity Securities
The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2014.
(1)
During the quarter ended December 31, 2014, equity securities were repurchased from employees and non-employee directors by an affiliated employee benefit trust in connection with the settlement of income tax withholding obligations arising from the vesting of share awards. Such securities remain available for re-issuance in connection with employee share awards.
(2)
During 2013, our shareholders approved a new share repurchase program. Subject to certain provisions under English law, including the requirement of Ensco plc to have sufficient distributable reserves, we may purchase up to a maximum of $2.0 billion in the aggregate under the program, but in no case more than 35.0 million shares. The program terminates in May 2018.
Performance Chart
The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2009 for Ensco plc, the Standard & Poor's 500 Stock Price Index, the Dow Jones U.S. Oil Equipment & Services Index and a self-determined peer group. Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date. Since Ensco operates exclusively as an offshore drilling service company, a self-determined peer group composed exclusively of major offshore drilling service companies has been included as a comparison.*
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* Our self-determined peer group is weighted according to market capitalization and consists of the following companies: Atwood Oceanics Inc., Diamond Offshore Drilling Inc., Noble Corporation, Rowan Companies plc, SeaDrill Ltd. and Transocean Ltd.
Item 6.
Item 6. Selected Financial Data
The financial data below should be read in conjunction with "Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
Our Business
We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We currently own and operate an offshore drilling rig fleet of 70 rigs, including seven rigs currently under construction, with drilling operations in most of the strategic markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, five moored semisubmersible rigs and 42 jackup rigs. Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is one of the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.
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 and drilling contracts spanning approximately 20 countries on six continents in nearly every major offshore basin around the world. The markets in which we operate include Australia, Brazil, the Mediterranean, Mexico, the Middle East, the North Sea, Southeast Asia, the U.S. Gulf of Mexico and West Africa.
We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide a drilling rig and rig crews and receive a fixed amount per day for each day we are performing drilling or related services. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.
Our Industry
Operating results in the offshore contract drilling industry are cyclical and directly related to the demand for drilling rigs and the available supply of drilling rigs. While the cost of moving a rig and the availability of rig-moving vessels 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
Demand for drilling rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. The markets for our contract drilling services are cyclical. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region. Such spending fluctuations result from many factors, including:
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oil and natural gas supply and demand,
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regional and global economic conditions and changes therein,
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political, social and legislative environments in major oil-producing countries,
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production and inventory levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers,
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capital allocation decisions by our customers, including the relative economics of offshore development versus onshore prospects,
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technological advancements that impact the methods or cost of oil and natural gas exploration and development,
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disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof, and
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the impact that these and other events, whether caused by economic conditions, international or national climate change regulations or other factors, may have on current and expected future oil and natural gas prices.
Recent changes in the offshore drilling market have led to a highly competitive contracting environment. Since October 1, 2014, the Brent crude oil price has declined from approximately $95 per barrel to approximately $60 per barrel on February 23, 2015. Operators have announced significant declines in capital spending in their 2015 budgets, including the cancellation or deferral of existing programs. These declines in capital spending levels, coupled with additional newbuild supply, have put significant pressure on day rates and utilization.
We expect that 2015 will be a challenging year for drilling contractors as customers wait to gain additional clarity on commodity pricing and seek to reduce costs in the near-term by attempting to sub-let contracted rig time and re-negotiate existing contract terms. We believe the current market dynamics will create a challenging contracting environment into 2016.
Since most factors that affect offshore exploration and development spending are beyond our control and because rig demand can change quickly, it is difficult for us to predict future industry conditions, demand trends or future operating results. Periods of low rig demand often result in excess rig supply, which generally results in reductions in utilization and day rates; conversely, periods of high rig demand often result in a shortage of rigs, which generally results in increased utilization and day rates.
Drilling Rig Supply
During the current newbuild cycle, various industry participants ordered the construction of 360 new drillships, semisubmersible rigs and jackup rigs, approximately160 of which were delivered during the last three years.
Currently, there are approximately 80 competitive newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately 30 are expected to be delivered before the end of 2015. Roughly half of the anticipated 2015 deliveries are without contracts, leading drilling contractors to retire or stack 35 older floaters since September 2014 due to a lack of available contracting opportunities. We expect that additional floaters will be retired or stacked during 2015 as lower commodity prices have negatively impacted the number of incremental contracting opportunities.
Currently, there are approximately 120 competitive newbuild jackup rigs reported to be under construction, of which approximately half are being built by companies that have not historically operated offshore drilling rigs. Approximately 60 of these competitive newbuild jackups are expected before the end of 2015 and most of these rigs are without contracts. As a result, we expect retirements and stacking of jackups to accelerate during 2015. Currently, there are approximately 40 marketed jackups older than 30 years of age that are idle and do not have any contracted work. Additionally, approximately 80 competitive jackups that are 30 years of age or older have contracts that expire during 2015. Operating costs for idle rigs, as well as capital expenditures required to recertify rigs during regulatory surveys, may prove cost prohibitive, and drilling contractors may instead elect to retire or stack these rigs.
Rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events, and the limited availability of insurance for certain perils in some geographic regions, may impact the supply of offshore drilling rigs in a particular market and cause fluctuations in utilization and day rates.
Drilling Rig Construction and Delivery
We remain focused on our long-established strategy of high-grading our fleet. We will continue to invest in the expansion of our fleet where we believe strategic opportunities exist. During the three-year period ended December 31, 2014, we invested $3.3 billion in the construction of new drilling rigs.
During the second quarter, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs (ENSCO 140 and ENSCO 141). ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTorneau Super 116E jackup design and will incorporate Ensco's patented Canti-Leverage AdvantageSM technology. These rigs are scheduled for delivery during the second quarter and the third quarter of 2016, respectively. Both of these rigs are currently uncontracted.
During 2013, we entered into agreements with KFELS to construct a premium jackup rig (ENSCO 110) and an ultra-premium harsh environment jackup rig (ENSCO 123). These rigs are scheduled for delivery during the first quarter of 2015 and the second quarter of 2016, respectively. Both of these rigs are currently uncontracted.
We previously entered into agreements with KFELS to construct three ultra-premium harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122). ENSCO 122 was delivered during the third quarter of 2014 and commenced drilling operations under a long-term contract in the North Sea during the fourth quarter of 2014. ENSCO 121 was delivered during the fourth quarter of 2013 and commenced drilling operations under a long-term contract in the North Sea during the second quarter of 2014. ENSCO 120 was delivered during the third quarter of 2013 and commenced drilling operations under a long-term contract in the North Sea during the first quarter of 2014.
We currently have three ultra-deepwater drillships under construction (ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10). ENSCO DS-9 and ENSCO DS-8 are committed under long-term contracts and currently scheduled for delivery during the first quarter and second quarter of 2015, respectively. ENSCO DS-10 is currently uncontracted and scheduled for delivery during the third quarter of 2015.
The expected delivery dates of our rig construction projects are subject to risks and may be delayed due to shipyard or third-party equipment vendor delays or at our election.
We expect cash flow generated during 2015 will primarily be used to fund capital expenditures, most notably milestone payments for newbuild rigs. Based on our balance sheet and contractual backlog of $9.7 billion, we believe future capital projects, debt service and dividend payments will primarily be funded from cash and cash equivalents, future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital, refinance existing debt or increase liquidity as necessary.
Divestitures
Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Consistent with this strategy, we sold eleven jackup rigs, two moored semisubmersible rig and our last remaining barge rig during the three-year period ended December 31, 2014. We are currently marketing for sale an additional seven rigs, which were classified as held for sale in our financial statements as of December 31, 2014.
Segment Highlights
Floaters
Operating results for our Floaters segment declined during 2014 due primarily to a $4.0 billion loss on impairment. Floater revenues grew slightly primarily due to the addition of ENSCO DS-7 to our fleet, but were more than offset by a $75.2 million, or 7%, increase in contract drilling expense. ENSCO DS-7 commenced drilling operations in Angola during the fourth quarter of 2013.
In January 2014, ENSCO DS-9 was contracted and is expected to commence a long-term contract in the U.S. Gulf of Mexico during the fourth quarter of 2015. In June 2014, ENSCO DS-8 was contracted and is expected to commence a long-term contract in Angola during the fourth quarter of 2015.
ENSCO 8503 executed a long-term contract in the U.S. Gulf of Mexico with a 2.5 year term commencing during the second quarter of 2015.
Jackups
Operating results for our Jackups segment declined during 2014 due to a $236.4 million loss on impairment. Excluding this loss, operating results improved primarily due to an increase in average day rates. In particular, premium jackup rigs earned significantly higher day rates due to increasing customer demand for more technologically capable rigs.
Ultra-premium harsh environment jackup rigs ENSCO 120 and ENSCO 122 commenced drilling operations under long-term contracts in the North Sea during the first and fourth quarters, respectively. Ultra-premium harsh environment jackup rig ENSCO 121 commenced drilling operations under a long-term contract in the Netherlands during the second quarter.
In the Middle East, ENSCO 76 was recontracted through December 2018 and ENSCO 84, ENSCO 96 and ENSCO 97 were recontracted through 2019.
ENSCO 109 executed a long-term contract in Angola, and ENSCO 52 executed a long-term contract in Malaysia, both with an expected term of three years.
During the second quarter, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs (ENSCO 140 and ENSCO 141). ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTorneau Super 116E jackup design and will incorporate Ensco's patented Canti-Leverage AdvantageSM technology. These rigs are scheduled for delivery during the second quarter and the third quarter of 2016, respectively.
BUSINESS ENVIRONMENT
Floaters
During the first half of 2014, the floater contracting environment was highly competitive due to a reduction in capital spending by operators, as well as an increase in global supply due to the delivery of newbuild floaters. More recently, these challenges were exacerbated by a steep decline in commodity prices during the fourth quarter that accelerated toward year-end, which led customers to significantly reduce capital budgets for 2015. Cancellations and delays of drilling programs have increased, many rigs currently contracted are being sublet thereby creating incremental supply, and certain customers are requesting contract concessions. There are limited contracting opportunities in the current market, and day rates and utilization are expected to decline during 2015.
Currently, there are approximately 80 competitive newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately 30 are expected to be delivered before the end of 2015. Roughly half
of the anticipated 2015 deliveries are without contracts, leading drilling contractors to retire or stack 35 older floaters since September 2014 due to a lack of available contracting opportunities. We expect that additional floaters will be retired or stacked during 2015 as lower commodity prices have negatively impacted the number of incremental contracting opportunities.
Jackups
Demand for jackups has also dropped due to the steep decline in commodity prices. Cancellations and delays of drilling programs have increased, some rigs currently contracted are being sublet thereby creating incremental supply, and certain customers are requesting contract concessions. As a result, there are limited contracting opportunities in the current market, and day rates and utilization are expected to decline during 2015.
Currently, there are approximately 120 competitive newbuild jackup rigs reported to be under construction, of which approximately half are being built by companies that have not historically operated offshore drilling rigs. Approximately 60 of these competitive newbuild jackups are expected by year-end 2015, and most of these rigs are without contracts. As a result, we expect retirements and stacking of jackups to accelerate during 2015. Currently, there are approximately 40 marketed jackups older than 30 years of age that are idle and do not have any contracted work. Additionally, approximately 80 competitive jackups that are 30 years of age or older have contracts that expire during 2015. Operating costs for idle rigs as well as capital expenditures required to recertify rigs during regulatory surveys may prove cost prohibitive and drilling contractors may instead elect to retire or stack these rigs.
RESULTS OF OPERATIONS
The following table summarizes our consolidated results of operations for each of the years in the three-year period ended December 31, 2014 (in millions):
Revenues and contract drilling expenses increased by $241.1 million, or 6%, and $129.8 million, or 7%, respectively, for the year ended December 31, 2014 as compared to the prior year. The increase in revenues was primarily due to the addition of newbuild rigs to both our Floaters and Jackups segments and an increase in average day rates across our existing fleet, partially offset by a decline in utilization. The increase in contract drilling expense was due to the aforementioned additions to our fleet and higher personnel and repair and maintenance costs. During 2013, contract drilling expense included a $14.2 million provision for doubtful accounts for receivables related to drilling services provided to OGX Petróleo e Gás Participações S.A. ("OGX"). Our receivables with OGX were fully reserved on our consolidated balance sheet as of December 31, 2013.
During 2014, we recorded a non-cash loss on impairment totaling $4.2 billion, of which $3.0 billion related to impairment of our Floater goodwill and $1.2 billion related to impairment of three floaters and ten jackups.
During 2013, revenues and contract drilling expense increased by $684.6 million, or 19%, and $304.3 million, or 19%, respectively, as compared to the prior year. The increase in revenues was primarily due to the addition of newbuild rigs to our Floaters segment and an increase in average day rates across our existing fleet, partially offset by a decline in utilization. The increase in contract drilling expense was due the aforementioned additions to our fleet and higher personnel costs, as well as the aforementioned provision for doubtful accounts related to OGX receivables.
A significant number of our drilling contracts are of a long-term nature. Accordingly, an increase or decline in demand for contract drilling services generally affects our operating results and cash flows gradually over future periods as long-term contracts expire, and new contracts and/or options are priced at current market rates.
Rig Counts, Utilization and Average Day Rates
The following table sets forth our offshore drilling rigs by reportable segment and rigs under construction as of December 31, 2014, 2013 and 2012:
(1)
During 2014, we sold ENSCO 5000 and classified ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500 and ENSCO DS-2 as "held for sale."
(2)
During 2014, we sold ENSCO 69, Pride Wisconsin, ENSCO 85, ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98 and classified ENSCO 58 and ENSCO 90 as "held for sale."
(3)
During the first quarter of 2013, we sold Pride Pennsylvania which was classified as "held for sale" as of December 31, 2012.
(4)
During 2014, we accepted delivery of one ultra-premium harsh environment jackup rig (ENSCO 122). ENSCO 122 commenced a long-term drilling during the fourth quarter.
During 2013, we accepted delivery of one ultra-deepwater drillship (ENSCO DS-7) and two ultra-premium harsh environment jackup rigs (ENSCO 120 and ENSCO 121). ENSCO DS-7 commenced a long-term contract during the fourth quarter of 2013. ENSCO 120 and ENSCO 121 commenced long-term contracts during the first quarter and second quarter of 2014, respectively.
(5)
During 2014, we entered into an agreement with Lamprell plc to construct two high-specification jackup rigs, ENSCO 140 and ENSCO 141, which are scheduled for delivery during the second quarter and third quarter of 2016, respectively. Both rigs remain uncontracted.
During 2013, we entered into an agreement with SHI to construct our eighth ultra-deepwater drillship (ENSCO DS-10), which is uncontracted and scheduled for delivery during the third quarter of 2015. During 2013, we also entered into agreements with KFELS to construct one premium jackup rig (ENSCO 110) and one ultra-premium harsh environment jackup rig (ENSCO 123). These rigs are scheduled for delivery during the first quarter of 2015 and second quarter of 2016, respectively. Both of these rigs are currently uncontracted.
The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2014:
(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 compensated downtime and mobilizations. When revenue is earned but is deferred and amortized over a future period, for example when a rig earns revenue 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)
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 of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below.
Operating Income
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
Segment information for each of the years in the three-year period ended December 31, 2014 is presented below (in millions). 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 were included in "Reconciling Items." Prior year information has been reclassified to conform to the current year presentation.
Year Ended December 31, 2014
Year Ended December 31, 2013
Year Ended December 31, 2012
Floaters
During 2014, Floater revenues increased by $38.0 million, or 1%, as compared to the prior year. The increase in revenues was primarily due to commencement of the ENSCO DS-7 drilling contract during the fourth quarter of 2013 and an increase in average day rates across our Floater fleet. These increases were partially offset by a decline in utilization attributable to certain rigs. ENSCO 5004 and ENSCO 5006 were in the shipyard for capital enhancement projects during 2014, and ENSCO 8503 incurred several months of uncontracted downtime primarily during the first quarter.
Contract drilling expense increased by $75.2 million, or 7%, as compared to the prior year, primarily due to the aforementioned addition of ENSCO DS-7 to our Floater fleet. To a lesser extent, higher personnel and repair and
maintenance costs also contributed to the increase in contract drilling expense. These increases were partially offset by lower contract drilling expense for ENSCO 5006 and lower windstorm insurance costs during 2014 following our decision to not renew our windstorm policy for floaters in the U.S. Gulf of Mexico. Contract drilling expense during 2013 also included the aforementioned provision for doubtful accounts related to OGX receivables.
We recognized a loss on impairment of $4.0 billion during the year ended December 31, 2014 related to goodwill and three older, less capable floaters. Detailed explanations of our loss on impairment are provided below. No impairments were recorded during the prior year period.
Depreciation expense increased by $15.9 million, or 5%, primarily due to the addition of ENSCO DS-7 to our Floater fleet, partially offset by lower depreciation as a result of the impairments recorded during the second quarter of 2014.
During 2013, Floater revenues increased by $510.5 million, or 24%, as compared to the prior year. The increase in revenues was primarily due to commencement of ENSCO 8506 and ENSCO DS-6 drilling operations during the first quarter of 2013 and commencement of ENSCO 8505 drilling operations during the second quarter of 2012. To a lesser extent, the increase in revenues was attributable to an increase in average day rates for various rigs in our Floater fleet. These increases were partially offset by a decline in utilization, primarily due to ENSCO 5005, which was in the shipyard for a capital enhancement project during 2013 and downtime prompted by a vendor notice regarding inspection and replacement of connector bolts on various rigs. ENSCO 5004 drilling services provided to OGX that were not recognized as revenue also adversely impacted utilization during 2013.
Contract drilling expense increased by $231.5 million, or 26%, as compared to the prior year, primarily due to the additions to our Floater fleet and increased personnel costs. These increases were partially offset by lower contract drilling expense for ENSCO 5005, which was in the shipyard for a capital enhancement project during 2013. The prior year also included the favorable settlement of third-party claims which reduced contract drilling expense by $63.3 million. Depreciation expense increased by $58.9 million, or 21%, primarily due to the aforementioned additions to our Floater fleet.
Jackups
During 2014, Jackup revenues increased by $185.9 million, or 12%, as compared to the prior year. The increase in revenues was primarily due to an increase in average day rates across our Jackup fleet and commencement of the ENSCO 120, ENSCO 121 and ENSCO 122 drilling contracts. These increases were partially offset by a decline in utilization for certain rigs in the Jackup fleet.
Contract drilling expense increased by $44.8 million, or 6%, as compared to the prior year, primarily due to the aforementioned additions to our Jackup fleet and an increase in personnel and repair and maintenance costs.
We recognized a loss on impairment of $236.4 million during the year ended December 31, 2014 related to ten jackups. Detailed explanations of our loss on impairment are provided below. No impairments were recorded during the prior year period.
Depreciation expense increased by $23.7 million, or 16%, primarily due to the additions to our Jackup fleet.
During 2013, Jackup revenues increased by $181.8 million, or 13%, as compared to the prior year. The increase in revenues was primarily due to an increase in average day rates, mostly attributable to the U.S. Gulf of Mexico, North Sea and Southeast Asia. Contract drilling expense increased by $75.4 million, or 11%, as compared to the prior year, primarily due to increased personnel costs.
Impairment of Long-Lived Assets
During 2014, we recorded a pre-tax, non cash loss on impairment of long-lived assets of $2,463.1 million, of which $1,220.8 million was included in (loss) income from continuing operations and $1,242.3 million was included in (loss) income from discontinued operations, net in our consolidated statement of operations. These losses were recorded during the second and fourth quarters.
During the second quarter, demand for floaters deteriorated as a result of continued reductions in capital spending by operators in addition to delays in operators’ drilling programs. The reduction in demand, combined with the increasing supply from newbuild floater deliveries, led to a very competitive market. In general, contracting activity declined significantly, and day rates and utilization came under pressure, especially for older, less capable floaters.
In response to the adverse change in the floaters business climate, management evaluated our older, less capable floaters and committed to a plan to sell five rigs. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000 and ENSCO 7500 were removed from our portfolio of rigs marketed for contract drilling services and actively marketed for sale. These rigs were written down to fair value, less costs to sell. We completed the sale of ENSCO 5000 in December 2014. The remaining four floaters were classified as "held for sale" on our December 31, 2014 consolidated balance sheet.
We measured the fair value of the "held for sale" rigs by applying a market approach, which was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We recorded a pre-tax, non-cash loss on impairment totaling $546.4 million during the second quarter associated with our "held for sale" rigs. The impairment charge was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014.
During the fourth quarter, Brent crude oil prices declined from approximately $95 per barrel to near $55 per barrel on December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs. As a result, day rates and utilization came under further pressure, especially for older, less capable rigs. The significant supply and demand imbalance will continue to be adversely impacted by future newbuild deliveries, program delays and lower capital spending by operators.
In response to the adverse change in business climate, management evaluated our aged rigs and committed to a plan to sell one additional floater and two jackups. ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. These rigs were written down to fair value, less costs to sell, during the fourth quarter and classified as "held for sale" on our December 31, 2014 consolidated balance sheet.
As of December 31, 2014, we measured the fair value of our seven "held for sale" rigs by applying a market approach, which was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. In addition to the asset impairment recorded during the second quarter, we recorded an additional pre-tax, non-cash loss on impairment totaling $407.9 million during the fourth quarter. The impairment charge was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014. See "Note 10 - Discontinued Operations" for additional information on our "held for sale" rigs.
On a quarterly basis, we evaluate the carrying value of our property and equipment to identify events or changes in circumstances ("triggering events") that indicate the carrying value may not be recoverable. During the second quarter, as a result of the adverse change in the floater business climate, management's decision to sell five floaters and the impairment charge incurred on the "held for sale" floaters, management concluded that a triggering event had occurred and performed an asset impairment analysis on our remaining older, less capable floaters.
Based on the analysis performed as of May 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to four other floaters totaling $991.5 million, of which $288.0 million related to ENSCO DS-2 which was removed from our portfolio of rigs marketed for contract drilling services during the fourth quarter. The ENSCO DS-2 impairment charge was reclassified to (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014. The remaining $703.5 million impairment charge was
included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying an income approach, using projected discounted cash flows. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.
During the fourth quarter, as a result of the decline in commodity prices and adverse changes in the offshore drilling market, management's decision to sell an additional floater and two jackups and the impairment charge incurred on the "held for sale" rigs, management concluded that a triggering event had occurred and performed an asset impairment analysis for all floaters and jackups.
Based on the analysis performed as of December 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to two older, less capable floaters and ten older, less capable jackups totaling $517.3 million. The impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying either an income approach, using projected discounted cash flows, or a market approach. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.
Impairment of Goodwill
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. During the second quarter, demand for floaters deteriorated as a result of a continued reduction in capital spending by operators in addition to announced delays in operators’ drilling programs. The reduction in demand, combined with increasing supply from newbuild floater deliveries, led to a very competitive market. In general, contracting activity for floaters declined significantly and day rates and utilization came under pressure, especially for older, less capable floaters.
Management considered the adverse change in the floater business climate, the commitment to a plan to sell five floaters in May 2014, and the impairment charge on the "held for sale" floaters during the second quarter and concluded that a triggering event had occurred. We performed an interim goodwill impairment test to evaluate the recoverability of the Floaters reporting unit goodwill balance of $3.1 billion as of May 31, 2014. Based on the valuation performed, the Floaters reporting unit estimated fair value exceeded the carrying value by approximately 7%; therefore, we concluded that the goodwill balance was not impaired.
As part of our annual goodwill impairment test as of December 31, 2014, we considered the significant decline in commodity prices during the fourth quarter of 2014. Specifically, Brent crude oil prices declined from approximately $95 per barrel at September 30, 2014 to near $55 per barrel at December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs. We expect that this reduction in demand will cause further deterioration in day rates and utilization and that current market dynamics will create a challenging contracting environment into 2016.
Our stock price also declined significantly during the latter half of 2014, reaching a five-year low of $25.88 on December 16th. Our stock price traded between $25.88 and $41.99 during the fourth quarter of 2014 and averaged $35.23 during this period.
Management considered the adverse changes in the current floater business climate, the sustained decline in stock price and the impairment charge on older, less capable floaters during the fourth quarter and concluded it was more-likely-than-not that the fair value of the Floater reporting unit was less than its carrying amount. As a result, we estimated the fair value of the reporting unit using a blended income and market approach. Based on the valuation performed as of December 31, 2014, the reporting unit estimated fair value was less than the carrying value; therefore, we concluded that the Floater goodwill balance was impaired. We compared the estimated fair value of the reporting
unit to the fair value of all assets and liabilities of the reporting unit to calculate the implied fair value of goodwill. As a result, we recorded a non-cash loss on impairment totaling $3.0 billion which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014.
The income approach was based on a discounted cash flow model, which utilized present values of cash flows to estimate fair value. The future cash flows were projected based on our estimates of future day rates, utilization, operating costs, capital requirements, growth rates and terminal values. Forecasted day rates and utilization take into account current market conditions and our anticipated business outlook, both of which have been impacted by the adverse changes in the floater business environment during 2014. The day rates reflected contracted rates during the respective contracted periods and management's estimate of market day rates in uncontracted periods. The forecasted market day rates were held constant in the near-term but were forecasted to grow in the longer-term and terminal period.
Operating costs were forecasted using a combination of our historical average operating costs and expected future costs, adjusted for an estimated inflation factor. Capital requirements in the discounted cash flow model were based on management's estimates of future capital costs, taking into consideration our historical trends. The estimated capital requirements included cash outflows for new rig construction, rig enhancements and minor upgrades and improvements.
A terminal period was used to reflect our estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 3.0%, which includes an estimated inflation factor. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital ("WACC") of 11.0%. These assumptions were derived from unobservable inputs and reflect management's judgments and assumptions.
The market approach was based upon the application of price-to-earnings multiples to management's estimates of future earnings adjusted for a control premium. The price-to-earnings multiples used in the market valuation ranged from 6.0x to 6.8x and were based on market participant multiples. Management's earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.
The estimated fair value of the Floaters reporting unit determined under the income approach was consistent with the estimated fair value determined under the market approach. For purposes of the goodwill impairment test, we calculated the Floaters reporting unit estimated fair value as the average of the values calculated under the income approach and the market approach.
We evaluated the estimated fair value of our reporting units compared to our market capitalization as of December 31, 2014. To perform this assessment, we used a market approach to estimate the fair value of the Jackups reporting unit. The aggregate fair values of our reporting units exceeded our market capitalization, and we believe the resulting implied control premium was reasonable based on recent market transactions within our industry or other relevant benchmark data.
We performed a qualitative assessment for our Jackup reporting unit as of December 31, 2014. Goodwill impairment tests performed during prior years indicated that the fair value of the Jackup reporting unit significantly exceeded its carrying amount. Despite the adverse changes in the offshore drilling climate, we concluded that the fair value remains substantially in excess of the carrying value of the reporting unit, as evidenced by the estimated fair value of the Jackup reporting unit calculated for the purpose of reconciling the fair value of our reporting units to our market capitalization. Therefore, we concluded that it remains more-likely-than-not that the Jackup reporting unit was not impaired.
The estimates used to determine the fair value of the Floaters reporting unit reflect management's best estimates, and we believe they are reasonable. Future declines in the Floaters reporting unit's operating performance or our anticipated business outlook may reduce the estimated fair value of our Floaters reporting unit and result in additional impairments. Factors that could have a negative impact on the fair value of the Floaters reporting unit include, but are not limited to:
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decreases in estimated market day rates and utilization due to greater-than-expected market pressures, downtime and other risks associated with offshore rig operations;
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sustained declines in our stock price;
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decreases in revenue due to our inability to attract and retain skilled personnel;
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changes in worldwide rig supply and demand, competition or technology, including changes as a result of newbuild rig deliveries;
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changes in future levels of drilling activity and expenditures, whether as a result of global capital markets and liquidity, prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs;
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possible cancellation or suspension of drilling contracts as a result of mechanical difficulties, performance or other reasons;
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delays in contract commencement dates;
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the outcome of litigation, legal proceedings, investigations or other claims or contract disputes resulting in significant cash outflows;
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governmental, regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations (such as the Gulf of Mexico during hurricane season);
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increases in the market-participant risk-adjusted WACC;
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declines in anticipated growth rates.
Adverse changes in one or more of these factors could result in additional goodwill impairments in future periods. As of December 31, 2014, there was $192.6 million of goodwill associated with our Jackup reporting unit and $83.5 million of goodwill associated with our Floater reporting unit on our consolidated balance sheet.
Other Income (Expense), Net
The following table summarizes other income (expense), net, for each of the years in the three-year period ended December 31, 2014 (in millions):
During 2014 and 2013, interest income declined as compared to the respective prior year periods primarily due to declining outstanding principal amounts for reimbursement of mobilization and upgrade costs on certain long-term drilling contracts due from customers.
Interest expense during 2014 increased $13.1 million. or 6%, as compared to the prior year. The increase was due to the $1.25 billion debt offering completed on September 29, 2014. During 2013, interest expense was comparable with the respective prior year period as the average outstanding principal balances associated with our long-term debt instruments remained consistent.
Interest expense capitalized during 2014 increased $10.5 million, or 16%, as compared to the prior year due to an increase in the average outstanding amount of capital invested in newbuild construction. During 2013, interest expense capitalized declined $38.1 million, or 36%, as compared to prior year due to a decline in the average outstanding amount of capital invested in newbuild construction. ENSCO 8506 and ENSCO DS-6 were placed into service during the first quarter of 2013, and ENSCO 8505 was placed into service during the second quarter of 2012.
During 2013, we received a $30.6 million reimbursement from the Mexican tax authority with respect to the tax authority's draw on letters of credit issued by an Ensco subsidiary for the benefit of Seahawk Drilling Inc. ("Seahawk") under a credit support agreement executed in connection with the 2009 spin-off of Seahawk. The reimbursement was included in other, net in our consolidated statement of operations for the year ended December 31, 2013.
Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Net foreign currency exchange gains and losses, inclusive of offsetting fair value derivatives, were $2.6 million of losses, $6.4 million of gains and $3.5 million of losses, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
Net unrealized gains of $2.3 million, $6.2 million and $2.8 million from marketable securities held in our supplemental executive retirement plans ("SERP") were included in other, net, in our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively. The fair value measurement of our marketable securities held in the SERP is discussed in Note 2 to our consolidated financial statements.
Provision for Income Taxes
Ensco 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 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 the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another.
Income tax expense was $140.5 million, $203.1 million and $228.6 million, and our consolidated effective income tax rate was (5.5)%, 12.4% and 17.5% during the years ended December 31, 2014, 2013 and 2012, respectively. Our consolidated effective income tax rate for 2014 includes the impact of various discrete tax items, including the recognition of a net $18.4 million tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years and a $16.4 million tax benefit associated with rig impairments. In addition, we recognized a net $41.4 million tax benefit in connection with the utilization of foreign tax credits that were previously subject to a valuation allowance.
The majority of discrete tax expense recognized during 2013 was attributable to the recognition of a $7.4 million liability for taxes associated with a $30.6 million reimbursement from the resolution of a dispute with the
Mexican tax authority and a $7.0 million increase in the valuation allowance on U.S. foreign tax credits resulting from a restructuring transaction.
The majority of discrete tax expense recognized during 2012 was attributable to $51.2 million of income tax expense associated with the restructuring of certain subsidiaries of Pride, and tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years.
Excluding the impact of the aforementioned tax items and goodwill and asset impairments, our consolidated effective income tax rates for the years ended December 31, 2014, 2013 and 2012 were 10.7%, 12.2% and 12.4%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three years result primarily from 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 the tax rates in such jurisdictions.
Discontinued Operations
Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Consistent with this strategy, we sold the following rigs during the three-year period ended December 31, 2014. These rigs are classified as discontinued operations (in millions):
(1) The rigs' operating results were reclassified to discontinued operations in our consolidated statements of operations for each of the years in the three-year period ended December 31, 2014 and previously were included within the operating segment noted in the above table.
(2) Includes the rig's net book value as well as inventory and other assets on the date of the sale.
(3) In September 2014, we sold jackup rigs ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98, all of which are contracted to Pemex. As described below, the loss on sale and operating results of ENSCO 93 were included in (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014.
During 2014, management committed to a plan to sell six floaters and two jackups. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500, ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. These rigs were written down to fair value, less costs to sell. We recorded a non-cash loss on impairment totaling $1.2 billion, net of tax benefits of $83.5 million, during the year ended December 31, 2014. The impairment charge was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014.
We completed the sale of ENSCO 5000 for net proceeds of $1.3 million in December 2014. The remaining five floaters and two jackups are being actively marketed for sale and were classified as "held for sale" on our December 31, 2014 consolidated balance sheet.
The operating results from these rigs were included in (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014.
During 2014, we sold ENSCO 93, a jackup contracted to Pemex. In connection with this sale, we executed a charter agreement with the purchaser to continue operating the rig for the remainder of the Pemex contract, which had an anticipated completion date in late 2015. Based on market developments during the fourth quarter, we now expect that the ENSCO 93 charter agreement will terminate prior to September 30, 2015. As a result, the loss on sale of $1.2 million and ENSCO 93 operating results were reclassified to (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014. Net proceeds from the sale of $51.7 million were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. See "Note 12 - Sale-leaseback" for additional information.
During 2014, we sold ENSCO 85 for net proceeds of $64.4 million and ENSCO 69 and Pride Wisconsin for net proceeds of $32.2 million. The operating results of these rigs were included in (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014. The net proceeds from the sale for ENSCO 69 and Pride Wisconsin were received in December 2013 and included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2013.
During 2012, we classified jackup rig Pride Pennsylvania as held for sale, and the rig was written down to fair value less estimated cost to sell. We recognized a $2.5 million loss for assets classified as held for sale during the year ended December 31, 2012.
The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2014 (in millions):
Debt and interest expense are not allocated to our discontinued operations.
During 2008, ENSCO 74 was lost as a result of Hurricane Ike in the U.S. Gulf of Mexico. The owner of a pipeline filed claims alleging that ENSCO 74 caused the pipeline to rupture during Hurricane Ike. We incurred $3.6 million in professional fees in connection with this matter, which we applied against our $10.0 million per occurrence deductible under our liability insurance policy.
In February 2014, we reached an agreement with the owner of the pipeline to settle the claims for $9.6 million. Accordingly, we recorded a $6.4 million charge for our remaining obligation under our liability insurance policy in loss from discontinued operations in our consolidated statement of operations for the year ended December 31, 2013.
The remaining $3.2 million was settled by our underwriters. See "Note 11 - Commitments and Contingencies" for additional information on the ENSCO 74 loss.
LIQUIDITY AND CAPITAL RESOURCES
Although our business is cyclical, we have historically relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt, which has provided us the ability to achieve future growth potential through acquisitions and newbuild rig construction. A substantial portion of our cash flow has been invested in the expansion and enhancement of our fleet of drilling rigs through newbuild construction and upgrade projects and the return of capital to shareholders through dividend payments.
Given recent market conditions, our Board of Directors elected to reduce the quarterly dividend payment in order to increase the Company's capital flexibility. We expect cash flow generated during 2015 will primarily be used to fund capital expenditures, most notably milestone payments for newbuild rigs. Based on our balance sheet and contractual backlog of $9.7 billion, we believe future capital projects, debt service and dividend payments will primarily be funded from cash and cash equivalents, future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital, refinance existing debt or increase liquidity as necessary.
During the three-year period ended December 31, 2014, our primary sources of cash were an aggregate $5.8 billion generated from operating activities of continuing operations, $1.2 billion in proceeds from the issuance of senior notes and $178.4 million in proceeds from rig sales. Our primary uses of cash during the same period included $5.0 billion for the construction, enhancement and other improvement of our drilling rigs, including $3.3 billion invested in newbuild construction, and $1.6 billion for dividend payments.
Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2014 are set forth below.
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 ended December 31, 2014 were as follows (in millions):
During 2014, cash flows from continuing operations increased by $246.7 million, or 14%, as compared to the prior year. The increase primarily resulted from a $503.1 million increase in cash receipts from contract drilling services, partially offset by a $259.2 million increase in cash payments related to contract drilling expenses.
Cash receipts from contract drilling services associated with customer reimbursed capital upgrades and mobilizations which are amortized to revenue over the term of the related contract totaled $267.0 million for the year ended December 31, 2014 as compared to $70.0 million for the year ended December 31, 2013.
During 2013, cash flows from continuing operations declined by $143.4 million, or 7%, as compared to the prior year. The decrease primarily resulted from a $348.7 million increase in cash payments related to contract drilling expenses, a $117.5 million increase in cash payments for income taxes, a $40.2 million increase in cash payments for interest and a $28.8 million increase in cash payments related to general and administrative expenses, partially offset by a $378.8 million increase in cash receipts from contract drilling services.
Cash payments during 2013 related to contract drilling and general and administrative expenses were generally higher than the prior year due in part to the full year impact of the Pride acquisition on certain annual payments made during 2013. Annual payments made during the year ended December 31, 2012 were based on seven months of acquired company operating activity.
Cash receipts from contract drilling services associated with customer reimbursed capital upgrades and mobilizations which are amortized to revenue over the term of the related contract totaled $70.0 million for the year ended December 31, 2013 as compared to $260.0 million for the year ended December 31, 2012.
We remain focused on our long-established strategy of high-grading and expanding the size of our fleet. During the three-year period ended December 31, 2014, we invested $3.3 billion in the construction of new drilling rigs and an additional $992.9 million enhancing the capability and extending the useful lives of our existing fleet.
Given recent market conditions, our Board of Directors elected to reduce the quarterly dividend payment in order to increase the Company's capital flexibility. We expect cash flow generated during 2015 will primarily be used to fund capital expenditures, most notably milestone payments for newbuild rigs. Based on our balance sheet and contractual backlog of $9.7 billion, we believe future capital projects, debt service and dividend payments will primarily be funded from cash and cash equivalents, future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital, refinance existing debt or increase liquidity as necessary.
Based on our current projections, we expect capital expenditures during 2015 to include approximately $1.6 billion for newbuild construction, approximately $250.0 million for rig enhancement projects and approximately $250.0 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.
Financing and Capital Resources
Our total debt, total capital and total debt to total capital ratios as of December 31, 2014, 2013 and 2012 are summarized below (in millions, except percentages):
* Total capital includes total debt plus Ensco shareholders' equity.
During 2014, our total capital declined $3.4 billion and our total debt to total capital ratio increased 14.8% to 41.9% primarily due to a pre-tax, non-cash loss on impairment of $5.5 billion.
Senior Notes
On September 29, 2014, we issued $625.0 million aggregate principal amount of unsecured 4.50% notes due 2024 at a discount of $850,000 and $625.0 million aggregate principal amount of unsecured 5.75% notes due 2044 (collectively the “2014 Notes”) at a discount of $2.8 million in a public offering. Interest on these notes is payable semiannually in April and October of each year commencing April 1, 2015. The 2014 Notes were issued pursuant to an Indenture between us and Deutsche Bank Trust Company Americas, as trustee (the “Trustee”), dated March 17, 2011 (the "Indenture") and a Second Supplemental Indenture between us and the Trustee, dated September 29, 2014. The net proceeds from the sale of the 2014 Notes are being used for general corporate purposes.
During 2011, we issued $1.0 billion aggregate principal amount of unsecured 3.25% notes due 2016 at a discount of $7.6 million and $1.5 billion aggregate principal amount of unsecured 4.70% notes due 2021 (collectively the “2011 Notes”) at a discount of $29.6 million in a public offering. Interest on these notes is payable semiannually in March and September of each year. The 2011 Notes were issued pursuant to the Indenture, and a supplemental indenture between us and the Trustee, dated March 17, 2011. The net proceeds from the sale of the 2011 Notes were used to fund a portion of the cash consideration payable in connection with the Pride acquisition.
Upon consummation of the Pride acquisition during 2011, we assumed the acquired company's outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million aggregate principal amount of 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of 7.875% senior notes due 2040 (the "Acquired Notes"). Under a supplemental indenture, Ensco plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes. See "Note 15 - Guarantee of Registered Securities" for additional information on the guarantee of the Acquired Notes.
We may redeem each series of the 2014 Notes in whole, at any time or in part from time to time, prior to maturity. If we elect to redeem the 2014 Notes due 2024 before the date that is three months prior to the maturity date or the 2014 Notes due 2044 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 the 2014 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 2011 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 2014 Notes, the 2011 Notes and the Acquired Notes contain customary events of default, including failure to pay principal or interest on such Notes when due, among others. The indentures governing the 2014 Notes, the 2011 Notes and the Acquired 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 Delaware issued $150.0 million of unsecured 7.20% Debentures due November 15, 2027 (the "Debentures") in a public offering. Interest on the Debentures is payable semiannually in May and November. 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. The Debentures are not subject to any sinking fund requirements. During 2009, in connection with the redomestication, Ensco plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures.
The Debentures and the indenture and the supplemental indentures 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 and the supplemental indentures 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.
MARAD Bonds Due 2016 and 2020
During 2001, a subsidiary of Ensco Delaware issued $190.0 million of 15-year bonds which are guaranteed by MARAD to provide long-term financing for ENSCO 7500. In December 2014, we fully redeemed the remaining outstanding principal of these bonds and incurred a "make-whole" payment of $600,000, and MARAD released its interests in ENSCO 7500.
During 2003, a subsidiary of Ensco Delaware issued $76.5 million of 17-year bonds which are guaranteed by MARAD to provide long-term financing for ENSCO 105. The bonds will be repaid in 34 equal semiannual principal installments of $2.3 million ending in October 2020. Interest on the bonds is payable semiannually, in April and October, at a fixed rate of 4.65%.
Ensco Delaware issued separate guaranties to MARAD, guaranteeing the performance of obligations under the bonds. During 2010, the documents governing MARAD's guarantee commitments were amended to address certain changes arising from the redomestication and to include Ensco plc as an additional guarantor of the debt obligations of Ensco Delaware and its subsidiaries.
Upon consummation of the Pride acquisition, we assumed $151.5 million of MARAD bonds issued to provide long-term financing for ENSCO 6003 and ENSCO 6004. The bonds are guaranteed by MARAD and will be repaid in semiannual principal installments ending in 2016. Interest on the bonds is payable semiannually at a weighted average fixed rate of 4.33%.
We may redeem each series of our outstanding MARAD bonds, in whole or in part, on any interest payment date, at a price equal to 100% of the their principal amount, plus accrued and unpaid interest and a “make-whole” premium.
Commercial Paper
We participate in a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes. During 2014, we increased the size of our program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $2.25 billion at any time outstanding. Amounts issued under the commercial paper program are supported by the available and unused committed capacity under our credit facility. As a result, amounts issued under the commercial paper program are limited by the amount of our available and unused committed capacity under our credit facility. The proceeds of such financings may be used for capital expenditures and other general corporate purposes. The commercial paper bears interest at rates that vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The weighted-average interest rate on our commercial paper borrowings was 0.26% and 0.35% during 2014 and 2013, respectively. Commercial paper maturities will vary but may not exceed 364 days from the date of issue. The commercial paper is not redeemable or subject to voluntary prepayment by us prior to maturity. We had no amounts outstanding under our commercial paper program as of December 31, 2014 and 2013.
Revolving Credit Facility
On September 30, 2014, we entered into an amendment to the Fourth Amended and Restated Credit Agreement (the "Five-Year Credit Facility"), among Ensco, Citibank, N.A., as Administrative Agent, DNB Bank ASA, as Syndication Agent, and a syndicate of banks. This amendment extended the Five-Year Credit Facility maturity date from May 7, 2018 to September 30, 2019 and increased the total commitment of the lenders from $2.0 billion to $2.25 billion. As amended, the Five-Year Credit Facility provides for a $2.25 billion senior unsecured revolving credit facility to be used for general corporate purposes.
Advances under the Five-Year Credit Facility bear interest at Base Rate or LIBOR plus an applicable margin rate (currently 0.125% per annum for Base Rate advances and 1.125% per annum for LIBOR advances) depending on our credit rating. Amounts repaid may be re-borrowed during the term of the Five-Year Credit Facility. We are required to pay a quarterly commitment fee (currently 0.125% per annum) on the undrawn portion of the $2.25 billion commitment which is also based on our credit rating. In addition to other customary restrictive covenants, the Five-Year Credit Facility requires us to maintain a total debt to total capitalization ratio of less than or equal to 50%. We have the right, subject to receipt of commitments from new or existing lenders, to increase the commitments under the Five-Year Credit Facility to an aggregate amount of up to $2.75 billion. We had no amounts outstanding under the Five-Year Credit Facility as of December 31, 2014 and 2013.
Other Financing
We filed an automatically effective shelf registration statement on Form S-3 with the U.S. Securities and Exchange Commission ("SEC") on January 15, 2015, 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, as amended, expires in January 2018.
In May 2013, our shareholders approved a new share repurchase program. Subject to certain provisions under English law, including the requirement of Ensco plc to have sufficient distributable reserves, we may purchase shares up to a maximum of $2.0 billion in the aggregate under the program, but in no case more than 35.0 million shares. The program terminates in May 2018.
In June 2014, we completed a capital reorganization under UK law (the “Capital Reorganization”), that provides the Company with greater flexibility going forward to return capital to shareholders in the form of dividends and share repurchases. The Capital Reorganization, which was authorized by our Board of Directors and approved by our shareholders at the Annual General Meeting in May 2014, was achieved through the issuance and subsequent cancellation of $3.0 billion of a newly-created class of shares (the “Capital Reorganization Shares”).
The Capital Reorganization Shares had no substantive economic or voting rights and were issued to a subsidiary of the Company on June 17, 2014 for the benefit of existing shareholders solely for the purpose of the Capital Reorganization transaction. Upon cancellation of the shares on June 18, 2014, $3.0 billion of the shareholders' equity of Ensco plc that was previously deemed non-distributable under UK law is now included in distributable reserves.
The Capital Reorganization did not involve any distribution or repayment of capital nor did it have an impact on the underlying net assets of the Company. There was no net impact on our shareholders’ equity for any period as a result of the Capital Reorganization.
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, future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. 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 of December 31, 2014 and the periods in which such obligations are due (in millions):
(1)
Contractual obligations do not include $160.9 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2014. We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts.
Contractual obligations do not include foreign currency forward contracts ("derivatives"). As of December 31, 2014, we had derivatives outstanding to exchange an aggregate $580.6 million U.S. dollars for various foreign currencies. As of December 31, 2014, our consolidated balance sheet included net derivative liabilities of $26.3 million. All of our outstanding derivatives mature during the next 18 months.
a
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 of December 31, 2014, we had not been required to make collateral deposits with respect to these agreements. The following table summarizes our other commitments as of December 31, 2014 (in millions):
Liquidity
Our liquidity position as of December 31, 2014, 2013 and 2012 is summarized below (in millions, except ratios):
We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as dividends or working capital requirements, from our cash and cash equivalents, short-term investments, operating cash flows, funds borrowed under our commercial paper program and, if necessary, funds borrowed under our revolving credit facility.
We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends from our operating cash flows and, if necessary, funds borrowed under our revolving credit facility or other future financing arrangements.
We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.
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. During 2009, the United 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 the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These EPA 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 Prevention of Significant Deterioration ("PSD") construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards to be established by the states or, in some cases, the EPA, on a case-by-case basis. The EPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore and offshore oil and natural gas production facilities.
The Companies Act 2006 (Strategic and Directors' Reports) Regulations 2013 now requires all quoted U.K. companies to report their annual GHG emissions in the company's directors' report. Additionally, in recent years, cap and trade initiatives to limit GHG emissions have been introduced in the European Union. Similarly, a number of bills related to climate change have been introduced in the U.S. Congress. If these or similar bills were to be adopted, such legislation could adversely impact many industries. However, it appears unlikely that comprehensive federal climate legislation will be passed by Congress in the foreseeable future. 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. If Congress undertakes comprehensive tax reform in the future, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. 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 or 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 the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.
MARKET RISK
We use derivatives to reduce our exposure to foreign currency exchange rate risk. Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.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 in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. As of December 31, 2014, we had cash flow hedges outstanding to exchange an aggregate $373.1 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 fair value of the underlying hedged items. As of December 31, 2014, we held derivatives not designated as hedging instruments to exchange an aggregate $207.5 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 of December 31, 2014 would
approximate $21.7 million. Approximately $18.1 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 into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements, which include provisions for a legally enforceable master netting agreement, with almost all of 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 5 to our consolidated financial statements for additional information on our derivative instruments.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires our management 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 by management regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill and income taxes.
Property and Equipment
As of December 31, 2014, the carrying value of our property and equipment totaled $12.5 billion, which represented 78% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate management's 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 by management 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 by management 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.
Our fleet of 20 floater rigs marketed for contract drilling services, exclusive of three rigs under construction, represented 62% of the gross cost and 66% of the net carrying amount of our depreciable property and equipment as of December 31, 2014. Our floater rigs are depreciated over useful lives ranging from 15 to 35 years. Our fleet of 36 jackup rigs marketed for contract drilling services, exclusive of four rigs under construction, represented 26% of the gross cost and 21% of the net carrying amount of our depreciable property and equipment as of December 31, 2014. Our jackup rigs are depreciated over useful lives ranging from ten to 30 years. 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 ended December 31, 2014 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2014:
Impairment of Long-Lived Assets and Goodwill
During the year ended December 31, 2014, we recorded a pre-tax, non cash loss on impairment of long-lived assets of $2.5 billion and a non-cash loss on impairment of our Floaters reporting unit goodwill of $3.0 billion. See "Note 3 - Property and Equipment" and "Note 8 - Goodwill and Other Intangible Assets and Liabilities" to our consolidated financial statements for additional information on our property and equipment and goodwill, respectively.
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.
If the global economy deteriorates and/or other events or changes in circumstances indicate that the carrying value of one or more drilling rigs may not be recoverable, we may conclude that a triggering event has occurred and perform a recoverability test. If, at the time of the recoverability test, management's judgments and assumptions regarding future industry conditions and operations have diminished, it is reasonably possible that we could conclude that one or more of our drilling rigs are impaired.
We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. When testing goodwill for impairment, we perform a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount. Our two
reportable segments represent our reporting units. If we determine it is more-likely-than-not that the fair value of a reporting unit exceeds its carrying value after qualitatively assessing all facts and circumstances, its goodwill is considered not impaired.
If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, we may conclude that the fair value of one or both of our reporting units has more-likely-than-not declined below its carrying amount and perform a quantitative assessment whereby we estimate the fair value of each reporting unit. If, at the time of the goodwill impairment test, management's judgments and assumptions regarding future industry conditions and operations have diminished, or if the market value of our shares has declined, we could conclude that the goodwill of one or both of our reporting units has been impaired.
The calculation of fair values of our reporting units is based on a blended income and market approach. The income approach is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including expected utilization levels, day rates, expense levels, capital requirements and terminal values for each of our rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our goodwill impairment test. It is reasonably possible that the judgments and assumptions inherent in our goodwill impairment test may change in response to future market conditions.
If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium which includes a comparison to implied control premiums from recent market transactions within our industry or other relevant benchmark data. To the extent that the implied control premium based on the aggregate fair value of our reporting units is not reasonable, we adjust the discount rate or other assumptions used in our discounted cash flow model and reduce the estimated fair values of our reporting units.
If the estimated fair value of a reporting unit exceeds its carrying value, its goodwill is considered not impaired. If the estimated fair value of a reporting unit is less than its carrying value, we estimate the implied fair value of the reporting unit's goodwill. If the carrying amount of the reporting unit's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to such excess. In the event we dispose of drilling rig operations that constitute a business, goodwill would be allocated in the determination of gain or loss on disposal.
Asset impairment evaluations are highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of expected utilization levels, day rates, expense levels and capital requirements. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.
Income Taxes
We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2014, our consolidated balance sheet included an $81.3 million net deferred income tax liability, an $84.2 million liability for income taxes currently payable and a $160.9 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 management's 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 would be subject to additional income taxes.
The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on management's interpretation of applicable tax laws and incorporate management's estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions 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 administrative practices and precedents of tax authorities change frequently, requiring us to modify existing tax strategies to conform to such changes.
NEW ACCOUNTING PRONOUNCEMENTS
In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("Update 2014-08"). The new guidance changes the criteria for reporting discontinued operations and enhances disclosure requirements. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Update 2014-08 is effective for annual and interim periods for fiscal years beginning on or after December 15, 2014 and early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. We will adopt the accounting standard on January 1, 2015. The adoption of ASU 2014-08 is expected to reduce the number of components reported as discontinued operations prospectively in our consolidated financial statements.
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) ("Update 2014-09"), which requires an entity to recognize the
amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. Early application is not permitted. We are currently evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures.
In June 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-12, Compensation- Stock Compensation (Topic 718): Accounting for Share Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period ("Update 2014-12"). The new guidance clarifies that entities should treat performance targets that can be met after the requisite service period of a share-based payment award as performance conditions that affect vesting. Update 2014-12 is effective for annual and interim periods for fiscal years beginning after December 15, 2015 and early adoption is permitted. We will adopt the accounting standard on a prospective basis effective January 1, 2016. We do not expect the adoption to have a material effect on our consolidated financial statements.
In August 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“Update 2014-15”). The new guidance clarifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. Update 2014-15 is effective for annual periods ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We will adopt the accounting standard on January 1, 2016. We do not expect the adoption to have a material effect on our consolidated financial statements.
Item 7A.
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."
Item 8.
Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined
to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2014 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, has issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.
March 2, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
Ensco plc:
We have audited the accompanying consolidated balance sheets of Ensco plc and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive (loss) income, and cash flows for each of the years in the three-year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ensco plc and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Ensco plc’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
March 2, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
Ensco plc:
We have audited Ensco plc’s (the Company) internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Ensco plc maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Ensco plc and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive (loss) income, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated March 2, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
March 2, 2015
ENSCO PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
ENSCO PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(in millions)
The accompanying notes are an integral part of these consolidated financial statements.
ENSCO PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except share and par value amounts)
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
ENSCO PLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We own an offshore drilling rig fleet of 70 rigs, including seven rigs under construction, spanning most of the strategic markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, five moored semisubmersible rigs and 42 jackup rigs. Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is one of the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.
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 and drilling contracts spanning approximately 20 countries on six continents in nearly every major offshore basin around the world. The markets in which we operate include the U.S. Gulf of Mexico, Mexico, Brazil, the Mediterranean, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.
We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide a drilling rig and rig crews and receive a fixed amount per day for each day we are performing drilling or related services. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.
Redomestication
During 2009, we completed a reorganization of the corporate structure of the group of companies controlled by our predecessor, ENSCO International Incorporated ("Ensco Delaware"), pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company incorporated under English law (the "redomestication").
We remain subject to the U.S. Securities and Exchange Commission (the "SEC") reporting requirements, the mandates of the Sarbanes-Oxley Act of 2002, as amended, and the applicable corporate governance rules of the New York Stock Exchange ("NYSE"), and we will continue to report our consolidated financial results in U.S. dollars and in accordance with U.S. generally accepted accounting principles ("U.S. GAAP"). We also must comply with additional reporting requirements of English law.
Basis of Presentation-U.K. Companies Act 2006 Section 435 Statement
The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP, which the Board of Directors consider to be the most meaningful presentation of our results of operations and financial position. The accompanying consolidated financial statements do not constitute statutory accounts required by the U.K. Companies Act 2006, which for the year ended December 31, 2014 will be prepared in accordance with generally accepted accounting principles in the U.K. and delivered to the Registrar of Companies in the U.K. following the annual general meeting of shareholders. The U.K. statutory accounts are expected to include an unqualified auditor’s report, which is not expected to contain any references to matters on which the auditors drew attention by way of emphasis without qualifying the report or any statements under Sections 498(2) or 498(3) of the U.K. Companies Act 2006.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Ensco plc and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Certain previously reported amounts have been reclassified to conform to the current year presentation.
Pervasiveness of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.
Foreign Currency Remeasurement and Translation
Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Most transaction gains and losses, including certain gains and losses on our derivative instruments, are included in other, net, in our consolidated statement of operations. Certain gains and losses from the translation of foreign currency balances of our non-U.S. dollar functional currency subsidiaries are included in accumulated other comprehensive income on our consolidated balance sheet. Net foreign currency exchange gains and losses, inclusive of offsetting fair value derivatives, were $2.6 million of losses, $6.4 million of gains and $3.5 million of losses, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
Cash Equivalents and Short-Term Investments
Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year at the date of purchase are classified as short-term investments.
Short-term investments, consisting of time deposits with initial maturities in excess of three months but less than one year, were included in other current assets on our consolidated balance sheets and totaled $757.3 million and $50.0 million as of December 31, 2014 and 2013, respectively. Cash flows from purchases and maturities of short-term investments were classified as investing activities in our consolidated statements of cash flows for the years ended December 31, 2014, 2013 and 2012.
Property and Equipment
All costs incurred in connection with the acquisition, construction, major enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Repair and maintenance costs are charged to contract drilling expense in the period in which they are incurred. Upon sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet, and the resulting gain or loss is included in contract drilling expense, unless reclassified to discontinued operations.
Our property and equipment is depreciated on a straight-line basis, after allowing for salvage values, over the estimated useful lives of our assets. Drilling rigs and related equipment are depreciated over estimated useful lives ranging from four to 35 years. Buildings and improvements are depreciated over estimated useful lives ranging from two to 30 years. Other equipment, including computer and communications hardware and software costs, is depreciated over estimated useful lives ranging from two to six years.
We evaluate the carrying value of our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. 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. Property and equipment held for sale is recorded at the lower of net book value or net realizable value.
During 2014, we recorded a pre-tax, non cash loss on impairment of long-lived assets of $2.5 billion. See "Note 3 - Property and Equipment" for additional information on these impairments.
If the global economy deteriorates and/or our expectation relative to future offshore drilling industry conditions decline, it is reasonably possible that additional impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.
Goodwill
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
We test goodwill for impairment on an annual basis as of December 31 of each year or when events or changes in circumstances indicate that a potential impairment exists. When testing goodwill for impairment, we perform a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount.
If we conclude that the fair value of one or both of our reporting units has more-likely-than-not declined below its carrying amount after qualitatively assessing existing facts and circumstances, we perform a quantitative assessment whereby we estimate the fair value of each reporting unit. In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by the drilling rigs in the reporting unit.
Based on a qualitative assessment performed as of December 31, 2014, we concluded it was more-likely-than-not that the fair value of our Floater reporting unit was less than its carrying amount and performed a quantitative assessment. As a result, we concluded that our Floater reporting unit goodwill balance was impaired. See "Note 8 - Goodwill and Other Intangible Assets and Liabilities" for additional information on our goodwill.
We concluded the fair value of our Jackup reporting more-likely-than-not exceeded its carrying amount, and there was no impairment of goodwill.
Operating Revenues and Expenses
Substantially all of our drilling contracts ("contracts") are performed on a day rate basis, and the terms of such contracts are typically for a specific period of time or the period of time required to complete a specific task, such as drill a well. Contract revenues and expenses are recognized on a per day basis, as the work is performed. Day rate revenues are typically earned, and contract drilling expense is typically incurred, on a uniform basis over the terms of our contracts.
In connection with some contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in operating revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in contract drilling expense.
Mobilization fees received and costs incurred prior to commencement of drilling operations are deferred and recognized on a straight-line basis over the period that the related drilling services are performed. Demobilization fees and related costs are recognized as incurred upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are expensed as incurred.
Deferred mobilization costs were included in other current assets and other assets, net, on our consolidated balance sheets and totaled $95.7 million and $66.6 million as of December 31, 2014 and 2013, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $149.4 million and $76.8 million as of December 31, 2014 and 2013, respectively.
In connection with some contracts, we receive up-front lump-sum fees or similar compensation for capital improvements to our drilling rigs. Such compensation is deferred and recognized as revenue over the period that the related drilling services are performed. The cost of such capital improvements is capitalized and depreciated over the useful life of the asset. Deferred revenue associated with capital improvements was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $428.9 million and $273.6 million as of December 31, 2014 and 2013, respectively.
We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized over the corresponding certification periods. Deferred regulatory certification and compliance costs were included in other current assets and other assets, net, on our consolidated balance sheets and totaled $20.0 million and $18.3 million as of December 31, 2014 and 2013, respectively.
In certain countries in which we operate, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statement of operations.
Derivative Instruments
We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 5 - Derivative Instruments" for additional information on how and why we use derivatives.
All derivatives are recorded on our consolidated balance sheet at fair value. Derivatives subject to legally enforceable master netting agreements are not offset on our consolidated balance sheet. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. Derivatives qualify for hedge accounting when they are formally designated as hedges and are effective in reducing the risk exposure that they are designated to hedge. Our assessment of hedge effectiveness is formally documented at hedge inception, and we review hedge effectiveness and measure any ineffectiveness throughout the designated hedge period on at least a quarterly basis.
Changes in the fair value of derivatives that are designated as hedges of the variability in expected future cash flows associated with existing recognized assets or liabilities or forecasted transactions ("cash flow hedges") are recorded in accumulated other comprehensive income ("AOCI"). Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transactions.
Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualifies as effective due to an unanticipated change in the forecasted transaction are recognized currently in earnings and included in other, net, in our consolidated statement of operations based on the change in the fair value of the derivative. When a forecasted transaction is probable of not occurring, gains and losses on the derivative previously recorded in AOCI are reclassified currently into earnings and included in other, net, in our consolidated statement of operations.
We occasionally enter into derivatives that hedge the fair value of recognized assets or liabilities, but do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, there generally is a natural hedging relationship where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in other, net, in our consolidated statement of operations.
Derivatives with asset fair values are reported in other current assets or other assets, net, on our consolidated balance sheet depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities on our consolidated balance sheet depending on maturity date.
Income Taxes
We conduct operations and earn income in numerous countries. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.
Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.
We operate in certain jurisdictions where tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. Interest and penalties relating to income taxes are included in current income tax expense in our consolidated statement of operations.
Our drilling rigs frequently move from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may involve a transfer of drilling rig ownership among our subsidiaries (“intercompany rig sale”). The pre-tax profit resulting from an intercompany rig sale is eliminated from our consolidated financial statements, and the carrying value of a rig sold in an intercompany transaction remains at historical net depreciated cost prior to the transaction. Our consolidated financial statements do not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary. Income taxes resulting from an intercompany rig sale, as well as the tax effect of any reversing temporary differences resulting from the sale, are deferred and amortized on a straight-line basis over the remaining useful life of the rig.
In some instances, we may determine that certain temporary differences will not result in a taxable or deductible amount in future years, as it is more-likely-than-not we will commence operations and depart from a given taxing jurisdiction without such temporary differences being recovered or settled. Under these circumstances, no future tax consequences are expected and no deferred taxes are recognized in connection with such operations. We evaluate these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized or derecognized.
We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. See "Note 9 - Income Taxes" for additional information on our deferred taxes, unrecognized tax benefits, intercompany transfers of drilling rigs and undistributed earnings.
Share-Based Compensation
We sponsor share-based compensation plans that provide equity compensation to our key employees, officers and non-employee directors. Share-based compensation cost is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). The amount of compensation cost recognized in our consolidated statement of operations is based on the awards ultimately expected to vest and, therefore, reduced for estimated forfeitures. All changes in estimated forfeitures are based on historical experience and are recognized as a cumulative adjustment to compensation cost in the period in which they occur. See "Note 7 - Benefit Plans" for additional information on our share-based compensation.
Fair Value Measurements
We measure certain of our assets and liabilities based on a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements represent inputs that are observable for similar assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. See "Note 2 - Fair Value Measurements" for additional information on the fair value measurement of certain of our assets and liabilities.
Earnings Per Share
We compute basic and diluted earnings per share ("EPS") in accordance with the two-class method. Net (loss) income attributable to Ensco used in our computations of basic and diluted EPS is adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS is calculated using the treasury stock method and excludes non-vested shares.
The following table is a reconciliation of (loss) income from continuing operations attributable to Ensco shares used in our basic and diluted EPS computations for each of the years in the three-year period ended December 31, 2014 (in millions):
The following table is a reconciliation of the weighted-average shares used in our basic and diluted earnings per share computations for each of the years in the three-year period ended December 31, 2014 (in millions):
Antidilutive share options totaling 400,000, 300,000 and 400,000 for the years ended December 31, 2014, 2013 and 2012, respectively, were excluded from the computation of diluted EPS.
Noncontrolling Interests
Third parties hold a noncontrolling ownership interest in certain of our non-U.S. subsidiaries. Noncontrolling interests are classified as equity on our consolidated balance sheet and net income attributable to noncontrolling interests is presented separately in our consolidated statement of operations.
(Loss) income from continuing operations attributable to Ensco for each of the years in the three-year period ended December 31, 2014 was as follows (in millions):
(Loss) income from discontinued operations attributable to Ensco for each of the years in the three-year period ended December 31, 2014 was as follows (in millions):
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) ("Update 2014-09"), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. Early application is not permitted. We are currently evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures.
2. FAIR VALUE MEASUREMENTS
The following fair value hierarchy table categorizes information regarding our net financial assets measured at fair value on a recurring basis as of December 31, 2014 and 2013 (in millions):
Supplemental Executive Retirement Plans
Our Ensco supplemental executive retirement plans (the "SERP") are non-qualified plans that provide for eligible employees to defer a portion of their compensation for use after retirement. Assets held in the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our consolidated balance sheets as of December 31, 2014 and 2013. The fair value measurements of assets held in the SERP were based on quoted market prices. Net unrealized gains of $2.3 million, $6.2 million and $2.8 million from marketable securities held in our SERP were included in other, net, in our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
Derivatives
Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2014 and 2013. See "Note 5 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurements of our derivatives were based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.
Other Financial Instruments
The carrying values and estimated fair values of our debt instruments as of December 31, 2014 and 2013 were as follows (in millions):
The estimated fair values of our senior notes and debentures were determined using quoted market prices. The estimated fair values of our U.S. Maritime Administration ("MARAD") bonds were determined using an income approach valuation model. The estimated fair values of our cash and cash equivalents, short-term investments, receivables, trade payables and other liabilities approximated their carrying values as of December 31, 2014 and 2013.
See "Note 3 - Property and Equipment" for additional information on the fair value measurement of property and equipment and "Note 8 - Goodwill and Other Intangible Assets and Liabilities" for additional information on the fair value measurement of goodwill.
3. PROPERTY AND EQUIPMENT
Property and equipment as of December 31, 2014 and 2013 consisted of the following (in millions):
During 2014, drilling rigs and equipment declined $2.6 billion primarily due to a loss on impairment of $2.5 billion, depreciation expense of $537.9 million and $152.4 million classified as "held for sale" included in other current assets on our December 31, 2014 consolidated balance sheet. These declines were partially offset by ENSCO 120, ENSCO 121 and ENSCO 122, which were placed into service during 2014 and capital upgrades to the existing rig fleet.
Work in progress as of December 31, 2014 primarily consisted of $820.1 million related to the construction of ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10 ultra-deepwater drillships, $233.1 million related to a capital enhancement project on ENSCO 5006, $179.3 million related to the construction of ENSCO 110, ENSCO 140 and ENSCO 141 premium jackup rigs, $59.2 million related to the construction of ENSCO 123 ultra-premium harsh environment jackup rig and costs associated with various modification and enhancement projects.
Work in progress as of December 31, 2013 primarily consisted of $627.2 million related to the construction of ENSCO 120 Series ultra-premium harsh environment jackup rigs, $513.4 million related to the construction of ENSCO DS-8, ENSCO DS-9 and ENSCO D-S 10 ultra-deepwater drillships, $43.7 million related to the construction of ENSCO 110 premium jackup rig and costs associated with various modification and enhancement projects.
Impairment of Long-Lived Assets
During 2014, we recorded a pre-tax, non cash loss on impairment of long-lived assets of $2,463.1 million, of which $1,220.8 million was included in (loss) income from continuing operations and $1,242.3 million was included in (loss) income from discontinued operations, net in our consolidated statement of operations. These losses were recorded during the second and fourth quarters.
During the second quarter, demand for floaters deteriorated as a result of continued reductions in capital spending by operators in addition to delays in operators’ drilling programs. The reduction in demand, combined with the increasing supply from newbuild floater deliveries, led to a very competitive market. In general, contracting activity declined significantly, and day rates and utilization came under pressure, especially for older, less capable floaters.
In response to the adverse change in the floaters business climate, management evaluated our older, less capable floaters and committed to a plan to sell five rigs. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000 and ENSCO 7500 were removed from our portfolio of rigs marketed for contract drilling services and actively marketed for sale. These rigs were written down to fair value, less costs to sell. We completed the sale of ENSCO 5000 in December 2014. The remaining four floaters were classified as "held for sale" on our December 31, 2014 consolidated balance sheet.
We measured the fair value of the "held for sale" rigs by applying a market approach, which was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We recorded a pre-tax, non-cash loss on impairment totaling $546.4 million during the second quarter associated with our "held for sale" rigs. The impairment charge was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014.
During the fourth quarter, Brent crude oil prices declined from approximately $95 per barrel to near $55 per barrel on December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs. As a result, day rates and utilization came under further pressure, especially for older, less capable rigs. The significant supply and demand imbalance will continue to be adversely impacted by future newbuild deliveries, program delays and lower capital spending by operators.
In response to the adverse change in business climate, management evaluated our aged rigs and committed to a plan to sell one additional floater and two jackups. ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. These rigs were written down to fair value, less costs to sell, during the fourth quarter and classified as "held for sale" on our December 31, 2014 consolidated balance sheet.
As of December 31, 2014, we measured the fair value of our seven "held for sale" rigs by applying a market approach, which was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. In addition to the asset impairment recorded during the second quarter, we recorded an additional pre-tax, non-cash loss on impairment totaling $407.9 million during the fourth quarter. The impairment charge was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014. See "Note 10 - Discontinued Operations" for additional information on our "held for sale" rigs.
On a quarterly basis, we evaluate the carrying value of our property and equipment to identify events or changes in circumstances ("triggering events") that indicate the carrying value may not be recoverable. During the second quarter, as a result of the adverse change in the floater business climate, management's decision to sell five floaters and the impairment charge incurred on the "held for sale" floaters, management concluded that a triggering event had occurred and performed an asset impairment analysis on our remaining older, less capable floaters.
Based on the analysis performed as of May 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to four other floaters totaling $991.5 million, of which $288.0 million related to ENSCO DS-2 which was removed from our portfolio of rigs marketed for contract drilling services during the fourth quarter. The ENSCO DS-2 impairment charge was reclassified to (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014. The remaining $703.5 million impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying an income approach, using projected discounted cash flows. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.
During the fourth quarter, as a result of the decline in commodity prices and adverse changes in the offshore drilling market, management's decision to sell an additional floater and two jackups and the impairment charge incurred on the "held for sale" rigs, management concluded that a triggering event had occurred and performed an asset impairment analysis for all floaters and jackups.
Based on the analysis performed as of December 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to two older, less capable floaters and ten older, less capable jackups totaling $517.3 million. The impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying either an income approach, using projected discounted cash flows, or a market approach. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.
4. DEBT
The carrying value of long-term debt as of December 31, 2014 and 2013 consisted of the following (in millions):
Senior Notes
On September 29, 2014, we issued $625.0 million aggregate principal amount of unsecured 4.50% notes due 2024 at a discount of $850,000 and $625.0 million aggregate principal amount of unsecured 5.75% notes due 2044 (collectively the “2014 Notes”) at a discount of $2.8 million in a public offering. Interest on these notes is payable semiannually in April and October of each year commencing April 1, 2015. The 2014 Notes were issued pursuant to an Indenture between us and Deutsche Bank Trust Company Americas, as trustee (the “Trustee”), dated March 17, 2011 (the "Indenture") and a Second Supplemental Indenture between us and the Trustee, dated September 29, 2014. The net proceeds from the sale of the 2014 Notes are being used for general corporate purposes.
During 2011, we issued $1.0 billion aggregate principal amount of unsecured 3.25% notes due 2016 at a discount of $7.6 million and $1.5 billion aggregate principal amount of unsecured 4.70% notes due 2021 (collectively the “2011 Notes”) at a discount of $29.6 million in a public offering. Interest on these notes is payable semiannually in March and September of each year. The 2011 Notes were issued pursuant to the Indenture, and a supplemental indenture between us and the Trustee, dated March 17, 2011. The net proceeds from the sale of the 2011 Notes were used to fund a portion of the cash consideration payable in connection with the Pride acquisition.
Upon consummation of the Pride acquisition during 2011, we assumed the acquired company's outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million aggregate principal amount of 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of 7.875% senior notes due 2040 (the "Acquired Notes"). Under a supplemental indenture, Ensco plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes. See "Note 15 - Guarantee of Registered Securities" for additional information on the guarantee of the Acquired Notes.
We may redeem each series of the 2014 Notes in whole, at any time or in part from time to time, prior to maturity. If we elect to redeem the 2014 Notes due 2024 before the date that is three months prior to the maturity date or the 2014 Notes due 2044 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 the 2014 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 2011 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 2014 Notes, the 2011 Notes and the Acquired Notes contain customary events of default, including failure to pay principal or interest on such Notes when due, among others. The indentures governing the 2014 Notes, the 2011 Notes and the Acquired 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 Delaware issued $150.0 million of unsecured 7.20% Debentures due November 15, 2027 (the "Debentures") in a public offering. Interest on the Debentures is payable semiannually in May and November. 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. The Debentures are not subject to any sinking fund requirements. During 2009, in connection with the redomestication, Ensco plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures.
The Debentures and the indenture and the supplemental indentures 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 and the supplemental indentures 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.
MARAD Bonds Due 2016 and 2020
During 2001, a subsidiary of Ensco Delaware issued $190.0 million of 15-year bonds which are guaranteed by MARAD to provide long-term financing for ENSCO 7500. In December 2014, we fully redeemed the remaining outstanding principal of these bonds and incurred a "make-whole" payment of $600,000, and MARAD released all interests in ENSCO 7500.
During 2003, a subsidiary of Ensco Delaware issued $76.5 million of 17-year bonds which are guaranteed by MARAD to provide long-term financing for ENSCO 105. The bonds will be repaid in 34 equal semiannual principal installments of $2.3 million ending in October 2020. Interest on the bonds is payable semiannually, in April and October, at a fixed rate of 4.65%.
Ensco Delaware issued separate guaranties to MARAD, guaranteeing the performance of obligations under the bonds. During 2010, the documents governing MARAD's guarantee commitments were amended to address certain changes arising from the redomestication and to include Ensco plc as an additional guarantor of the debt obligations of Ensco Delaware and its subsidiaries.
Upon consummation of the Pride acquisition, we assumed $151.5 million of MARAD bonds issued to provide long-term financing for ENSCO 6003 and ENSCO 6004. The bonds are guaranteed by MARAD and will be repaid in semiannual principal installments ending in 2016. Interest on the bonds is payable semiannually at a weighted average fixed rate of 4.33%.
Commercial Paper
We participate in a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes. During 2014, we increased the size of our program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $2.25 billion at any time outstanding. Amounts issued under the commercial paper program are supported by the available and unused committed capacity under our credit facility. As a result, amounts issued under the commercial paper program are limited by the amount of our available and unused committed capacity under our credit facility. The proceeds of such financings may be used for capital expenditures and other general corporate purposes. The commercial paper bears interest at rates that vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The weighted-average interest rate on our commercial paper borrowings was 0.26% and 0.35% during 2014 and 2013, respectively. Commercial paper maturities will vary but may not exceed 364 days from the date of issue. The commercial paper is not redeemable or subject to voluntary prepayment by us prior to maturity. We had no amounts outstanding under our commercial paper program as of December 31, 2014 and 2013.
Revolving Credit Facility
On September 30, 2014, we entered into an amendment to the Fourth Amended and Restated Credit Agreement (the "Five-Year Credit Facility"), among Ensco, Citibank, N.A., as Administrative Agent, DNB Bank ASA, as Syndication Agent, and a syndicate of banks. This amendment extended the Five-Year Credit Facility maturity date from May 7, 2018 to September 30, 2019 and increased the total commitment of the lenders from $2.0 billion to $2.25 billion. As amended, the Five-Year Credit Facility provides for a $2.25 billion senior unsecured revolving credit facility to be used for general corporate purposes.
Advances under the Five-Year Credit Facility bear interest at Base Rate or LIBOR plus an applicable margin rate (currently 0.125% per annum for Base Rate advances and 1.125% per annum for LIBOR advances) depending on our credit rating. Amounts repaid may be re-borrowed during the term of the Five-Year Credit Facility. We are required to pay a quarterly commitment fee (currently 0.125% per annum) on the undrawn portion of the $2.25 billion commitment which is also based on our credit rating. In addition to other customary restrictive covenants, the Five-Year Credit Facility requires us to maintain a total debt to total capitalization ratio of less than or equal to 50%. We have the right, subject to receipt of commitments from new or existing lenders, to increase the commitments under the Five-Year Credit Facility to an aggregate amount of up to $2.75 billion. We had no amounts outstanding under the Five-Year Credit Facility as of December 31, 2014 and 2013.
Maturities
The aggregate maturities of our debt, excluding net unamortized premiums of $247.9 million, as of December 31, 2014 were as follows (in millions):
Interest expense totaled $161.4 million, $158.8 million and $123.6 million for the years ended December 31, 2014, 2013 and 2012, respectively, which was net of interest amounts capitalized of $78.2 million, $67.7 million and $105.8 million in connection with our newbuild rig construction and other capital projects.
5. DERIVATIVE INSTRUMENTS
We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. 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 mitigate our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by entering into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements, which include provisions for a legally enforceable master netting agreement, with almost all of our derivative counterparties. See "Note 14 - Supplemental Financial Information" for additional information on the mitigation of credit risk relating to counterparties of our derivatives. We do not enter into derivatives for trading or other speculative purposes.
All derivatives were recorded on our consolidated balance sheets at fair value. Derivatives subject to legally enforceable master netting agreements were not offset on our consolidated balance sheets. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for additional information on our accounting policy for derivatives and "Note 2 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.
As of December 31, 2014 and 2013, our consolidated balance sheets included net foreign currency derivative liabilities of $26.3 million and net assets of $1.8 million, respectively. All of our derivatives mature during the next 18 months.
Derivatives recorded at fair value on our consolidated balance sheets as of December 31, 2014 and 2013 consisted of the following (in millions):
(1)
Derivative assets and liabilities that have maturity dates equal to or less than 12 months from the respective balance sheet dates were included in other current assets and accrued liabilities and other, respectively, on our consolidated balance sheets.
(2)
Derivative assets and liabilities that have maturity dates greater than 12 months from the respective balance sheet dates were included in other assets, net, and other liabilities, respectively, on our consolidated balance sheets.
We utilize cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with contract drilling expenses and capital expenditures denominated in various currencies. As of December 31, 2014, we had cash flow hedges outstanding to exchange an aggregate $373.1 million for various foreign currencies, including $194.3 million for British pounds, $81.2 million for Brazilian reais, $35.5 million for Euros, $28.5 million for Singapore dollars, $20.1 million for Australian dollars and $13.5 million for other currencies.
Gains and losses, net of tax, on derivatives designated as cash flow hedges included in our consolidated statements of operations and comprehensive income for each of the years in the three-year period ended December 31, 2014 were as follows (in millions):
(1)
Changes in the fair value of cash flow hedges are recorded in AOCI. Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transaction.
(2)
Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other, net, in our consolidated statements of operations.
(3)
Losses on interest rate lock derivatives reclassified from AOCI into income (effective portion) were included in interest expense, net in our consolidated statements of operations.
(4)
During the year ended December 31, 2014, $400,000 of gains were reclassified from AOCI into contract drilling expense and $900,000 of gains were reclassified from AOCI into depreciation expense in our consolidated statement of operations. During the year ended December 31, 2013, $2.5 million of losses were reclassified from AOCI into contract drilling expense and $900,000 of gains were reclassified from AOCI into depreciation expense in our consolidated statement of operations.
We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. We predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities but 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 fair value of the underlying hedged items. As of December 31, 2014, we held derivatives not designated as hedging instruments to exchange an aggregate $207.5 million for various foreign currencies, including $98.9 million for Euros, $36.1 million for British pounds, $31.1 million for Swiss francs, $10.3 million for Indonesian Rupiah, $8.6 million for Brazilian reais and $22.5 million for other currencies.
Net losses of $24.8 million and net gains of $3.6 million and $1.5 million associated with our derivatives not designated as hedging instruments were included in other, net, in our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
As of December 31, 2014, the estimated amount of net losses associated with derivatives, net of tax, that will be reclassified to earnings during the next 12 months was as follows (in millions):
6. SHAREHOLDERS' EQUITY
Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2014 was as follows (in millions):
During 2013, our shareholders approved a new share repurchase program. Subject to certain provisions under English law, including the requirement of Ensco plc to have sufficient distributable reserves, we may purchase up to a maximum of $2.0 billion in the aggregate under the program, but in no case more than 35.0 million shares. The program terminates during 2018. As of December 31, 2014, there had been no share repurchases under this program.
7. BENEFIT PLANS
Our shareholders approved the 2012 Long-Term Incentive Plan (the “2012 LTIP”) effective January 1, 2012, to provide for the issuance of non-vested share awards, share option awards and performance awards (collectively "awards"). Under the 2012 LTIP, 14.0 million shares were reserved for issuance as awards to officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. As of December 31, 2014, there were 7.7 million shares available for issuance as awards under the 2012 LTIP. Awards may be satisfied by newly issued shares, including shares held by a subsidiary or affiliated entity, or by delivery of shares held in an affiliated employee benefit trust at the Company's discretion.
Non-Vested Share Awards
Grants of non-vested share awards generally vest at rates of 20% or 33% per year, as determined by a committee or subcommittee of the Board of Directors at the time of grant. Our non-vested share awards have voting and dividend rights effective on the date of grant. Compensation expense is measured using the market value of our shares on the date of grant and is recognized on a straight-line basis over the requisite service period (usually the vesting period).
The following table summarizes non-vested share award related compensation expense recognized during each of the years in the three-year period ended December 31, 2014 (in millions):
The following table summarizes the value of non-vested share awards granted and vested during each of the years in the three-year period ended December 31, 2014:
The following table summarizes non-vested share award activity for the year ended December 31, 2014 (shares in thousands):
As of December 31, 2014, there was $100.7 million of total unrecognized compensation cost related to non-vested share awards, which is expected to be recognized over a weighted-average period of 2.1 years.
Share Option Awards
Share option awards ("options") granted to officers and employees generally become exercisable in 25% increments over a four-year period or 33% increments over a three-year period and, to the extent not exercised, expire on the seventh anniversary of the date of grant. Options granted to non-employee directors are immediately exercisable and, to the extent not exercised, expire on the seventh anniversary of the date of grant. The exercise price of options granted under the 2012 LTIP equals the market value of the underlying shares on the date of grant. As of December 31, 2014, options granted to purchase 472,000 shares with a weighted average exercise price of $41.09 were outstanding under the 2012 LTIP and predecessor or acquired plans. No options have been granted since 2011, and there were no unrecognized compensation costs related to options as of December 31, 2014.
Performance Awards
Under the 2012 LTIP, performance awards may be issued to our senior executive officers. Performance awards granted prior to 2013 are payable in Ensco shares, cash or a combination thereof upon attainment of specified performance goals based on relative total shareholder return ("TSR") and absolute and relative return on capital employed ("ROCE"). Performance awards granted during 2013 and 2014 are payable in Ensco shares upon attainment of specified performance goals based on relative TSR and relative ROCE. The performance goals are determined by a committee or subcommittee of the Board of Directors.
Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. Our performance awards granted prior to 2013 are classified as liability awards with compensation expense measured based on the estimated probability of attainment of the specified performance goals and recognized on a straight-line basis over the requisite service period. The estimated probable outcome of attainment of the specified performance goals is based on historical experience, and any subsequent changes in this estimate are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs.
Our performance awards granted during 2013 and 2014 are classified as equity awards with compensation expense recognized on a straight-line basis over the requisite service period. The estimated probable outcome of attainment of the specified performance goals is based on historical experience, and any subsequent changes in this estimate for the relative ROCE performance goal are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs.
The aggregate grant-date fair value of performance awards granted during 2014, 2013 and 2012 totaled $7.4 million, $8.2 million and $7.2 million, respectively. The aggregate fair value of performance awards vested during 2014, 2013 and 2012 totaled $6.9 million, $7.4 million and $5.3 million, respectively, all of which was paid in cash.
During the years ended December 31, 2014, 2013 and 2012, we recognized $3.4 million, $6.6 million and $9.7 million of compensation expense for performance awards, respectively, which was included in general and administrative expense in our consolidated statements of operations. As of December 31, 2014, there was $5.0 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 1.9 years.
Savings Plans
We have profit sharing plans (the "Ensco Savings Plan," the "Ensco Multinational Savings Plan" and the "Ensco Limited Retirement Plan"), which cover eligible employees, as defined within each plan. The Ensco Savings Plan includes a 401(k) savings plan feature which allows eligible employees to make tax deferred contributions to the plan. The Ensco Limited Retirement Plan also allows eligible employees to make tax deferred contributions to the plan. Contributions made to the Ensco Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.
We generally make matching cash contributions to the plans. We match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary. Matching contributions totaled $20.7 million, $21.1 million and $16.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. Profit sharing contributions made into the plans require approval of the Board of Directors and are generally paid in cash. We recorded profit sharing contribution provisions of $30.7 million, $55.3 million and $45.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. Matching contributions and profit sharing contributions become vested in 33% increments upon completion of each initial year of service with all contributions becoming fully vested subsequent to achievement of three or more years of service. We have 1.0 million shares reserved for issuance as matching contributions under the Ensco Savings Plan.
8. GOODWILL AND OTHER INTANGIBLE ASSETS AND LIABILITIES
Goodwill
The carrying amount of goodwill as of December 31, 2014 is detailed below by reporting unit (in millions):
Impairment of Goodwill
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. During the second quarter, demand for floaters deteriorated as a result of a continued reduction in capital spending by operators in addition to announced delays in operators’ drilling programs. The reduction in demand, combined with increasing supply from newbuild floater deliveries, led to a very competitive market. In
general, contracting activity for floaters declined significantly and day rates and utilization came under pressure, especially for older, less capable floaters.
Management considered the adverse change in the floater business climate, the commitment to a plan to sell five floaters in May 2014, and the impairment charge on the "held for sale" floaters during the second quarter and concluded that a triggering event had occurred. We performed an interim goodwill impairment test to evaluate the recoverability of the Floaters reporting unit goodwill balance of $3.1 billion as of May 31, 2014. Based on the valuation performed, the Floaters reporting unit estimated fair value exceeded the carrying value by approximately 7%; therefore, we concluded that the goodwill balance was not impaired.
As part of our annual goodwill impairment test as of December 31, 2014, we considered the significant decline in commodity prices during the fourth quarter of 2014. Specifically, Brent crude oil prices declined from approximately $95 per barrel at September 30, 2014 to near $55 per barrel at December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs. We expect that this reduction in demand will cause further deterioration in day rates and utilization and that current market dynamics will create a challenging contracting environment into 2016.
Our stock price also declined significantly during the latter half of 2014, reaching a five-year low of $25.88 on December 16th. Our stock price traded between $25.88 and $41.99 during the fourth quarter of 2014 and averaged $35.23 during this period.
Management considered the adverse changes in the current floater business climate, the sustained decline in stock price and the impairment charge on older, less capable floaters during the fourth quarter and concluded it was more-likely-than-not that the fair value of the Floater reporting unit was less than its carrying amount. As a result, we estimated the fair value of the reporting unit using a blended income and market approach. Based on the valuation performed as of December 31, 2014, the reporting unit estimated fair value was less than the carrying value; therefore, we concluded that the Floater goodwill balance was impaired. We compared the estimated fair value of the reporting unit to the fair value of all assets and liabilities of the reporting unit to calculate the implied fair value of goodwill. As a result, we recorded a non-cash loss on impairment totaling $3.0 billion which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014.
The income approach was based on a discounted cash flow model, which utilized present values of cash flows to estimate fair value. The future cash flows were projected based on our estimates of future day rates, utilization, operating costs, capital requirements, growth rates and terminal values. Forecasted day rates and utilization take into account current market conditions and our anticipated business outlook, both of which have been impacted by the adverse changes in the floater business environment during 2014. The day rates reflected contracted rates during the respective contracted periods and management's estimate of market day rates in uncontracted periods. The forecasted market day rates were held constant in the near-term but were forecasted to grow in the longer-term and terminal period.
Operating costs were forecasted using a combination of our historical average operating costs and expected future costs, adjusted for an estimated inflation factor. Capital requirements in the discounted cash flow model were based on management's estimates of future capital costs, taking into consideration our historical trends. The estimated capital requirements included cash outflows for new rig construction, rig enhancements and minor upgrades and improvements.
A terminal period was used to reflect our estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 3.0%, which includes an estimated inflation factor. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital ("WACC") of 11.0%. These assumptions were derived from unobservable inputs and reflect management's judgments and assumptions.
The market approach was based upon the application of price-to-earnings multiples to management's estimates of future earnings adjusted for a control premium. The price-to-earnings multiples used in the market valuation ranged from 6.0x to 6.8x and were based on market participant multiples. Management's earnings estimates were derived
from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.
The estimated fair value of the Floaters reporting unit determined under the income approach was consistent with the estimated fair value determined under the market approach. For purposes of the goodwill impairment test, we calculated the Floaters reporting unit estimated fair value as the average of the values calculated under the income approach and the market approach.
We evaluated the estimated fair value of our reporting units compared to our market capitalization as of December 31, 2014. To perform this assessment, we used a market approach to estimate the fair value of the Jackups reporting unit. The aggregate fair values of our reporting units exceeded our market capitalization, and we believe the resulting implied control premium was reasonable based on recent market transactions within our industry or other relevant benchmark data.
We performed a qualitative assessment for our Jackup reporting unit as of December 31, 2014. Goodwill impairment tests performed during prior years indicated that the fair value of the Jackup reporting unit significantly exceeded its carrying amount. Despite the adverse changes in the offshore drilling climate, we concluded that the fair value remains substantially in excess of the carrying value of the reporting unit, as evidenced by the estimated fair value of the Jackup reporting unit calculated for the purpose of reconciling the fair value of our reporting units to our market capitalization. Therefore, we concluded that it remains more-likely-than-not that the Jackup reporting unit was not impaired.
The estimates used to determine the fair value of the Floaters reporting unit reflect management's best estimates, and we believe they are reasonable. Future declines in the Floaters reporting unit's operating performance or our anticipated business outlook may reduce the estimated fair value of our Floaters reporting unit and result in additional impairments. Factors that could have a negative impact on the fair value of the Floaters reporting unit include, but are not limited to:
•
decreases in estimated market day rates and utilization due to greater-than-expected market pressures, downtime and other risks associated with offshore rig operations;
•
sustained declines in our stock price;
•
decreases in revenue due to our inability to attract and retain skilled personnel;
•
changes in worldwide rig supply and demand, competition or technology, including changes as a result of newbuild rig deliveries;
•
changes in future levels of drilling activity and expenditures, whether as a result of global capital markets and liquidity, prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs;
•
possible cancellation or suspension of drilling contracts as a result of mechanical difficulties, performance or other reasons;
•
delays in contract commencement dates;
•
the outcome of litigation, legal proceedings, investigations or other claims or contract disputes resulting in significant cash outflows;
•
governmental, regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations (such as the Gulf of Mexico during hurricane season);
•
increases in the market-participant risk-adjusted WACC;
•
declines in anticipated growth rates.
Adverse changes in one or more of these factors could result in additional goodwill impairments in future periods.
Drilling Contract Intangibles
In connection with the Pride acquisition, we recorded intangible assets and liabilities representing the estimated fair values of the acquired company's firm drilling contracts in place at the date of acquisition with favorable or unfavorable contract terms as compared to then-current market day rates for comparable drilling rigs.
The gross carrying amounts of our drilling contract intangibles, which we consider to be definite-lived intangibles assets and intangible liabilities, and accumulated amortization as of December 31, 2014 and 2013 were as follows (in millions):
The various factors considered in the determination of the fair values of our drilling contract intangibles were (1) the contracted day rate for each contract, (2) the remaining term of each contract, (3) the rig class and (4) the market conditions for each respective rig class at the date of acquisition. The intangible assets and liabilities were calculated based on the present value of the difference in cash inflows over the remaining contract term as compared to a hypothetical contract with the same remaining term at an estimated then-current market day rate using a risk-adjusted discount rate and an estimated effective income tax rate.
We amortize the drilling contract intangibles to operating revenues over the respective remaining drilling contract terms on a straight-line basis. The estimated net (reduction) increase to future operating revenues related to the amortization of these intangible assets and liabilities as of December 31, 2014, is as follows (in millions):
9. INCOME TAXES
We generated loss of $460.3 million, income of $173.4 million and $101.1 million from continuing operations before income taxes in the U.S. and loss of $2.1 billion, income of $1.5 billion and $1.2 billion from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2014, 2013 and 2012, respectively.
The following table summarizes components of the provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2014 (in millions):
Deferred Taxes
The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2014 and 2013 (in millions):
The realization of substantially all of our deferred tax assets is dependent on generating sufficient taxable income during future periods in various jurisdictions in which we operate. Realization of certain of our deferred tax assets is not assured. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change.
As of December 31, 2014, we had deferred tax assets of $98.6 million for U.S. foreign tax credits (“FTC”) and $204.5 million related to $814.5 million of net operating loss (“NOL”) carryforwards, which can be used to reduce our income taxes payable in future years. The FTC expire between 2017 and 2023. NOL carryforwards, which were generated in various jurisdictions worldwide, include $459.5 million that do not expire and $355.0 million that will expire, if not utilized, beginning in 2015 through 2020. Due to the uncertainty of realization, we have a $267.5 million valuation allowance on FTC and NOL carryforwards, primarily relating to countries where we no longer operate or do not expect to generate future taxable income.
Effective Tax Rate
Ensco 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 not subject to U.K. taxation. As a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. Our consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2014, differs from the U.K. statutory income tax rate as follows:
Our consolidated effective income tax rate for 2014 includes the impact of various discrete tax items, including the recognition of a net $18.4 million tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years, and a $16.4 million tax benefit associated with rig impairments. In addition, we recognized a net $41.4 million tax benefit in connection with the utilization of foreign tax credits that were previously subject to a valuation allowance.
The majority of discrete tax expense recognized during 2013 was attributable to the recognition of a $7.4 million liability for taxes associated with a $30.6 million reimbursement from the resolution of a dispute with the Mexican tax authority and a $7.0 million increase in the valuation allowance on U.S. foreign tax credits resulting from a restructuring transaction in December 2013.
The majority of discrete tax expense recognized during 2012 was attributable to $51.2 million of income tax expense associated with the restructuring of certain subsidiaries of Pride in December 2012, and tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years.
Excluding the impact of the aforementioned tax items and goodwill and asset impairments, our consolidated effective income tax rates for the years ended December 31, 2014, 2013 and 2012 were 10.7%, 12.2% and 12.4%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three
years result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and the differences in the tax rates in such tax jurisdictions.
Unrecognized Tax Benefits
Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. As of December 31, 2014, we had $134.4 million of unrecognized tax benefits, of which $115.9 million was included in other liabilities on our consolidated balance sheet and the remaining $18.5 million, which is associated with a tax position taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets. As of December 31, 2013, we had $151.7 million of unrecognized tax benefits, of which $130.7 million was included in other liabilities on our consolidated balance sheet and the remaining $21.0 million was presented as a reduction of deferred tax assets. If recognized, $110.4 million of our unrecognized tax benefits would impact our consolidated effective income tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2014 and 2013 is as follows (in millions):
Accrued interest and penalties totaled $26.5 million and $17.3 million as of December 31, 2014 and 2013, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized net expense of $9.2 million, benefits $1.6 million and $2.8 million associated with interest and penalties during the years ended December 31, 2014, 2013 and 2012, respectively. Interest and penalties are included in current income tax expense in our consolidated statements of operations.
Tax years as early as 2004 remain subject to examination in the major tax jurisdictions in which we operated. Ensco Delaware and Ensco United Incorporated, an indirect wholly-owned subsidiary of Ensco, participate in the U.S. Internal Revenue Service’s Compliance Assurance Process ("IRS CAP") which, among other things, provides for the resolution of tax issues in a timely manner and generally eliminates the need for lengthy post-filing examinations. The 2010, 2011, 2012 and 2013 U.S. federal tax returns of Ensco Delaware remain subject to examination under the IRS CAP.
Statutes of limitations applicable to certain of our tax positions lapsed during 2014, 2013 and 2012, resulting in net income tax benefits, inclusive of interest and penalties, of $2.4 million, $3.1 million and $28.6 million, respectively.
Statutes of limitations applicable to certain of our tax positions will lapse during 2015. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $9.6 million, inclusive of $2.8 million of accrued interest and penalties, all of which would impact our consolidated effective income tax rate if recognized.
Intercompany Transfer of Drilling Rigs
During the three-year period ended December 31, 2014, we transferred ownership of certain drilling rigs among our subsidiaries, including three jackup rigs during 2014, two semisubmersible rigs during 2013 and one jackup rig during 2012. There was no income tax liability associated with the intercompany transfers of drilling rigs during 2014 and 2013. A $1.7 million income tax liability resulted from the gain on the intercompany transfer of the jackup rig in 2012. The related income tax expense was deferred and is being amortized on a straight-line basis over the 15-year remaining useful life of the rig. There were no temporary differences associated with any of the intercompany transfers of drilling rigs during the three-year period ended December 31, 2014
As of December 31, 2014 and 2013, the unamortized balance associated with deferred charges for income taxes incurred in connection with intercompany transfers of drilling rigs totaled $39.7 million and $50.2 million, respectively, and was included in other assets, net, on our consolidated balance sheets. Current income tax expense for the years ended December 31, 2014, 2013 and 2012 included $2.6 million, $4.1 million and $9.1 million, respectively, of amortization of income taxes incurred in connection with intercompany transfers of drilling rigs.
As of December 31, 2014 and 2013, the unamortized balance associated with the deferred tax liability for reversing temporary differences of transferred drilling rigs totaled $23.0 million and $29.2 million, respectively, and was included in deferred income taxes on our consolidated balance sheets. Deferred income tax benefit for the year ended December 31, 2014 and deferred income tax expense for the years ended December 31, 2013 and 2012 included benefits of $4.8 million, $1.9 million and $3.4 million, respectively, of amortization of deferred reversing temporary differences associated with intercompany transfers of drilling rigs.
Undistributed Earnings
Dividend income received by Ensco plc from its subsidiaries is exempt from U.K. taxation. We do not provide deferred taxes on undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Each of the subsidiaries for which we maintain such policy has significant net assets, liquidity, contract backlog and/or other financial resources available to meet operational and capital investment requirements and otherwise allow us to continue to maintain our policy of reinvesting the undistributed earnings indefinitely.
In December 2012, a U.S. subsidiary received $530.0 million in earnings distributions from two non-U.S. subsidiaries. There was no net U.S. tax liability on the earnings repatriation, as we utilized net operating loss carryforwards to offset the previously untaxed portion of the earnings distribution. The earnings distribution was made in consideration of unique circumstances, and our U.S. subsidiaries continue to have significant net assets, liquidity, contract backlog and other financial resources available to meet operational and capital investment requirements. Accordingly, this distribution did not change, and we continue to maintain, our policy and intention to reinvest the undistributed earnings of the two aforementioned subsidiaries indefinitely.
As of December 31, 2014 and 2013, the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $2.3 billion and $2.1 billion, respectively. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we would be subject to additional income taxes. The unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate as of December 31, 2014.
10. DISCONTINUED OPERATIONS
We sold the following rigs during the three-year period ended December 31, 2014 (in millions):
(1) The rigs' operating results were reclassified to discontinued operations in our consolidated statements of operations for each of the years in the three-year period ended December 31, 2014 and were previously included within the operating segment noted in the above table.
(2) Includes the rig's net book value as well as inventory and other assets on the date of the sale.
(3) In September 2014, we sold jackup rigs ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98, all of which are contracted to Pemex. As described below, the loss on sale and operating results of ENSCO 93 were included in (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014.
During 2014, management committed to a plan to sell six floaters and two jackups. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500, ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. These rigs were written down to fair value, less costs to sell. We recorded a non-cash loss on impairment totaling $1.2 billion, net of tax benefits of $83.5 million, during the year ended December 31, 2014. The impairment charge was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2014.
We completed the sale of ENSCO 5000 for net proceeds of $1.3 million in December 2014. The remaining five floaters and two jackups are being actively marketed for sale and were classified as "held for sale" on our December 31, 2014 consolidated balance sheet.
The operating results from these rigs were included in (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014.
During 2014, we sold ENSCO 93, a jackup contracted to Pemex. In connection with this sale, we executed a charter agreement with the purchaser to continue operating the rig for the remainder of the Pemex contract, which had an anticipated completion date in late 2015. Based on market developments during the fourth quarter, we now expect that the ENSCO 93 charter agreement will terminate prior to September 30, 2015. As a result, the loss on sale of $1.2 million and ENSCO 93 operating results were reclassified to (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014. Net proceeds from the sale of $51.7 million were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. See "Note 12 - Sale-leaseback" for additional information.
During 2014, we sold ENSCO 85 for net proceeds of $64.4 million and ENSCO 69 and Pride Wisconsin for net proceeds of $32.2 million. The operating results of these rigs were included in (loss) income from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2014. The net proceeds from the sale for ENSCO 69 and Pride Wisconsin were received in December 2013 and included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2013.
During 2012, we classified jackup rig Pride Pennsylvania as held for sale, and the rig was written down to fair value less estimated cost to sell. We recognized a $2.5 million loss for assets classified as held for sale during the year ended December 31, 2012.
The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2014 (in millions):
Debt and interest expense are not allocated to our discontinued operations.
During 2008, ENSCO 74 was lost as a result of Hurricane Ike in the U.S. Gulf of Mexico. The owner of a pipeline filed claims alleging that ENSCO 74 caused the pipeline to rupture during Hurricane Ike. We incurred $3.6 million in professional fees in connection with this matter, which we applied against our $10.0 million per occurrence deductible under our liability insurance policy.
In February 2014, we reached an agreement with the owner of the pipeline to settle the claims for $9.6 million. Accordingly, we recorded a $6.4 million charge for our remaining obligation under our liability insurance policy in loss from discontinued operations in our consolidated statement of operations for the year ended December 31, 2013. The remaining $3.2 million was settled by our underwriters. See "Note 11 - Commitments and Contingencies" for additional information on the ENSCO 74 loss.
11. COMMITMENTS AND CONTINGENCIES
Leases
We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $54.4 million, $49.1 million and $46.9 million during the years ended December 31, 2014, 2013 and 2012, respectively. Future minimum rental payments under our noncancellable operating lease obligations are as follows: $77.3 million during 2015; $31.8 million during 2016; $16.2 million during 2017; $10.6 million during 2018; $10.2 million during 2019 and $55.0 million thereafter.
Capital Commitments
The following table summarizes the cumulative amount of contractual payments made as of December 31, 2014 for our rigs under construction and estimated timing of our remaining contractual payments (in millions):
(1)
Cumulative paid represents the aggregate amount of contractual payments made from commencement of the construction agreement through December 31, 2014.
(2)
Total commitments are based on fixed-price shipyard construction contracts, exclusive of costs associated with commissioning, systems integration testing, project management and capitalized interest.
Future contractual payments for rig enhancement projects, which are not reflected in the table above, are $42.8 million. We currently estimate these payments will be made during 2015.
The timing of these expenditures may vary based on the completion of various construction milestones, which are, to a large extent, beyond our control.
ENSCO 29 Wreck Removal
During 2005, a portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina. In June 2014, we received a letter from an operator demanding that Ensco retrieve the derrick and drawworks from the seabed.
Our property insurance policies include coverage for the ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also maintain liability insurance policies that provide coverage under certain circumstances for wreckage and debris removal costs in excess of the $3.8 million coverage provided under the property insurance policies. We believe that it is not probable a liability exists with respect to this matter, and no liability has been recorded on our consolidated balance sheet as of December 31, 2014. While we cannot reasonably estimate a range of possible loss at this time, it is possible that removal costs may be in excess of our insurance coverage. Although we do not expect costs associated with the ENSCO 29 wreck removal to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.
ENSCO 74 Loss
During 2008, ENSCO 74 was lost as a result of Hurricane Ike in the U.S. Gulf of Mexico. The sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker during 2009. Wreck removal operations on the sunken rig hull of ENSCO 74 were completed during 2010.
We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law during 2009. A number of claimants presented claims in the exoneration/limitation proceedings. We have liability insurance policies that provide coverage for such claims as well as removal of wreckage and debris in excess of the property
insurance policy sublimit, subject to a $10.0 million per occurrence deductible for third-party claims and an annual aggregate limit of $490.0 million.
The owner of a pipeline filed claims alleging that ENSCO 74 caused the pipeline to rupture during Hurricane Ike and sought damages for the cost of repairs and business interruption in an amount in excess of $26.0 million. During 2014, we reached an agreement with the owner of the pipeline to settle the claims for $9.6 million. Prior to the settlement we incurred legal fees of $3.6 million for this matter. During 2014, we paid the remaining $6.4 million of our deductible under our liability insurance policy, which was included in (loss) income from discontinued operations, net in our consolidated statement of operations for the year ended December 31, 2013. The remaining $3.2 million was paid by our underwriters under the terms of the related insurance policies.
The owner of the oil tanker that struck the hull of ENSCO 74 filed claims seeking monetary damages currently in excess of $5.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. This matter went to trial in June 2014, and the Company won a directed verdict on all claims. The plaintiff has the right to appeal the decision. We believe that it is not probable that a liability exists with respect to these claims.
We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.
Although we do not expect final disposition of the claims associated with the ENSCO 74 loss to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.
Asbestos Litigation
We and certain subsidiaries have been named as defendants, along with numerous third-party companies as co-defendants, in multi-party lawsuits filed in Illinois, Mississippi, Texas, Louisiana and the UK by approximately 125 plaintiffs. The lawsuits seek an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the 1960s through the 1980s.
During 2013, we reached an agreement in principle with 58 of the plaintiffs to settle lawsuits filed in Mississippi for a nominal amount. A special master reviewed all 58 cases and made an allocation of settlement funds among the parties. The District Court Judge reviewed the allocations and accepted the special master’s recommendations and approved the settlements. The settlement documents and final documentation for the individual plaintiffs are being processed.
We intend to vigorously defend against the remaining claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.
In addition to the pending cases in Illinois, Mississippi, Texas, Louisiana and the UK, we have other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect final disposition of these asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.
Other Matters
In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings,
including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.
In the ordinary course of business with customers and others, we have entered into 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. Letters of credit outstanding as of December 31, 2014 totaled $263.9 million and are issued under facilities provided by various banks and other financial institutions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2014, we had not been required to make collateral deposits with respect to these agreements.
12. SALE-LEASEBACK
In September 2014, we sold jackup rigs ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98, all of which were contracted to Pemex. We received proceeds of $211.8 million and incurred commissions and other incremental, direct costs of $5.3 million. The carrying value of these rigs was $169.6 million.
In connection with this sale, we executed charter agreements with the purchaser to continue operating the rigs for the remainder of the Pemex contracts, which have anticipated completion dates in either late 2015 or 2016. We accounted for the transaction as a sale-leaseback, whereby we will retain a significant portion of the remaining use of the rigs as a result of the charter agreements.
We recorded an aggregate gain on sale of $7.5 million at the time of disposal, which represented the portion of the gain that exceeded the present value of payments due under the charter agreements, and was included in contract drilling expense in our consolidated statement of operations for the year ended December 31, 2014. The remaining $29.4 million gain was deferred and amortized to contract drilling expense within the Jackup segment over the remaining charter term of each rig. Of the $29.4 million deferred gain, $7.0 million was recognized in contract drilling expense in our consolidated statement of operations for the year ended December 31, 2014 and $22.4 million was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2014.
Due to our charter agreements with the purchaser, we expect to have significant continuing involvement and cash flows related to ENSCO 83, ENSCO 89 and ENSCO 98; therefore, the operating results for these rigs were included in income from continuing operations within the Jackup segment for periods prior to the date of sale (September 30, 2014). Operating results for periods beginning after September 30, 2014 were included in income from continuing operations within the Other segment. The proceeds from the sale of these rigs were included in investing activities of continuing operations in our consolidated statement of cash flows for the year ended December 31, 2014.
At the time of sale, we expected to also have significant continuing involvement and cash flows related to ENSCO 93; therefore, the operating results for the rig were included in income from continuing operations within the Jackup segment at September 30, 2014. Based on market developments during the fourth quarter, we now expect that the ENSCO 93 charter agreement will terminate prior to September 30, 2015. As a result, the loss on sale of $1.2 million and ENSCO 93 operating results were reclassified to (loss) income from discontinued operations, net in our consolidated statements of operations for the three-year period December 31, 2014. The proceeds from the sale were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. See "Note 10 - Discontinued Operations" for additional information.
13. SEGMENT INFORMATION
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
Segment information for each of the years in the three-year period ended December 31, 2014 is presented below (in millions). 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 and were included in "Reconciling Items." We measure segment assets as property and equipment. Prior year information has been reclassified to conform to the current year presentation.
Year Ended December 31, 2014
Year Ended December 31, 2013
Year Ended December 31, 2012
Information about Geographic Areas
As of December 31, 2014, our Floaters segment consisted of seven drillships, 13 dynamically positioned semisubmersible rigs and five moored semisubmersible rigs deployed in various locations throughout North and South America, Middle East and Africa, Asia Pacific, Europe and the Mediterranean and Brazil. Additionally, our Floaters segment included three ultra-deepwater drillships under construction in South Korea.
Our Jackups segment consisted of 42 jackup rigs, of which 38 were deployed in various locations throughout North and South America, Middle East and Africa, Asia Pacific and Europe and the Mediterranean and four of which were under construction in Singapore and the United Arab Emirates.
As of December 31, 2014, the geographic distribution of our drilling rigs by operating segment was as follows:
(1)
The five floaters and two jackups classified as "held for sale" as of December 31, 2014 are included in the table above.
(2)
We provide management services on six rigs owned by third-parties not included in the table above.
For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned and assets to the geographic location of the drilling rig as of the end of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined.
Information by country for those countries that account for more than 10% of total revenues or 10% of our long-lived assets was as follows (in millions):
14. SUPPLEMENTAL FINANCIAL INFORMATION
Consolidated Balance Sheet Information
Accounts receivable, net, as of December 31, 2014 and 2013 consisted of the following (in millions):
Other current assets as of December 31, 2014 and 2013 consisted of the following (in millions):
Assets held for sale primarily consists of drilling rigs and equipment. See "Note 3 - Property and Equipment" for additional information on the assets classified as "held for sale" on our balance sheet as of December 31, 2014.
Other assets, net, as of December 31, 2014 and 2013 consisted of the following (in millions):
Accrued liabilities and other as of December 31, 2014 and 2013 consisted of the following (in millions):
Other liabilities as of December 31, 2014 and 2013 consisted of the following (in millions):
Accumulated other comprehensive income as of December 31, 2014 and 2013 consisted of the following (in millions):
Consolidated Statement of Operations Information
Repair and maintenance expense related to continuing operations for each of the years in the three-year period ended December 31, 2014 was as follows (in millions):
Consolidated Statement of Cash Flows Information
Net cash provided by operating activities of continuing operations attributable to the net change in operating assets and liabilities for each of the years in the three-year period ended December 31, 2014 was as follows (in millions):
Cash paid for interest and income taxes for each of the years in the three-year period ended December 31, 2014 was as follows (in millions):
Capitalized interest totaled $78.2 million, $67.7 million and $105.8 million during the years ended December 31, 2014, 2013 and 2012, respectively. Capital expenditure accruals totaling $137.2 million, $111.8 million and $110.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, were excluded from investing activities in our consolidated statements of cash flows.
Amortization of intangibles and other, net, included amortization of intangible assets and liabilities related to the estimated fair values of acquired Company firm drilling contracts in place at the Pride acquisition date, debt premiums related to the fair value adjustment of acquired Company debt instruments, deferred charges for income taxes incurred on intercompany transfers of drilling rigs and certain other deferred costs.
Concentration of Risk
We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and investments and our use of derivatives in connection with the management of foreign currency exchange rate risk. We mitigate our credit risk relating to receivables from customers, which consist primarily of major international, government-owned and independent oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which generally have been within management's expectations. During 2014, we insured certain receivables deemed to have a higher credit risk. We mitigate our credit risk relating to cash and investments by focusing on diversification and quality of instruments. Cash equivalents and short-term investments consist of a portfolio of high-grade instruments. Custody of cash and cash equivalents and short-term investments is maintained at several well-capitalized financial institutions, and we monitor the financial condition of those financial institutions.
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 into ISDA Master Agreements, which include provisions for a legally enforceable master netting
agreement, with almost all 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.
During 2014, BP accounted for $723.9 million, or 16%, of our consolidated revenues, 80% of which were attributable to our Floaters segment.
During 2013, Petrobras accounted for $604.8 million, or 14%, of consolidated revenues, all of which were provided by our Floaters segment, and BP accounted for $444.9 million, or 10%, of consolidated revenues, 84% of which were attributable to our Floaters segment.
During 2012, Petrobras accounted for $771.9 million, or 21%, of our consolidated revenues, all of which were attributable to our Floaters segment.
During 2014, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $1.7 billion, or 38%, of our consolidated revenues, of which 79% were provided by our Floaters segment. Revenues provided by our drilling operations in Angola and Brazil during the year ended December 31, 2014 totaled $607.9 million and $459.1 million, or 13% and 10%, of our consolidated revenues, all of which were provided by our Floaters segment.
During 2013, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $1.7 billion, or 39%, of our consolidated revenues, of which 77% were provided by our Floaters segment. Revenues provided by our drilling operations in Brazil during the year ended December 31, 2013 totaled $683.7 million, or 16%, of our consolidated revenue, all of which were provided by our Floaters segment.
During 2012, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $1.3 billion, or 35%, of our consolidated revenues, of which 75% were provided by our Floaters segment. Revenues provided by our drilling operations in Brazil during the year ended December 31, 2012 totaled $776.3 million, or 21%, of our consolidated revenues, all of which were provided by our Floaters segment.
15. GUARANTEE OF REGISTERED SECURITIES
In connection with the Pride acquisition, Ensco plc and Pride entered into a supplemental indenture to the indenture dated as of July 1, 2004 between Pride and the Bank of New York Mellon, as indenture trustee, providing for, among other matters, the full and unconditional guarantee by Ensco plc of Pride’s 8.5% senior notes due 2019, 6.875% senior notes due 2020 and 7.875% senior notes due 2040, which had an aggregate outstanding principal balance of $1.7 billion as of December 31, 2014. The Ensco plc guarantee provides for the unconditional and irrevocable guarantee of the prompt payment, when due, of any amount owed to the holders of the notes.
Ensco plc is also a full and unconditional guarantor of the 7.2% Debentures due 2027 issued by Ensco Delaware in November 1997, which had an aggregate outstanding principal balance of $150.0 million as of December 31, 2014.
All guarantees are unsecured obligations of Ensco plc ranking equal in right of payment with all of its existing and future unsecured and unsubordinated indebtedness.
The following tables present our condensed consolidating statements of operations for each of the years in the three-year period ended December 31, 2014; our condensed consolidating statements of comprehensive (loss) income for each of the years in the three-year period ended December 31, 2014; our condensed consolidating balance sheets as of December 31, 2014 and 2013; and our condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2014, in accordance with Rule 3-10 of Regulation S-X.
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
Year Ended December 31, 2014
(in millions)
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
Year Ended December 31, 2013
(in millions)
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
Year Ended December 31, 2012
(in millions)
16. UNAUDITED QUARTERLY FINANCIAL DATA
The following tables summarize our unaudited quarterly consolidated income statement data for the years ended December 31, 2014 and 2013 (in millions, except per share amounts):
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A. Controls and Procedures
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has concluded that our disclosure controls and procedures, as defined in Rule 13a-15 under the Securities Exchange Act of 1934, as amended, (the "Exchange Act"), are effective.
During the fiscal quarter ended December 31, 2014, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.
Item 9B.
Item 9B. Other Information
Not applicable.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item with respect to our directors, corporate governance matters, committees of the Board of Directors and Section 16(a) of the Exchange Act is contained in our Proxy Statement for the Annual General Meeting of Shareholders ("Proxy Statement") to be filed with the SEC not later than 120 days after the end of our fiscal year ended December 31, 2014 and incorporated herein by reference.
The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this Annual Report on Form 10-K.
The guidelines and procedures of the Board of Directors are outlined in our Corporate Governance Policy. The committees of the Board of Directors operate under written charters adopted by the Board of Directors. The Corporate Governance Policy and committee charters are available on our website at www.enscoplc.com in the Corporate Governance section and are available in print without charge by contacting our Investor Relations Department at 713-430-4607.
We have a Code of Business Conduct Policy that applies to all employees, including our principal executive officer, principal financial officer and controller. The Code of Business Conduct Policy is available on our website at www.enscoplc.com in the Corporate Governance section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Business Conduct Policy by posting such information on our website. Our Proxy Statement contains governance disclosures, including information on our Code of Business Conduct Policy, the Ensco Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the Board of Directors and director attendance at the Annual General Meeting of Shareholders.
Item 11.
Item 11. Executive Compensation
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The following table summarizes certain information related to our compensation plans under which our shares are authorized for issuance as of December 31, 2014:
Additional information required by this item is included in our Proxy Statement and incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a)
The following documents are filed as part of this report:
1. Financial Statements
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
The schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable or provided elsewhere in the financial statements and, therefore, have been omitted.
Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.
PART IV
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on March 2, 2015.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
INDEX TO EXHIBITS
Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.