Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited consolidated financial statements as of
June 30, 2018
and for the
three-month and six-month
periods ended
June 30, 2018
and
2017
included elsewhere herein and with our annual report on Form 10-K for the year ended
December 31, 2017
. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our annual report and elsewhere in this quarterly report. See “Forward-Looking Statements.”
EXECUTIVE SUMMARY
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
58
rigs, with drilling operations in most of the strategic markets around the globe. We also have
three
rigs under construction. Our rig fleet includes
12
drillships,
nine
dynamically positioned semisubmersible rigs,
four
moored semisubmersible rigs and
36
jackup rigs, including rigs under construction. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.
Our Industry
Oil prices increased significantly during the second half of 2017 and into the first half of 2018, with prices remaining above $70 per barrel for most of the second quarter. While commodity prices have improved, we expect near-term market conditions to remain challenging and the recovery in demand for contract drilling services to be gradual with different segments of the market recovering more quickly than others. In addition to a sustained increase in commodity prices, we believe further improvements in demand coupled with a reduction in rig supply are necessary to generate meaningful increases in day rates.
While industry conditions remain challenging, we have observed improvements in the shallow-water market as higher levels of customer demand and rig retirements have led to gradually increasing jackup utilization over the past year. Moreover, new floater contracts and open tenders have increased as compared to a year ago due to higher commodity prices and improved break-even economics for deepwater projects. Despite the increase in customer activity, recent contract awards have been subject to an extremely competitive bidding process. The intense pressure on operating day rates in recent periods has resulted in low margin contracts. Therefore, we expect our results from operations to continue to decline in 2018 as current contracts with above market rates expire and new contracts are executed at lower rates.
Liquidity Position
We have historically relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We periodically rely on the issuance of debt and/or equity securities to supplement our liquidity needs. Based on our balance sheet, our contractual backlog and
$2.0 billion
available under our Credit Facility, we expect to fund our short-term and long-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from cash and cash equivalents, short-term investments, operating cash flows and, if necessary, funds borrowed under our Credit Facility or other future financing arrangements. We remain focused on our liquidity and over the past several years have executed a number of transactions to significantly improve our financial position and manage our debt maturities.
Cash and Debt
As of
June 30, 2018
, we had
$5.0 billion
in total debt outstanding, representing approximately
37.2%
of our total capitalization. We also had
$740.5 million
in cash and cash equivalents and short-term investments and
$2.0 billion
of undrawn capacity under our Credit Facility.
In January 2018, we issued
$1.0 billion
aggregate principal amount of unsecured
7.75%
senior notes due 2026. Net proceeds of
$983.5 million
from the 2026 Notes were partially used to fund the repurchase and redemption of
$237.6 million
principal amount of our
8.50%
senior notes due 2019,
$328.0 million
principal amount of our
6.875%
senior notes due 2020 and
$156.2 million
principal amount of our
4.70%
senior notes due 2021. During the first quarter, we recognized a pre-tax loss from debt extinguishment of
$19.0 million
, net of discounts, premiums, debt issuance costs and commissions.
Following the debt offering, repurchases and redemption, our only debt maturities until 2024 are
$122.9 million
during 2020 and
$113.5 million
during 2021.
Backlog
As of
June 30, 2018
, our backlog was
$2.3 billion
as compared to
$2.8 billion
as of
December 31, 2017
. Our backlog declined primarily due to revenues realized during the year, partially offset by new contract awards and contract extensions. As current contracts expire, we will likely experience further declines in backlog, which will result in a decline in revenues and operating cash flows over the near-term. Contract backlog was adjusted for drilling contracts signed or terminated after each respective balance sheet date but prior to filing our annual and quarterly reports on
February 27, 2018
and
July 26, 2018
, respectively.
In July 2018, we executed a contract amendment for ENSCO DS-8, which primarily modified the scheduled cost escalations, bonus scheme and priced option, but did not change the day rate or primary term of the firm contracted period. Our operating results will not be significantly impacted as a result of the amendment.
BUSINESS ENVIRONMENT
Floaters
The floater contracting environment continues to be challenged due to reduced demand, as well as excess newbuild supply. Floater demand has declined significantly in recent years due to lower commodity prices which have caused our customers to reduce capital expenditures, resulting in the cancellation and delay of drilling programs. During the past several quarters, we have observed increased activity that is translating into marginal improvements in near-term utilization; however, further improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized.
During the first quarter, we extended the contract for ENSCO 8503 by two wells and executed one-well and two-well contracts for ENSCO 8505.
In April 2018, our customer terminated the contract for ENSCO 8504 due to force majure.
During the second quarter, we executed a 100-day contract for ENSCO 8503 that contains two one-well priced options. The contract is expected to commence in November 2018 in the U.S. Gulf of Mexico. We also extended the contract for ENSCO DS-12 for approximately 45 days.
During the first quarter, we began marketing the ENSCO 5005 for sale and classified this rig as held-for-sale as of March 31, 2018. In April 2018, we sold ENSCO 7500 for scrap and recognized an insignificant pre-tax gain within loss from discontinued operations, net, in our condensed consolidated statement of operations. During the second
quarter, we began marketing for sale ENSCO 6001 and classified this rig as held-for-sale as of
June 30, 2018
. The rig was sold for scrap in July 2018, resulting in an insignificant pre-tax loss that will be recognized during the third quarter.
There are approximately
42
newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately
eight
are scheduled to be delivered by the end of 2018. Nearly all newbuild floaters are uncontracted. Several newbuild deliveries have already been delayed into future years, and we expect that more uncontracted newbuilds will be delayed or cancelled.
Drilling contractors have retired approximately
111
floaters since the beginning of the downturn. Approximately
24
floaters older than 30 years of age are currently idle, approximately
16
additional floaters older than 30 years have contracts that will expire by year-end 2018 without follow-on work and a further
12
floaters between 15 and 30 years old have been idle for more than two years. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify these aging rigs may prove cost prohibitive. Drilling contractors will likely elect to scrap or cold-stack some or all of these rigs.
Jackups
Demand for jackups has improved with increased tendering activity observed in the past several quarters off historic lows; however, day rates remain depressed due to the oversupply of rigs.
During the first quarter, we executed a seven-well contract for ENSCO 72, a three-well extension and a one-well contract for ENSCO 101 and a one-well extension for ENSCO 121. We also executed two short-term contracts for ENSCO 68.
In April 2018, we executed three-year contracts with Saudi Aramco for ENSCO 140, ENSCO 141 and ENSCO 108 for drilling operations offshore Saudi Arabia. ENSCO 140 commenced drilling operations during July 2018, and we expect ENSCO 141 and ENSCO 108 to commence drilling operations during the third and fourth quarters of 2018, respectively.
Additionally, during the second quarter, we executed a ten-month contract for ENSCO 115 and short-term contracts and extensions for ENSCO 75, ENSCO 87, ENSCO 121 and ENSCO 122. The ENSCO 115 contact is expected to commence during the first quarter of 2019.
During the second quarter, we sold ENSCO 81 and ENSCO 82 and recognized an insignificant pre-tax gain in our condensed consolidated statement of operations for the quarter ended June 30, 2018. Additionally, we began marketing ENSCO 80 and classified this rig as held-for-sale as of
June 30, 2018
.
There are approximately
91
newbuild jackup rigs reported to be under construction, of which approximately
49
are scheduled to be delivered by the end of 2018. All newbuild jackups are uncontracted. Over the past year, some jackup orders have been cancelled, and many newbuild jackups have been delayed. We expect that additional rigs may be delayed or cancelled given limited contracting opportunities.
Drilling contractors have retired approximately
66
jackups since the beginning of the downturn. Approximately
108
jackups older than 30 years are idle and approximately
59
jackups that are 30 years or older have contracts expiring by the end of 2018 without follow-on work. Expenditures required to re-certify these aging rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold-stack these rigs. We expect jackup scrapping and cold-stacking to continue during 2018 and into 2019.
Divestitures
Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and deemphasize other assets and operations that are not part of our long-term strategic plan or that no longer meet our standards for economic returns. Consistent with this strategy, we recently scrapped two floaters and two jackup rigs. Additionally, we are currently marketing for sale ENSCO 80 and ENSCO 5005, both of which are older, less capable assets, as part of our fleet high-grading strategy.
Following the Merger, we continue to focus on our fleet management strategy in light of the new composition of our rig fleet. As part of this strategy, we may act opportunistically from time to time to monetize assets to enhance shareholder value and improve our liquidity profile, in addition to selling or disposing of older, lower-specification or non-core rigs.
RESULTS OF OPERATIONS
The following table summarizes our condensed consolidated results of operations for the
three-month and six-month
periods ended
June 30, 2018
and
2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Revenues
|
$
|
458.5
|
|
|
$
|
457.5
|
|
|
$
|
875.5
|
|
|
$
|
928.6
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling (exclusive of depreciation)
|
344.3
|
|
|
291.3
|
|
|
669.5
|
|
|
569.4
|
|
Depreciation
|
120.7
|
|
|
107.9
|
|
|
235.9
|
|
|
217.1
|
|
General and administrative
|
26.1
|
|
|
30.5
|
|
|
54.0
|
|
|
56.5
|
|
Operating income (loss)
|
(32.6
|
)
|
|
27.8
|
|
|
(83.9
|
)
|
|
85.6
|
|
Other expense, net
|
(84.8
|
)
|
|
(53.2
|
)
|
|
(155.5
|
)
|
|
(110.9
|
)
|
Provision for income taxes
|
24.7
|
|
|
19.3
|
|
|
43.1
|
|
|
43.4
|
|
Loss from continuing operations
|
(142.1
|
)
|
|
(44.7
|
)
|
|
(282.5
|
)
|
|
(68.7
|
)
|
Income (loss) from discontinued operations, net
|
(8.0
|
)
|
|
.4
|
|
|
(8.1
|
)
|
|
(.2
|
)
|
Net loss
|
(150.1
|
)
|
|
(44.3
|
)
|
|
(290.6
|
)
|
|
(68.9
|
)
|
Net income attributable to noncontrolling interests
|
(.9
|
)
|
|
(1.2
|
)
|
|
(.5
|
)
|
|
(2.3
|
)
|
Net loss attributable to Ensco
|
$
|
(151.0
|
)
|
|
$
|
(45.5
|
)
|
|
$
|
(291.1
|
)
|
|
$
|
(71.2
|
)
|
Revenues increased
$1.0 million
for the
three-month
period ended
June 30, 2018
, as compared to the prior year quarter, primarily due to the addition of Atwood rigs to the fleet and the commencement of ENSCO DS-10 drilling operations during the first quarter of 2018, offset by lower average day rates across the fleet. For the six-month period ended
June 30, 2018
, revenues declined
$53.1 million
, or
6%
, as compared to the prior year period, primarily due to lower average day rates across the fleet which more than offset the increase from the addition of Atwood rigs and the commencement of ENSCO DS-10 drilling operations during the first quarter of 2018.
Contract drilling expense increased
$53.0 million
, or
18%
, and
$100.1 million
, or
18%
, for the
three-month
and
six-month
periods ended
June 30, 2018
, as compared to the prior periods, primarily due to the addition of Atwood rigs to the fleet, the commencement of ENSCO DS-10 drilling operations during the first quarter of 2018 and integration-related costs.
Depreciation expense increased
$12.8 million
, or
12%
, and
$18.8 million
, or
9%
, respectively, for the
three-month
and six-month periods ended
June 30, 2018
, as compared to the prior periods, primarily due to the addition of Atwood rigs to the fleet and the commencement of ENSCO DS-10 drilling operations. This increase was partially offset by lower depreciation expense on two non-core floaters and one non-core jackup that were impaired to scrap during the fourth quarter of 2017.
General and administrative expenses declined by
$4.4 million
, or
14%
, and
$2.5 million
, or
4%
, for the
three-month and six-month
periods ended
June 30, 2018
, respectively, primarily due to lower Merger-related costs and accrued performance-based compensation.
Other expense, net, increased
$31.6 million
for the three-month period ended
June 30, 2018
, as compared to the prior year quarter, primarily due to higher debt balances and average interest rates resulting from the debt transactions we undertook during the first quarter of 2018, lower capitalized interest due to the decline in the amount of capital invested in newbuild construction and foreign currency losses. In addition, other expense, net, for the current period included measurement period adjustments related to the Merger resulting in a reduction to the bargain purchase gain.
Other expense, net, increased
$44.6 million
for the six-month period ended
June 30, 2018
, as compared to the prior year period, primarily due to higher interest expense resulting from the debt transactions we undertook during the first quarter of 2018, the pre-tax loss on debt extinguishment associated with those transactions, foreign currency losses and lower interest income. These declines were partially offset by measurement period adjustments related to the Merger resulting in additional bargain purchase gain.
Income (loss) from discontinued operations, net, included a
$7.5 million
discrete tax expense related to the sale of ENSCO 7500 in April 2018.
Rig Counts, Utilization and Average Day Rates
The following table summarizes our offshore drilling rigs by reportable segment, rigs under construction and rigs held-for-sale as of
June 30, 2018
and
2017
:
|
|
|
|
|
|
2018
|
|
2017
|
Floaters
(1)(2)(3)
|
22
|
|
19
|
Jackups
(3)(4)
|
34
|
|
32
|
Under construction
(1)(5)
|
3
|
|
2
|
Held-for-sale
(3)(6)
|
3
|
|
2
|
Total
|
62
|
|
55
|
|
|
(1)
|
During the third quarter of 2017, we accepted delivery of ENSCO DS-10.
|
|
|
(2)
|
During the fourth quarter of 2017, we added ENSCO DS-11, ENSCO DS-12, ENSCO DPS-1 and ENSCO MS-1 from the Merger.
|
|
|
(3)
|
During the first quarter of 2018, we classified ENSCO 5005, ENSCO 81 and ENSCO 82 as held-for-sale. During the second quarter of 2018, we classified ENSCO 6001 and ENSCO 80 as held-for-sale.
|
|
|
(4)
|
During the fourth quarter of 2017, we added ENSCO 111, ENSCO 112, ENSCO 113, ENSCO 114 and ENSCO 115 from the Merger.
|
|
|
(5)
|
During the fourth quarter of 2017, we added ENSCO DS-13 and ENSCO DS-14 from the Merger, both of which are under construction.
|
|
|
(6)
|
During the third quarter of 2017, we sold ENSCO 52. During the second quarter of 2018, we sold ENSCO 7500, ENSCO 81 and ENSCO 82.
|
The following table summarizes our rig utilization and average day rates by reportable segment for the
three-month and six-month
periods ended
June 30, 2018
and
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Rig Utilization
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Floaters
|
53
|
%
|
|
43
|
%
|
|
48
|
%
|
|
45
|
%
|
Jackups
|
66
|
%
|
|
64
|
%
|
|
63
|
%
|
|
64
|
%
|
Total
|
61
|
%
|
|
56
|
%
|
|
57
|
%
|
|
57
|
%
|
Average Day Rates
(2)
|
|
|
|
|
|
|
|
|
|
Floaters
|
$
|
237,513
|
|
|
$
|
338,675
|
|
|
$
|
248,576
|
|
|
$
|
337,611
|
|
Jackups
|
78,408
|
|
|
88,583
|
|
|
76,011
|
|
|
87,468
|
|
Total
|
$
|
135,343
|
|
|
$
|
155,946
|
|
|
$
|
133,988
|
|
|
$
|
156,200
|
|
|
|
(1)
|
Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned and recognized day rate revenue, including days associated with early contract terminations, compensated downtime and mobilizations. When revenue is 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.
|
Operating Income
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which currently consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
Segment information 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."
Three Months Ended
June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters
|
|
Jackups
|
|
Other
|
|
Operating Segments Total
|
|
Reconciling Items
|
|
Consolidated Total
|
Revenues
|
$
|
284.9
|
|
|
$
|
158.7
|
|
|
$
|
14.9
|
|
|
$
|
458.5
|
|
|
$
|
—
|
|
|
$
|
458.5
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling (exclusive of depreciation)
|
203.7
|
|
|
126.8
|
|
|
13.8
|
|
|
344.3
|
|
|
—
|
|
|
344.3
|
|
Depreciation
|
80.8
|
|
|
36.5
|
|
|
—
|
|
|
117.3
|
|
|
3.4
|
|
|
120.7
|
|
General and administrative
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.1
|
|
|
26.1
|
|
Operating income (loss)
|
$
|
0.4
|
|
|
$
|
(4.6
|
)
|
|
$
|
1.1
|
|
|
$
|
(3.1
|
)
|
|
$
|
(29.5
|
)
|
|
$
|
(32.6
|
)
|
Three Months Ended
June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters
|
|
Jackups
|
|
Other
|
|
Operating Segments Total
|
|
Reconciling Items
|
|
Consolidated Total
|
Revenues
|
$
|
264.0
|
|
|
$
|
178.9
|
|
|
$
|
14.6
|
|
|
$
|
457.5
|
|
|
$
|
—
|
|
|
$
|
457.5
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling (exclusive of depreciation)
|
145.6
|
|
|
132.3
|
|
|
13.4
|
|
|
291.3
|
|
|
—
|
|
|
291.3
|
|
Depreciation
|
72.0
|
|
|
31.6
|
|
|
—
|
|
|
103.6
|
|
|
4.3
|
|
|
107.9
|
|
General and administrative
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.5
|
|
|
30.5
|
|
Operating income
|
$
|
46.4
|
|
|
$
|
15.0
|
|
|
$
|
1.2
|
|
|
$
|
62.6
|
|
|
$
|
(34.8
|
)
|
|
$
|
27.8
|
|
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters
|
|
Jackups
|
|
Other
|
|
Operating Segments Total
|
|
Reconciling Items
|
|
Consolidated Total
|
Revenues
|
$
|
543.9
|
|
|
$
|
302.1
|
|
|
$
|
29.5
|
|
|
$
|
875.5
|
|
|
$
|
—
|
|
|
$
|
875.5
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling (exclusive of depreciation)
|
388.8
|
|
|
253.7
|
|
|
27.0
|
|
|
669.5
|
|
|
—
|
|
|
669.5
|
|
Depreciation
|
156.1
|
|
|
73.0
|
|
|
—
|
|
|
229.1
|
|
|
6.8
|
|
|
235.9
|
|
General and administrative
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54.0
|
|
|
54.0
|
|
Operating income (loss)
|
$
|
(1.0
|
)
|
|
$
|
(24.6
|
)
|
|
$
|
2.5
|
|
|
$
|
(23.1
|
)
|
|
$
|
(60.8
|
)
|
|
$
|
(83.9
|
)
|
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters
|
|
Jackups
|
|
Other
|
|
Operating Segments Total
|
|
Reconciling Items
|
|
Consolidated Total
|
Revenues
|
$
|
548.8
|
|
|
$
|
350.7
|
|
|
$
|
29.1
|
|
|
$
|
928.6
|
|
|
$
|
—
|
|
|
$
|
928.6
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling (exclusive of depreciation)
|
292.0
|
|
|
250.9
|
|
|
26.5
|
|
|
569.4
|
|
|
—
|
|
|
569.4
|
|
Depreciation
|
144.8
|
|
|
63.7
|
|
|
—
|
|
|
208.5
|
|
|
8.6
|
|
|
217.1
|
|
General and administrative
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56.5
|
|
|
56.5
|
|
Operating income
|
$
|
112.0
|
|
|
$
|
36.1
|
|
|
$
|
2.6
|
|
|
$
|
150.7
|
|
|
$
|
(65.1
|
)
|
|
$
|
85.6
|
|
Floaters
Floater revenue increased
$20.9 million
, or
8%
, for the
three-month
period ended
June 30, 2018
, as compared to the prior year quarter, primarily due to the addition of Atwood rigs to the fleet and the commencement of ENSCO DS-10 drilling operations during the first quarter of 2018. This increase was partially offset by lower average day rates across the fleet. For the six-month period ended
June 30, 2018
, floater revenues declined
$4.9 million
, or
1%
, as compared to the prior year period, as lower average day rates across the fleet more than offset the addition of the Atwood rigs and the commencement of ENSCO DS-10 drilling operations.
Floater contract drilling expense increased
$58.1 million
, or
40%
, and
$96.8 million
, or
33%
, for the
three-month
and
six-month
periods ended
June 30, 2018
, respectively, as compared to the prior year periods, primarily due to the addition of Atwood rigs to the fleet and the commencement of ENSCO DS-10 drilling operations during the first quarter of 2018. The increase was partially offset by costs incurred in the prior year to settle a previously disclosed legal contingency and lower contract preparation costs in the current period.
Floater depreciation expense increased
$8.8 million
, or
12%
, and
11.3 million
, or
8%
, for the
three-month
and six-month periods ended
June 30, 2018
, as compared to the prior year periods, primarily due to the addition of Atwood rigs and the commencement of depreciation on the ENSCO DS-10, partially offset by lower depreciation expense on two non-core floaters that were impaired to scrap during the fourth quarter of 2017.
Jackups
Jackup revenues declined
$20.2 million
, or
11%
, and
$48.6 million
, or
14%
, for the
three-month and six-month
periods ended
June 30, 2018
, respectively, primarily due to lower average day rates, the sale of the ENSCO 52 and ENSCO 104 termination payments recognized during the prior year period. These declines were partially offset by the addition of Atwood rigs to the fleet.
Jackup contract drilling expense declined
$5.5 million
, or
4%
, for the
three-month
period ended
June 30, 2018
, as compared to the prior year quarter, primarily due to rigs that were undergoing shipyard projects during the prior period, the sale of ENSCO 52 and lower stacking costs on idle rigs, partially offset by the addition of Atwood rigs to the fleet.
Jackup contract drilling expense increased
$2.8 million
, or
1%
, for the
six-month
period ended
June 30, 2018
, as compared to the prior year period, primarily due to the addition of Atwood rigs to the fleet and higher stacking costs, partially offset by the sale of ENSCO 52 and lower contract preparation costs in the current period.
Jackup depreciation expense for the
three-month
and
six-month
period ended
June 30, 2018
increased
$4.9 million
, or
16%
, and
$9.3 million
, or
15%
, respectively, as compared to the prior year periods, primarily due to the addition of Atwood rigs to the fleet.
Other Income (Expense)
The following table summarizes other income (expense) for the
three-month and six-month
periods ended
June 30, 2018
and
2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Interest income
|
$
|
3.9
|
|
|
$
|
7.6
|
|
|
$
|
6.9
|
|
|
$
|
14.8
|
|
Interest expense, net:
|
|
|
|
|
|
|
|
|
|
Interest expense
|
(86.9
|
)
|
|
(73.9
|
)
|
|
(170.9
|
)
|
|
(149.3
|
)
|
Capitalized interest
|
11.2
|
|
|
13.6
|
|
|
29.6
|
|
|
30.4
|
|
|
(75.7
|
)
|
|
(60.3
|
)
|
|
(141.3
|
)
|
|
(118.9
|
)
|
Other, net
|
(13.0
|
)
|
|
(.5
|
)
|
|
(21.1
|
)
|
|
(6.8
|
)
|
|
$
|
(84.8
|
)
|
|
$
|
(53.2
|
)
|
|
$
|
(155.5
|
)
|
|
$
|
(110.9
|
)
|
Interest income for the
three-month
and
six-month
periods ended
June 30, 2018
declined as compared to the prior year periods as a result of lower average short-term investment balances.
Interest expense for the
three-month
and
six-month
periods ended
June 30, 2018
increased as compared to the prior year periods due to the higher debt balance and average interest rates resulting from the debt transactions we undertook during January 2018. Interest expense capitalized during the
three-month
and
six-month
periods ended
June 30, 2018
declined as compared to the prior year periods due to a decline in the amount of capital invested in newbuild construction, resulting from the commencement of drilling operations on ENSCO DS-10.
Other expense, net, for the
three-month
period ended
June 30, 2018
included foreign currency losses as discussed below and measurement period adjustments related to the Merger resulting in an
$8.3 million
decline in bargain purchase gain
.
Other expense, net, for the
six-month
period ended
June 30, 2018
included a pre-tax loss of
$19.0 million
related to the repurchase and redemption of senior notes in the first quarter of 2018 and foreign currency losses as discussed below. These losses were partially offset by measurement period adjustments related to the Merger resulting in
$8.3 million
of additional bargain purchase gain.
Other expense, net, for the
six-month
period ended
June 30, 2017
included a pre-tax loss of
$6.2 million
related to the January 2017 debt exchange.
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. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Net foreign currency exchange
losses
of
$5.7 million
and
$12.0 million
, inclusive of offsetting fair value derivatives, were included in other, net, for the
three-month
and
six-month
periods ended
June 30, 2018
, respectively. These losses were primarily attributable to a strengthening U.S. dollar and the devaluation of the Angolan kwanza. Net foreign currency exchange
losses
of
$2.4 million
and
$4.1 million
, inclusive of offsetting fair value derivatives, were included in other, net, for the
three-month and six-month
periods ended
June 30, 2017
, respectively.
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 generally not subject to U.K. taxation. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income.
Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of our 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. In periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Further, we may continue to incur income tax expense in periods in which we operate at a loss.
Discrete income tax benefit for the three-month period ended
June 30, 2018
was
$2.3 million
and was primarily attributable to U.S. tax reform, partially offset by discrete tax expense related to rig sales and unrecognized tax benefits associated with tax positions taken in prior years. Discrete income tax expense for the three-month period ended
June 30, 2017
was
$2.2 million
and was primarily attributable to the debt exchange and repurchases we undertook during the first quarter of 2017 and a settlement of a previously disclosed legal contingency. Excluding the aforementioned discrete tax items, income tax expense for the three-month periods ended
June 30, 2018
and 2017 was
$27.0 million
and
$17.1 million
, respectively. The
$9.9 million
increase in income tax expense as compared to the prior year period was primarily due to U.S. tax reform and an increase in the relative components of our earnings, excluding discrete items, generated in tax jurisdictions with higher tax rates, partially offset by overall lower income levels.
Discrete income tax benefit for the six-month period ended
June 30, 2018
was
$11.2 million
and was primarily attributable to U.S. tax reform and a restructuring transaction, partially offset by discrete tax expense related to repurchase and redemption of senior notes, the effective settlement of liabilities for unrecognized tax benefits associated with tax positions taken in prior years and rig sales. Discrete income tax expense for the six-month period ended
June 30, 2017
was
$9.8 million
and was primarily attributable to the debt exchange and repurchases we undertook during the first quarter of 2017, a restructuring transaction, the effective settlement of a liability for unrecognized tax benefits associated with a tax position taken in prior years and a settlement of a previously disclosed legal contingency. Excluding the aforementioned discrete tax items, income tax expense for the six-month periods ended
June 30, 2018
and
2017
was
$54.3 million
and
$33.6 million
, respectively. The
$20.7 million
increase in income tax expense as compared to the prior year period was primarily due to U.S. tax reform and an increase in the relative components of our earnings, excluding discrete items, generated in tax jurisdictions with higher tax rates, partially offset by overall lower income levels.
LIQUIDITY AND CAPITAL RESOURCES
We have historically relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We periodically rely on the issuance of debt and/or equity securities to supplement our liquidity needs. A substantial portion of our cash has been invested in the expansion and enhancement of our fleet of drilling rigs through newbuild construction, acquisitions and upgrade projects. We expect that cash flow generated from operations during 2018 will primarily be used to fund capital expenditures and repurchase debt.
Based on our balance sheet, our contractual backlog and
$2.0 billion
available under our Credit Facility, we expect to fund our short-term and long-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from cash and cash equivalents, short-term investments,
operating cash flows and, if necessary, funds borrowed under our Credit Facility or other future financing arrangements. We remain focused on our liquidity and over the past several years have executed a number of transactions to significantly improve our financial position and manage our debt maturities.
In January 2018, we issued
$1.0 billion
aggregate principal amount of unsecured
7.75%
senior notes due 2026. Net proceeds of
$983.5 million
from the 2026 Notes were partially used to fund the repurchase and redemption of
$237.6 million
principal amount of our
8.50%
senior notes due 2019, $328.0 million principal amount of our
6.875%
senior notes due 2020 and
$156.2 million
principal amount of our
4.70%
senior notes due 2021.
Our Board of Directors declared a $0.01 quarterly cash dividend during the second quarter. Our Credit Facility prohibits us from paying dividends in excess of $0.01 per share per fiscal quarter. Dividends in excess of this amount would require the amendment or waiver of such provisions. The declaration and amount of future dividends is at the discretion of our Board of Directors. In the future, our Board of Directors may, without advance notice, determine to suspend our dividend in order to maintain our financial flexibility and best position us for long-term success.
During the
six-month
period ended
June 30, 2018
, our primary source of cash was
$1.0 billion
in proceeds from the issuance of senior notes and
$185.0 million
in net maturities of short-term investments. Our primary uses of cash for the same period were
$771.2 million
for the repurchase and redemption of outstanding debt and
$331.9 million
for the construction, enhancement and other improvements of our drilling rigs.
During the
six-month
period ended
June 30, 2017
, our primary source of cash was
$130.5 million
generated from operating activities of continuing operations. Our primary uses of cash for the same period were
$537.0 million
for debt repurchases,
$332.6 million
for the construction, enhancement and other improvements of our drilling rigs and net purchases of short-term investments of
$237.8 million
.
Cash Flow and Capital Expenditures
Our cash flow from operating activities of continuing operations and capital expenditures for the
six-month
periods ended
June 30, 2018
and
2017
were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
Cash provided by (used in) operating activities of continuing operations
|
$
|
(18.0
|
)
|
|
$
|
130.5
|
|
Capital expenditures
|
|
|
|
|
|
New rig construction
|
$
|
277.7
|
|
|
$
|
286.6
|
|
Rig enhancements
|
26.5
|
|
|
15.5
|
|
Minor upgrades and improvements
|
27.7
|
|
|
30.5
|
|
|
$
|
331.9
|
|
|
$
|
332.6
|
|
Cash flows from operating activities of continuing operations declined
$148.5 million
as compared to the prior year period due primarily to declining margins. As challenging industry conditions persist and our remaining above-market, older contracts expire and utilization increases with the execution of new market-rate contracts, our operating cash flows are expected to continue to decline over the near-term.
We currently have one premium jackup rig under construction, ENSCO 123. In January 2018, we made a milestone payment of
$207.4 million
which was invoiced and included in accounts payable - trade as of December 31, 2017 on our condensed consolidated balance sheet. We have two ultra-deepwater drillships under construction, ENSCO DS-13 and ENSCO DS-14, which are scheduled for delivery in September 2019 and June 2020, respectively, or such earlier date that we elect to take delivery with 45 days' notice. In June 2018, we paid an interim milestone payment of
$15.0 million
on ENSCO DS-14.
The following table summarizes the cumulative amount of contractual payments made as of
June 30, 2018
for our rigs under construction and estimated timing of our remaining contractual payments (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative Paid
(1)
|
|
Remaining 2018
|
|
2019
|
|
2020
|
|
Total
(2)
|
ENSCO 123
|
|
$
|
275.8
|
|
|
$
|
2.0
|
|
|
$
|
7.6
|
|
|
$
|
—
|
|
|
$
|
285.4
|
|
ENSCO DS-13
(3)
|
|
—
|
|
|
—
|
|
|
83.9
|
|
|
—
|
|
|
83.9
|
|
ENSCO DS-14
(3)
|
|
15.0
|
|
|
—
|
|
|
—
|
|
|
165.0
|
|
|
180.0
|
|
|
|
$
|
290.8
|
|
|
$
|
2.0
|
|
|
$
|
91.5
|
|
|
$
|
165.0
|
|
|
$
|
549.3
|
|
|
|
(1)
|
Cumulative paid represents the aggregate amount of contractual payments made from commencement of the construction agreement through
June 30, 2018
. Contractual payments made by Atwood prior to the Merger for ENSCO DS-13 and ENSCO DS-14 are excluded.
|
|
|
(2)
|
Total commitments are based on fixed-price shipyard construction contracts, exclusive of costs associated with commissioning, systems integration testing, project management, holding costs and interest.
|
|
|
(3)
|
The remaining milestone payments for ENSCO DS-13 and ENSCO DS-14 bear interest at a rate of
4.5%
per annum, which accrues during the holding period until delivery. Delivery is scheduled for September 2019 and June 2020 for ENSCO DS-13 and ENSCO DS-14, respectively. Upon delivery, the remaining milestone payments and accrued interest thereon may be financed through a promissory note with the shipyard for each rig. The promissory notes will bear interest at a rate of
5%
per annum with a maturity date of December 30, 2022 and will be secured by a mortgage on each respective rig. The remaining milestone payments for ENSCO DS-13 and ENSCO DS-14 are included in the table above in the period in which we expect to take delivery of the rig. However, we may elect to execute the promissory notes and defer payment until December 2022.
|
The actual timing of these expenditures may vary based on the completion of various construction milestones, which are, to a large extent, beyond our control.
Based on our current projections, we expect capital expenditures during 2018 to include approximately
$360.0 million
for newbuild construction, approximately
$55.0 million
for rig enhancement projects and approximately
$60.0 million
for minor upgrades and improvements. Depending on market conditions and future opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.
Financing and Capital Resources
Senior Notes
On January 26, 2018, we issued
$1.0 billion
aggregate principal amount of unsecured 7.75% senior notes due 2026 at par. Interest on the 2026 Notes is payable semiannually on February 1 and August 1 of each year commencing August 1, 2018.
Tender Offers and Redemption
Concurrent with the issuance of the 2026 Notes in January 2018, we launched cash tender offers for up to
$985.0 million
aggregate principal amount on certain series of our senior notes issued by us and Pride, our wholly-owned subsidiary. The tender offers expired February 7, 2018, and we repurchased
$182.6 million
of our
8.50%
senior notes due 2019,
$256.6 million
of our
6.875%
senior notes due 2020 and
$156.2 million
of our
4.70%
senior notes due 2021. Subsequently, we issued a redemption notice for the remaining outstanding
$55.0 million
principal amount of the
8.50%
senior notes due 2019 and repurchased
$71.4 million
principal amount of our senior notes due 2020.
The following table sets forth the total principal amounts repurchased as a result of the tender offers, redemption and repurchase (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Principal Amount Repurchased
|
|
Aggregate Repurchase Price
(1)
|
8.50% Senior notes due 2019
|
|
$
|
237.6
|
|
|
$
|
256.8
|
|
6.875% Senior notes due 2020
|
|
328.0
|
|
|
354.7
|
|
4.70% Senior notes due 2021
|
|
156.2
|
|
|
159.7
|
|
Total
|
|
$
|
721.8
|
|
|
$
|
771.2
|
|
|
|
(1)
|
Excludes accrued interest paid to holders of the repurchased senior notes.
|
During the first quarter of 2018, we recognized a pre-tax loss from debt extinguishment of
$19.0 million
, net of discounts, premiums, debt issuance costs and commissions.
Maturities
Following the January 2018 debt offering, repurchases and redemption, our only debt maturities until 2024 are
$122.9 million
during 2020 and
$113.5 million
during 2021.
Debt to Capital
Our total debt, total capital and total debt to total capital ratios are summarized below (in millions, except percentages):
|
|
|
|
|
|
|
|
|
|
June 30,
2018
|
|
December 31,
2017
|
Total debt
|
$
|
4,994.9
|
|
|
$
|
4,750.7
|
|
Total capital
(1)
|
$
|
13,431.1
|
|
|
$
|
13,482.8
|
|
Total debt to total capital
|
37.2
|
%
|
|
35.2
|
%
|
(1)
Total capital consists of total debt and Ensco shareholders' equity.
Revolving Credit Facility
We have a
$2.0 billion
senior unsecured revolving credit facility with a syndicate of banks to be used for general corporate purposes. Our borrowing capacity is
$2.0 billion
through September 2019 and declines to
$1.3 billion
through September 2020 and to
$1.2 billion
through September 2022. The credit agreement governing the Credit Facility includes an accordion feature allowing us to increase the commitments expiring in September 2022 up to an aggregate amount not to exceed
$1.5 billion
.
Advances under the Credit Facility bear interest at Base Rate or LIBOR plus an applicable margin rate, depending on our credit ratings. We are required to pay a quarterly commitment fee on the undrawn portion of the
$2.0 billion
commitment, which is also based on our credit rating.
In January 2018, Moody's downgraded our senior unsecured bond credit rating from B2 to B3. The rating actions resulted in an increase to the interest rates applicable to our borrowings and the quarterly commitment fee on the undrawn portion of the
$2.0 billion
commitment. The applicable margin rates are
3.00%
per annum for Base Rate advances and
4.00%
per annum for LIBOR advances. The quarterly commitment fee is
0.75%
per annum on the undrawn portion of the
$2.0 billion
commitment.
The Credit Facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to
60%
and to provide guarantees from certain of our rig-owning subsidiaries sufficient to meet certain guarantee coverage ratios. The Credit Facility also contains customary restrictive covenants, including, among others, prohibitions on creating, incurring or assuming certain debt and liens (subject to customary exceptions, including a permitted lien basket that permits us to raise secured debt up to the lesser of
$750 million
or
10%
of consolidated tangible net worth (as defined in the Credit Facility)); entering into certain merger arrangements; selling, leasing, transferring or otherwise disposing of all or substantially all of our assets; making a material change in the nature of the business; paying or distributing dividends on our ordinary shares (subject to certain exceptions, including the ability to continue paying a quarterly dividend of
$0.01
per share); borrowings, if after giving effect to such borrowings and the application of the proceeds thereof, the aggregate amount of available cash (as defined in the Credit Facility) would exceed
$150 million
; and entering into certain transactions with affiliates.
The Credit Facility also includes a covenant restricting our ability to repay indebtedness maturing after September 2022, which is the final maturity date of the Credit Facility. This covenant is subject to certain exceptions that permit us to manage our balance sheet, including the ability to make repayments of indebtedness (i) of acquired companies within
90
days of the completion of the acquisition or (ii) if, after giving effect to such repayments, available cash is greater than
$250 million
and there are no amounts outstanding under the Credit Facility.
As of
June 30, 2018
, we were in compliance in all material respects with our covenants under the Credit Facility. We had
no
amounts outstanding under the Credit Facility as of
June 30, 2018
and
December 31, 2017
.
Our access to credit and capital markets depends on the credit ratings assigned to our debt, and we do not maintain an investment-grade status. Our current credit ratings, and any additional actual or anticipated downgrades in our credit ratings, could limit our available options when accessing credit and capital markets, or when restructuring or refinancing our debt. In addition, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations.
Other Financing
We filed an automatically effective shelf registration statement on Form S-3 with the SEC on November 21, 2017, which provides us the ability to issue debt securities, equity securities, guarantees and/or units of securities in one or more offerings. The registration statement expires in November 2020.
Our shareholders approved a new share repurchase program at our annual shareholder meeting held in May 2018. Subject to certain provisions under English law, including the requirement of Ensco plc to have sufficient distributable reserves, we may repurchase shares up to a maximum of
$500.0 million
in the aggregate from one or more financial intermediaries under the program, but in no case more than
65.0 million
shares. The program terminates in May 2023. Our prior share repurchase program approved by our shareholders in 2013, under which we could repurchase up to a maximum of $2.0 billion in the aggregate, not to exceed 35.0 million shares, terminated in May 2018.
From time to time, we and our affiliates may repurchase our outstanding senior notes in the open market, in privately negotiated transactions, through tender offers, exchange offers or otherwise, or we may redeem senior notes that are able to be redeemed, pursuant to their terms. In connection with any exchange, we may issue equity, issue new debt and/or pay cash consideration. Any future repurchases, exchanges or redemptions will depend on various factors existing at that time. There can be no assurance as to which, if any, of these alternatives (or combinations thereof) we may choose to pursue in the future. There can be no assurance that an active trading market will exist for our outstanding senior notes following any such transactions.
Other Commitments
As of
June 30, 2018
, we were contingently liable for an aggregate amount of
$125.4 million
under outstanding letters of credit and surety bonds which 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 and surety bonds are not normally called, as we typically comply with the underlying performance requirement. As of
June 30, 2018
, we had not been required to make any collateral deposits with respect to these agreements.
Liquidity
Our liquidity position is summarized in the table below (in millions, except ratios):
|
|
|
|
|
|
|
|
|
|
June 30,
2018
|
|
December 31,
2017
|
Cash and cash equivalents
|
$
|
485.5
|
|
|
$
|
445.4
|
|
Short-term investments
|
$
|
255.0
|
|
|
$
|
440.0
|
|
Working capital
|
$
|
913.0
|
|
|
$
|
853.5
|
|
Current ratio
|
2.7
|
|
|
2.1
|
|
We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from our cash and cash equivalents, short-term investments, operating cash flows, and, if necessary, funds borrowed under the Credit Facility.
We expect to fund our long-term liquidity needs, including contractual obligations and anticipated capital expenditures from our operating cash flows and, if necessary, funds borrowed under the 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.
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
June 30, 2018
, we had cash flow hedges outstanding to exchange an aggregate
$212.1 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
June 30, 2018
, we held derivatives not designated as hedging instruments to exchange an aggregate
$153.2 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
June 30, 2018
would approximate
$17.9 million
. Approximately
$13.0 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 related to derivative counterparties 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 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 of our derivatives mature during the next
18 months
. See Note 5 to our condensed consolidated financial statements included in "Item 1. Financial Information" for additional information on our derivative instruments.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires us to make estimates, judgments and assumptions that affect the amounts reported in our condensed consolidated financial statements and accompanying notes. Our significant accounting policies are included in Note 1 to our audited consolidated financial statements for the year ended
December 31, 2017
, included in our annual report on Form 10-K filed with the SEC on
February 27, 2018
. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our condensed 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 income taxes. For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates" in Part II of our annual report on Form 10-K for the year ended
December 31, 2017
.
New Accounting Pronouncements
See Note 1 to our condensed consolidated financial statements included in "Item 1. Financial Statements" for information on new accounting pronouncements.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Information required under Item 3. has been incorporated into "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."