ITEM 2. Managements Discussion and Analysis of Financial Condition and
Results of Operations.
The following discussion should be read in conjunction with our unaudited consolidated financial statements
(including the notes thereto) included elsewhere in this report and our audited consolidated financial statements and the notes thereto, Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations
and Item 1A, Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2015. References to Diamond Offshore, we, us or our mean Diamond Offshore Drilling,
Inc., a Delaware corporation, and its subsidiaries.
We provide contract drilling services worldwide with a fleet of 24 offshore drilling
rigs. Our current fleet consists of four drillships, 19 semisubmersibles and one jack-up rig. We have four additional jack-up rigs being marketed for sale. In October 2016, we sold one of two retired semisubmersible rigs for scrap and
expect to complete the sale of the remaining retired rig by the end of 2016. The
Ocean GreatWhite
, is expected to be available for customer acceptance shortly. See Contract Drilling Backlog.
Market Overview
Oil prices, which had
fallen to a 12-year low of less than $30 per barrel in January 2016, rebounded into the low-$50 per barrel range by the end of the third quarter of 2016, but continue to exhibit day-to-day volatility due to multiple factors, including fluctuations
in the current and expected level of global oil inventories. As a result, overall fundamentals in the offshore oil and gas industry have not improved, and, in some markets, have deteriorated further. Despite the increase in oil prices during
the third quarter of 2016, industry reports indicate that utilization for floaters continues to fall and cancelation of contracts for deepwater rigs has persisted. Prospective customers for contract drilling services are currently formulating
their 2017 capital spending programs, and it is unlikely that capital spending for exploration and development will exceed 2016 levels, assuming commodity prices remain at current levels. Customer inquiries for rig availability and new tenders
have continued to decline in 2016, as compared to prior years, although recently there has been a slight increase in rig tendering activity, primarily for projects commencing in 2018 and later.
The oversupply of drilling rigs in the floater markets continues to persist. Industry analysts report that 65 floater rigs have been cold
stacked since the beginning of 2016 and an additional 17 floaters have been scrapped year-to-date, with an additional three units estimated to be scrapped by year end. Despite these events, the number of available rigs continues to grow as
contracted rigs come off contract and newly-built rigs are delivered. As of the date of this report, industry data indicates that there are approximately 36 competitive, or non-owner-operated, newbuild floaters on order, of which only three
rigs are reported to be contracted for future work. Of the 36 rigs on order, nine and 16 rigs are scheduled for delivery in the remainder of 2016 and in 2017, respectively. The remaining 11 rigs are scheduled for delivery between 2018 and
2020. Industry analysts predict that delivery dates may shift further as newbuild owners negotiate with their respective shipyards.
Competition for the limited number of drilling jobs continues to be intense. In some cases, dayrates have been negotiated at break-even
levels, or below, to provide for the recovery of a portion of operating costs for rigs that would otherwise be uncontracted or cold stacked. In addition, customer discussions indicate a preference for hot rigs rather than the
reactivation of cold-stacked rigs. This preference incentivizes the drilling contractor to contract rigs at lower rates to maintain the rigs in an active state and allow for at least partial cost recovery. Industry analysts have predicted
that the offshore contract drilling market may remain depressed with further declines in dayrates and utilization likely into 2017.
As a
result of the continuing and worsening market conditions for the offshore drilling industry and continued pessimistic outlook for the near term, certain of our customers, as well as those of our competitors, have attempted to renegotiate or
terminate existing drilling contracts. Such renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in exchange for additional contract term, shortening the term on one contracted rig in exchange for additional
term on another rig, early termination of a contract in exchange for a lump sum payout and many other possibilities. In addition to the potential for renegotiations, some of our drilling contracts permit the customer to terminate the contract early
after specified notice periods, usually resulting in a requirement for the customer to pay a contractually specified termination amount, which may not fully compensate us for the loss of the contract. As a result of these depressed market
conditions, certain customers have also utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under
circumstances where we believe we are in compliance with the contracts.
22
Particularly during depressed market conditions, the early termination of a contract may result
in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. When a customer terminates our contract prior to the contracts scheduled expiration, our
contract backlog is also adversely impacted.
The continuation of these conditions for an extended period could result in more of our rigs
being without contracts and/or cold stacked or scrapped and could further materially and adversely affect our financial condition, results of operations and cash flows. When we cold stack or expect to scrap a rig, we evaluate the rig for impairment.
We currently expect that these adverse market conditions will continue for the foreseeable future. As of October 1, 2016, ten rigs in our fleet were cold stacked and an additional four jack-up rigs are currently being marketed for sale. We have two
retired semisubmersible rigs, which we expect to sell for scrap value in the fourth quarter of 2016. See Contract Drilling Backlog
for future commitments of our rigs during 2016 through 2020.
Our results of operations and cash flows for the quarter ended September 30, 2016 have been negatively impacted by the continuing and
worsening market conditions in the offshore drilling industry, as discussed above. See Results of Operations and Liquidity and Capital Resources and Notes 1 and 2 to our unaudited consolidated financial
statements included in Item 1 of Part I of this report.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of October 1, 2016, February 16, 2016 (the date reported in our Annual Report on
Form 10-K for the year ended December 31, 2015), and October 1, 2015 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2015). Contract drilling backlog as presented below includes only firm commitments
(typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding
scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization
rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling
backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods
are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to
terminate or renegotiate our contracts, which could adversely affect our reported backlog.
In October 2016, BP notified us that they would
no longer pursue a drilling campaign in the Great Australian Bight where the
Ocean GreatWhite
was to be the primary drilling rig for the campaign. BP has confirmed that its decision will not impact the contract for the rig. BP is
exploring alternative locations for the
Ocean GreatWhite
.
In August 2016, our subsidiary received notice of termination of its
drilling contract from Petróleo Brasileiro S.A., or Petrobras, the customer for the
Ocean Valor
. In August 2016, we filed a lawsuit in Brazil, claiming that Petrobras purported termination of the contract was unlawful and
requesting an injunction to prohibit the contract termination. In September 2016, a Brazilian court issued a preliminary injunction, suspending Petrobras purported termination of the contract and ordering that the contract remain in effect
until the end of the term or further court order. Petrobras has appealed the granting of the injunction. The drilling contract provides for a dayrate of approximately $455,000 and was estimated to conclude in accordance with its terms in October
2018. The rig is currently on standby earning a reduced dayrate. We do not believe that Petrobras had a valid or lawful basis for terminating the contract, and we intend to continue to defend our rights under the contract; however, litigation is
inherently unpredictable, and there can be no assurance as to the ultimate outcome of this matter.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 1,
2016
|
|
|
February 16,
2016
|
|
|
October 1,
2015
|
|
|
|
(In thousands)
|
|
Contract Drilling Backlog
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater Floaters
(1)
|
|
$
|
3,614,000
|
|
|
$
|
4,415,000
|
|
|
$
|
4,851,000
|
|
Deepwater Floaters
|
|
|
258,000
|
|
|
|
375,000
|
|
|
|
439,000
|
|
Other Rigs
(2)
|
|
|
210,000
|
|
|
|
405,000
|
|
|
|
419,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,082,000
|
|
|
$
|
5,195,000
|
|
|
$
|
5,709,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Contract drilling backlog as of October 1, 2016 for
our ultra-deepwater floaters includes (i) $641.0 million for the years 2017 to 2020 attributable to future work for the semisubmersible
Ocean GreatWhite
, which is
|
23
|
contracted to BP, and (ii) $306.3 million from 2016 to 2018 attributable to contracted work for the
Ocean Valor
under the contract that Petrobras has attempted to terminate and is
currently in effect pursuant to an injunction granted by a Brazilian court.
|
(2)
|
Includes contract drilling backlog for our mid-water floater and jack-up rigs.
|
The following table reflects the amount of our contract drilling backlog by year as of October 1, 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ending December 31,
|
|
|
|
Total
|
|
|
2016
(1)
|
|
|
2017
|
|
|
2018
|
|
|
2019 - 2020
|
|
|
|
(In thousands)
|
|
Contract Drilling Backlog
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater Floaters
(2)
|
|
$
|
3,614,000
|
|
|
$
|
243,000
|
|
|
$
|
1,187,000
|
|
|
$
|
1,129,000
|
|
|
$
|
1,055,000
|
|
Deepwater Floaters
|
|
|
258,000
|
|
|
|
68,000
|
|
|
|
181,000
|
|
|
|
9,000
|
|
|
|
|
|
Other Rigs
(3)
|
|
|
210,000
|
|
|
|
57,000
|
|
|
|
153,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,082,000
|
|
|
$
|
368,000
|
|
|
$
|
1,521,000
|
|
|
$
|
1,138,000
|
|
|
$
|
1,055,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents the three-month period beginning October 1, 2016.
|
(2)
|
Contract drilling backlog as of October 1, 2016 for our ultra-deepwater floaters includes (i) $213.0 million and $214.0 million for the years 2017 and
2018, respectively, and $214.0 million in the aggregate for the years 2019 to 2020, attributable to future work for the
Ocean GreatWhite
, which is contracted to BP, and (ii) $37.7 million, $149.4 million and $119.2 million for the years
2016, 2017 and 2018, respectively, attributable to contracted work for the
Ocean Valor
under the contract that Petrobras has attempted to terminate and is currently in effect pursuant to an injunction granted by a Brazilian
court.
|
(3)
|
Includes contract drilling backlog for our mid-water floater and jack-up rigs.
|
The following table reflects the percentage of rig days committed by year as of October 1, 2016. The percentage of rig days committed is
calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs, including cold-stacked rigs, multiplied by the number of
days in a particular year).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ending December 31,
|
|
|
|
2016
(1)
|
|
|
2017
|
|
|
2018
|
|
|
2019 - 2020
|
|
Rig Days Committed
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater Floaters
|
|
|
53
|
%
|
|
|
59
|
%
|
|
|
57
|
%
|
|
|
27
|
%
|
Deepwater Floaters
|
|
|
44
|
%
|
|
|
37
|
%
|
|
|
2
|
%
|
|
|
|
|
Other Rigs
(3)
|
|
|
18
|
%
|
|
|
14
|
%
|
|
|
|
|
|
|
|
|
(1)
|
Represents the three-month period beginning October 1, 2016.
|
(2)
|
As of October 1, 2016, includes no currently known, scheduled shipyard days for surveys and extended maintenance projects for the remainder of 2016 or for the
year 2017.
|
(3)
|
Includes committed days for our mid-water floater and jack-up rigs.
|
Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows
Regulatory Surveys, Planned Downtime and Regulatory Compliance.
Our operating income is negatively impacted when we perform
certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half-years. We can provide no assurance as to the exact timing
and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See
Contract Drilling Backlog
.
Physical Damage and Marine Liability Insurance.
We are self-insured for physical damage to rigs and equipment caused by
named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial
condition, results of operations and cash flows. Under our current insurance policy, which renewed effective May 1, 2016, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico
for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.
In addition, under our current insurance policy, which renewed effective May 1, 2016, we carry marine liability insurance covering certain
legal liabilities, including coverage for certain personal injury claims, and generally covering liabilities arising out of or relating to pollution and/or environmental risk. We believe that the policy limit for
24
our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine
liability coverage related to insurable events arising due to named windstorms in the U.S. Gulf of Mexico is $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $25.0 million and, if aggregate
claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. Our deductibles for other marine liability coverage, including
personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million
for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.
Construction and Capital Upgrade Projects.
We capitalize interest cost for the construction and upgrade of qualifying
assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period
ends when the asset is substantially complete and ready for its intended use. During the first nine months of 2016, we capitalized interest of $15.2 million related to the construction of the
Ocean GreatWhite
and will continue capitalizing
interest on this project until it is ready to begin working for BP, which we expect to occur in the fourth quarter of 2016. We will also commence depreciation of the
Ocean GreatWhite
in the fourth quarter of 2016.
Critical Accounting Policies
Our
significant accounting policies are discussed in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015. There were no material changes to these policies
during the nine months ended September 30, 2016.
25
Results of Operations
Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of
economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the
appropriate aggregation in accordance with applicable accounting standards on segment reporting. However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in
our fleet to enhance the readers understanding of our financial condition, changes in financial condition and results of operations.
Key performance indicators by equipment type are listed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
REVENUE EARNING DAYS
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater
|
|
|
481
|
|
|
|
786
|
|
|
|
1,566
|
|
|
|
1,945
|
|
Deepwater
|
|
|
218
|
|
|
|
379
|
|
|
|
618
|
|
|
|
1,066
|
|
Mid-Water
|
|
|
181
|
|
|
|
241
|
|
|
|
543
|
|
|
|
1,253
|
|
Jack-ups
|
|
|
|
|
|
|
172
|
|
|
|
149
|
|
|
|
817
|
|
|
|
|
|
|
UTILIZATION
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater
|
|
|
48
|
%
|
|
|
71
|
%
|
|
|
52
|
%
|
|
|
62
|
%
|
Deepwater
|
|
|
34
|
%
|
|
|
59
|
%
|
|
|
32
|
%
|
|
|
56
|
%
|
Mid-Water
|
|
|
33
|
%
|
|
|
31
|
%
|
|
|
29
|
%
|
|
|
39
|
%
|
Jack-ups
|
|
|
|
|
|
|
31
|
%
|
|
|
11
|
%
|
|
|
50
|
%
|
|
|
|
|
|
AVERAGE DAILY REVENUE
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater
|
|
$
|
451,800
|
|
|
$
|
478,800
|
|
|
$
|
483,700
|
|
|
$
|
484,900
|
|
Deepwater
|
|
|
303,000
|
|
|
|
360,700
|
|
|
|
311,200
|
|
|
|
428,400
|
|
Mid-Water
|
|
|
311,200
|
|
|
|
288,500
|
|
|
|
295,900
|
|
|
|
273,600
|
|
Jack-ups
|
|
|
|
|
|
|
96,700
|
|
|
|
202,700
|
|
|
|
89,900
|
|
(1)
|
A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization,
demobilization and contract preparation days.
|
(2)
|
Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all specified rigs in our fleet
(including cold-stacked rigs, but excluding rigs under construction). As of September 30, 2016, our cold-stacked rigs included four ultra-deepwater semisubmersibles, three deepwater semisubmersibles and three mid-water semisubmersibles. In
addition, we have four jack-up rigs that are currently being marketed for sale and two semisubmersible rigs that have been retired. In October 2016, we sold one of our retired rigs for scrap and expect to complete the sale of the remaining
retired rig by the end of 2016.
|
(3)
|
Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per revenue earning day.
|
26
Comparative data relating to our revenues and operating expenses by equipment type are listed
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
(In thousands)
|
|
CONTRACT DRILLING REVENUE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater
|
|
$
|
217,275
|
|
|
$
|
376,195
|
|
|
$
|
757,338
|
|
|
$
|
943,261
|
|
Deepwater
|
|
|
66,011
|
|
|
|
136,668
|
|
|
|
192,319
|
|
|
|
456,542
|
|
Mid-Water
|
|
|
56,350
|
|
|
|
69,500
|
|
|
|
160,716
|
|
|
|
342,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floaters
|
|
|
339,636
|
|
|
|
582,363
|
|
|
|
1,110,373
|
|
|
|
1,742,586
|
|
Jack-ups
|
|
|
|
|
|
|
16,673
|
|
|
|
30,195
|
|
|
|
73,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contract Drilling Revenue
|
|
$
|
339,636
|
|
|
$
|
599,036
|
|
|
$
|
1,140,568
|
|
|
$
|
1,816,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES RELATED TO REIMBURSABLE EXPENSES
|
|
$
|
9,542
|
|
|
$
|
10,706
|
|
|
$
|
67,900
|
|
|
$
|
47,775
|
|
CONTRACT DRILLING EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater
|
|
$
|
124,099
|
|
|
$
|
156,107
|
|
|
$
|
375,020
|
|
|
$
|
472,131
|
|
Deepwater
|
|
|
36,226
|
|
|
|
67,630
|
|
|
|
118,511
|
|
|
|
217,769
|
|
Mid-Water
|
|
|
17,634
|
|
|
|
35,784
|
|
|
|
67,380
|
|
|
|
201,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floaters
|
|
|
177,959
|
|
|
|
259,521
|
|
|
|
560,911
|
|
|
|
891,739
|
|
Jack-ups
|
|
|
1,833
|
|
|
|
12,507
|
|
|
|
14,764
|
|
|
|
54,950
|
|
Other
|
|
|
6,862
|
|
|
|
5,916
|
|
|
|
22,156
|
|
|
|
24,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contract Drilling Expense
|
|
$
|
186,654
|
|
|
$
|
277,944
|
|
|
$
|
597,831
|
|
|
$
|
971,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REIMBURSABLE EXPENSES
|
|
$
|
7,965
|
|
|
$
|
10,476
|
|
|
$
|
51,283
|
|
|
$
|
46,904
|
|
OPERATING INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floaters:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-Deepwater
|
|
$
|
93,176
|
|
|
$
|
220,088
|
|
|
$
|
382,318
|
|
|
$
|
471,130
|
|
Deepwater
|
|
|
29,785
|
|
|
|
69,038
|
|
|
|
73,808
|
|
|
|
238,773
|
|
Mid-Water
|
|
|
38,716
|
|
|
|
33,716
|
|
|
|
93,336
|
|
|
|
140,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floaters
|
|
|
161,677
|
|
|
|
322,842
|
|
|
|
549,462
|
|
|
|
850,847
|
|
Jack-ups
|
|
|
(1,833
|
)
|
|
|
4,166
|
|
|
|
15,431
|
|
|
|
18,519
|
|
Other
|
|
|
(6,862
|
)
|
|
|
(5,916
|
)
|
|
|
(22,156
|
)
|
|
|
(24,782
|
)
|
Reimbursable expenses, net
|
|
|
1,577
|
|
|
|
230
|
|
|
|
16,617
|
|
|
|
871
|
|
Depreciation
|
|
|
(86,473
|
)
|
|
|
(118,086
|
)
|
|
|
(295,729
|
)
|
|
|
(378,714
|
)
|
General and administrative expense
|
|
|
(15,237
|
)
|
|
|
(16,888
|
)
|
|
|
(48,774
|
)
|
|
|
(50,888
|
)
|
Gain (loss) on disposition of assets
|
|
|
1,222
|
|
|
|
(794
|
)
|
|
|
2,265
|
|
|
|
(19
|
)
|
Impairment of assets
|
|
|
|
|
|
|
(2,546
|
)
|
|
|
(678,145
|
)
|
|
|
(361,074
|
)
|
Restructuring and separation costs
|
|
|
|
|
|
|
(1,574
|
)
|
|
|
|
|
|
|
(8,735
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Income (Loss)
|
|
$
|
54,071
|
|
|
$
|
181,434
|
|
|
$
|
(461,029
|
)
|
|
$
|
46,025
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
150
|
|
|
|
629
|
|
|
|
592
|
|
|
|
1,796
|
|
Interest expense, net of amounts capitalized
|
|
|
(19,032
|
)
|
|
|
(21,350
|
)
|
|
|
(68,704
|
)
|
|
|
(70,800
|
)
|
Foreign currency transaction (loss) gain
|
|
|
(712
|
)
|
|
|
(1,163
|
)
|
|
|
(7,833
|
)
|
|
|
954
|
|
Other, net
|
|
|
269
|
|
|
|
217
|
|
|
|
(11,199
|
)
|
|
|
702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax (expense) benefit
|
|
|
34,746
|
|
|
|
159,767
|
|
|
|
(548,173
|
)
|
|
|
(21,323
|
)
|
Income tax (expense) benefit
|
|
|
(20,819
|
)
|
|
|
(23,345
|
)
|
|
|
59,588
|
|
|
|
(7,578
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
13,927
|
|
|
$
|
136,422
|
|
|
$
|
(488,585
|
)
|
|
$
|
(28,901
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
Overview
Three Months Ended September 30, 2016 and 2015
Operating Income (Loss).
Operating results for the third quarter of 2016 decreased $127.4 million compared to the same
period of 2015, primarily due to lower utilization of our fleet, partially offset by a $31.6 million decrease in depreciation expense. Asset impairments in 2015 and 2016 lowered our depreciable asset base, reducing depreciation expense recorded
during the third quarter of 2016, compared to the prior year quarter.
Contract drilling revenue and expense decreased $259.4 million and
$91.3 million, respectively, during the third quarter of 2016, compared to the third quarter of 2015, due to continued low demand for contract drilling services, resulting in an aggregate 698-day decrease in revenue earning days for our drilling
fleet. The decline in contract drilling expense reflected lower costs for labor and personnel ($61.4 million), mobilization of rigs ($18.0 million), shorebase and operational support ($7.1 million) and a net decrease in other rig operating
costs and overhead costs ($16.8 million, including reductions in costs for repairs and maintenance, revenue-based agency fees, freight and rig stacking costs). Reduced contract drilling expense in the third quarter of 2016 was partially offset
by expenses associated with our Pressure Control by the Hour
TM
, or PCbtH, program currently employed on three of our drillships.
Income Tax (Expense) Benefit.
Our effective tax rate for the three months ended September 30, 2016 was 59.9%, compared to a
14.8% effective tax rate for the three months ended September 30, 2015. The effective tax rate in the 2016 period was higher than in the same period of 2015 primarily due to the mix of our domestic and international pre-tax earnings and losses
as well as return to provision adjustments of approximately $6 million in the current period.
Nine Months Ended September 30, 2016 and 2015
Operating Income (Loss).
Operating results for the first nine months of 2016 decreased $507.1 million
compared to the same period of 2015, primarily due to additional impairment losses recognized in 2016 ($317.1 million incremental loss) combined with the negative impact of lower utilization of our rig fleet. These negative effects on operating
income were partially offset by an $83.0 million decrease in depreciation expense. Depreciation expense decreased primarily due to a lower depreciable asset base in 2016, compared to the first nine months of 2015, as a result of asset
impairments taken in 2015 and in the second quarter of 2016.
Contract drilling revenue decreased $675.5 million, or 37%, during the first
nine months of 2016, compared to the same period of 2015, primarily as a result of an aggregate of 2,205 fewer revenue earning days across our entire fleet, combined with the negative effect of lower average daily revenue earned, primarily by
our deepwater floaters.
Total contract drilling expense decreased $373.6 million, or 38%, during the first nine months of 2016, compared
to the same period of 2015, reflecting our lower cost structure due to additional rigs idled, cold stacked or retired during 2015 and in 2016, as well as the favorable impact of our cost control initiatives. The reduction in contract drilling
expense during the first nine months of 2016 included lower expense, primarily for labor and personnel ($188.2 million), repairs and maintenance ($50.2 million), amortized mobilization costs ($44.3 million), shorebase and operational support costs
($35.9 million), freight ($13.9 million), revenue-based agency fees ($13.7 million), inspections ($10.4 million), and other rig operating costs ($37.1 million), including rig stacking costs and late start penalties recognized in 2015. Contract
drilling expense for the first nine months of 2016 included incremental costs associated with our PCbtH program.
Impairment of
Assets
. During the first nine months of 2015, we recognized an aggregate impairment loss of $361.1 million with respect to the carrying values of our older drillship, the
Ocean Clipper
, seven mid-water floaters and one jack-up
rig. During the first nine months of 2016, we recognized an aggregate impairment charge of $678.1 million with respect to the carrying values of two mid-water, three deepwater, and three ultra-deepwater floaters, including related rig spares
and supplies. See Notes 1, 2 and 3 to our unaudited consolidated financial statements included in Item 1 of Part I of this report.
Restructuring and Separation Costs.
During the first quarter of 2015, in response to the decline in the offshore drilling
market, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, which resulted in the recognition of $8.7 million in restructuring and other employee separation related costs during the first
nine months of 2015.
Other, net.
During the second quarter of 2016, we sold our investment in privately-placed
corporate bonds for a total recognized loss of $12.1 million.
28
Income Tax Benefit (Expense).
Our effective tax rate for the nine months ended
September 30, 2016 was 10.9%, compared to an 8.7% effective tax rate for the nine months ended September 30, 2015. The effective tax rate in the 2016 period was higher than in the same period of 2015, primarily due to the mix of our domestic
and international pre-tax earnings and losses, as well as a $61.1 million valuation allowance for current and prior year foreign tax credits recorded in the current period.
Contract Drilling Revenue and Expense by Equipment Type
Three Months Ended September 30, 2016 and 2015
Ultra-Deepwater Floaters.
Revenue generated by our ultra-deepwater floaters decreased $158.9 million during the third quarter of 2016,
compared to the same period of 2015, primarily as a result of 305 fewer revenue earning days ($145.9 million) and lower average daily revenue earned ($13.0 million). Revenue earning days in the third quarter of 2016 decreased, primarily due to fewer
revenue earning days for rigs under contract during the 2015 period that have subsequently been cold stacked (168 days), the
Ocean Clipper
, which was sold in November 2015 (88 days), the
Ocean BlackRhino
, which is currently between
contracts (88 days), and unplanned downtime for contracted rigs (40 days), including downtime associated with an unplanned retrieval of a blowout preventer on one of our drillships. The decrease in revenue earning days was partially offset by
81 incremental revenue earning days for the
Ocean BlackLion
, which was placed in service in the third quarter of 2015. Average daily revenue decreased during the third quarter of 2016, compared to the prior year period, primarily due to
a lower dayrate earned by the
Ocean Courage
.
Contract drilling expense for our ultra-deepwater floaters decreased $32.0 million
during the third quarter of 2016, compared to the third quarter of 2015, primarily due to reduced costs for our cold-stacked ultra-deepwater rigs, including the retired
Ocean Clipper
and the deferral of costs associated with contract
preparation activities for the
Ocean BlackRhino
. Contract drilling expense in the third quarter of 2016 reflected lower expense for labor and personnel ($32.3 million), mobilization of rigs ($15.7 million), repairs and maintenance ($3.1
million), revenue-based agency fees ($2.4 million), freight ($1.3 million) and other contract drilling expense ($9.7 million). Cost reductions in the third quarter of 2016 were partially offset by costs associated with the PCbtH program in
effect on three of our drillships and incremental contract drilling expense for the
Ocean BlackLion
($20.5 million).
Deepwater
Floaters.
Revenue generated by our deepwater floaters decreased $70.7 million in the third quarter of 2016, compared to the same quarter in 2015, primarily due to 161 fewer revenue earning days ($58.1 million) combined with lower
average daily revenue earned ($12.6 million) during the current year quarter. Revenue earning days decreased for the third quarter of 2016 primarily due to incremental downtime associated with cold-stacked rigs that had previously operated
during the third quarter of 2015 (200 additional days) and the
Ocean Valiant
, which completed its contract in August 2016 and is now preparing for its next contract (44 additional days), partially offset by incremental revenue earning days
for the
Ocean Apex
, which began operating under contract in the second quarter of 2016 (91 incremental days). Average daily revenue decreased during the third quarter of 2016, compared to the prior year period, primarily due to a lower
dayrate earned by the
Ocean Valiant
.
Contract drilling expense incurred by our deepwater floaters decreased $31.4 million during
the third quarter of 2016, compared to the same period of 2015, primarily due to reduced operating costs for our cold-stacked deepwater rigs ($35.4 million), partially offset by incremental contract drilling expense for our three active rigs.
Mid-Water Floaters.
Revenue generated by our mid-water floaters decreased $13.2 million in the third quarter of 2016,
compared to the same quarter in 2015, primarily due to 60 fewer revenue earning days ($17.3 million), partially offset by higher average daily revenue earned ($4.1 million). Revenue earnings days decreased in the third quarter of 2016 due to
the absence of revenue earning days for rigs that have been retired (94 fewer days), partially offset by the absence of planned downtime associated with the
Ocean Guardian
s survey during the prior year quarter (36 incremental days).
Since the first quarter of 2015, we have sold ten mid-water floaters, reducing our mid-water fleet to five drilling rigs, three of which are currently cold stacked, and two rigs that are under contract until various times in 2017. One
additional mid-water rig, the
Ocean Quest,
has been retired and is expected to be sold in the fourth quarter of 2016.
Contract
drilling expense for our mid-water floaters decreased $18.2 million in the third quarter of 2016, compared to the prior year quarter, primarily due to reduced operating costs for our cold-stacked and retired mid-water rigs ($16.1 million).
29
Jack-ups.
Contract drilling revenue and expense for our jack-up fleet
decreased $16.7 million and $10.7 million, respectively, during the third quarter of 2016, compared to the same period of 2015. We had no jack-up rigs under contract during the third quarter of 2016, compared to two rigs under contract in the
third quarter of 2015. The
Ocean Scepter
is scheduled to commence operations under a new contract in Mexico beginning in the first quarter of 2017. Our four remaining jack-up rigs are being marketed for sale.
Nine Months Ended September 30, 2016 and 2015
Ultra-Deepwater Floaters.
Revenue generated by our ultra-deepwater floaters during the first nine months of 2016 decreased $185.9
million compared to the same period of 2015, primarily as a result of an aggregate of 379 fewer revenue earning days ($184.0 million). Revenue earning days for the first nine months of 2016 decreased primarily due to 752 fewer revenue earning days
for rigs that had operated during the first nine months of 2015 and are now cold stacked, as well as the
Ocean Clipper
, which was sold in late 2015. The aggregate decrease in revenue earning days was partially offset by incremental
revenue earning days for the
Ocean BlackLion, w
hich began operating under contract after the third quarter of 2015 (186 days), and the
Ocean Monarch
, which was warm stacked during the 2015 period (181 days).
Excluding our newbuild drillships, contract drilling expense for our ultra-deepwater floaters decreased $97.1 million during the first nine
months of 2016, compared to the same period of 2015, reflecting lower expense for labor and personnel ($78.6 million), maintenance and inspections ($32.3 million), mobilization ($22.7 million), shorebase and operational support ($11.2 million),
freight ($7.5million), revenue-based agency fees ($6.6 million), and other rig operating and overhead costs ($9.7 million). These reductions in contract drilling expense were primarily due to lower costs for our cold-stacked rigs and the
retired
Ocean Clipper
, as well as cost reduction initiatives implemented in 2015. Incremental contract drilling expense for our four drillships operating in the GOM was $71.5 million.
Deepwater Floaters.
Revenue generated by our deepwater floaters decreased $264.2 million in the first nine months of 2016,
compared to the same period in 2015, primarily due to 448 fewer revenue earning days ($191.8 million), combined with a lower average daily revenue earned ($72.4 million). Revenue earning days for the first nine months of 2016 decreased
primarily due to the cold stacking of three rigs that had operated during the first nine months of 2015 (686 fewer days), partially offset by incremental revenue earning days for rigs with contracts that commenced in the middle of the second quarter
of 2015 and in 2016 (238 additional days). Average daily revenue decreased as a result of lower amortized mobilization and contract preparation fees recognized in the first nine months of 2016 compared to the same period in 2015 ($21.7
million), combined with lower dayrates earned by the
Ocean Valiant
and
Ocean Apex
during 2016.
Contract drilling expense
incurred by our deepwater floaters decreased $99.3 million during the first nine months of 2016, compared to the same period of 2015, primarily due to a net reduction in costs for labor and personnel ($41.3 million), mobilization of rigs ($20.6
million), repairs and maintenance ($14.6 million), shorebase and operational support ($9.5 million), revenue-based agency fees ($4.1 million) and other operating costs ($9.2 million), primarily as a result of the cold stacking of rigs.
Mid-Water Floaters.
Revenue generated by our mid-water floaters during the first nine months of 2016 decreased $182.1
million compared to the same period in 2015, primarily due to 710 fewer revenue earning days ($194.2 million), partially offset by higher average daily revenue ($12.1 million). Comparing the periods, only three of our mid-water floaters operated
during both periods.
Contract drilling expense for our mid-water floaters decreased $134.5 million in the first nine months of 2016,
compared to the prior year period, reflecting lower costs for labor and personnel ($64.6 million), maintenance and repairs ($14.5 million), shorebase and operational support ($15.8 million), mobilization ($7.6 million), cold stacking of rigs ($6.0
million), penalties ($5.7 million), inspections ($5.3 million) and other ($15.0 million).
Jack-ups.
Contract drilling
revenue and expense for our jack-up fleet decreased $43.3 million and $40.2 million, respectively, during the first nine months of 2016 compared to the prior year period. Revenue earning days decreased by 668 days due to the cold stacking of
four rigs that operated under contract during the 2015 period and an early contract termination for the
Ocean Scepter
in 2016.
30
Liquidity and Capital Resources
We principally rely on our cash flows from operations and cash reserves to meet our liquidity needs and may also utilize borrowings under our
$1.5 billion syndicated revolving credit agreement, or Credit Agreement. See Credit Agreement.
Based on our cash
available for current operations and contractual backlog of $4.1 billion as of October 1, 2016, of which $368.0 million is expected to be realized during the last quarter of 2016, we believe any additional capital expenditures in 2016 will be funded
from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement, as needed. See Cash Flow, Capital Expenditures and Contractual Obligations Contractual Cash Obligations Rig
Construction.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company,
or DFAC, and, as a result of our intention to indefinitely reinvest the earnings of DFAC and its foreign subsidiaries to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to
finance our domestic activities. To the extent available, we expect to utilize the operating cash flows generated by and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to
meet each entitys respective working capital requirements and capital commitments.
At September 30, 2016 and December 31, 2015, we
had cash available for current operations as follows:
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
(In thousands)
|
|
Cash and cash equivalents
|
|
$
|
81,329
|
|
|
$
|
119,028
|
|
Marketable securities
|
|
|
46
|
|
|
|
11,518
|
|
|
|
|
|
|
|
|
|
|
Total cash available for current operations
|
|
$
|
81,375
|
|
|
$
|
130,546
|
|
|
|
|
|
|
|
|
|
|
A substantial portion of our cash flows has been invested in the enhancement of our drilling fleet. We
determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We
make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments thereto if required. See Cash Flow, Capital Expenditures and Contractual Obligations Capital
Expenditures.
We pay dividends at the discretion of our Board of Directors, or Board. Any determination to declare a dividend,
as well as the amount of any dividend that may be declared, will be based on the Boards consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business
needs and other factors that our Board considers relevant at that time. On February 8, 2016, we announced that we would discontinue our quarterly regular cash dividend. During the nine-month period ended September 30, 2015, we paid regular cash
dividends totaling $51.4 million.
Depending on market and other conditions, we may, from time to time, purchase shares of our common stock
in the open market or otherwise. We did not purchase any shares of our outstanding common stock during the nine-month periods ended September 30, 2016 and 2015.
During the nine-month period ended September 30, 2016, our primary source of cash was an aggregate $492.0 million generated by operating
activities, $157.5 million from the sale and leaseback of certain equipment on three of our drillships, and $10.0 million in proceeds from the sale of one jack-up rig and two mid-water floaters. See Cash Flow, Capital Expenditures and
Contractual Obligations Contractual Cash Obligations - Pressure Control by the Hour. Cash usage during the same period was primarily for capital expenditures aggregating $598.2 million, including the final payment to Hyundai Heavy
Industries Co., Ltd., or HHI, for the
Ocean GreatWhite
and $104.5 million for the net repayment of borrowings under our Credit Agreement.
During the nine-month period ended September 30, 2015, our primary source of cash was an aggregate $466.7 million generated from operating
activities, $493.0 million from short-term borrowings under our commercial paper program and $8.4 million from the disposition of assets, including $5.4 million in proceeds from the sale of eight mid-water floaters for scrap during the
period. Cash usage during the same period was primarily $758.3 million towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program, including the final construction installment on the
Ocean
BlackLion
, $250.0 million for debt repayment and $52.3 million for the payment of dividends and anti-dilution adjustments to stock plan participants.
31
We may, from time to time, issue debt or equity securities, or a combination thereof, to finance
capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current
financial condition, current credit ratings, current market conditions and other factors beyond our control.
Cash Flow, Capital Expenditures and
Contractual Obligations
Our cash flow from operations and capital expenditures for the nine-month periods ended September 30, 2016 and
2015 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
(In thousands)
|
|
Cash flow from operations
|
|
$
|
491,994
|
|
|
$
|
466,677
|
|
|
|
|
Cash capital expenditures:
|
|
|
|
|
|
|
|
|
Drillship construction
|
|
$
|
|
|
|
$
|
416,095
|
|
Major upgrade of deepwater floaters
|
|
|
|
|
|
|
34,632
|
|
Construction of ultra-deepwater floater
|
|
|
477,749
|
|
|
|
37,129
|
|
Ocean Patriot
enhancement project
|
|
|
|
|
|
|
1,349
|
|
Ocean Confidence
service-life extension project
|
|
|
|
|
|
|
74,956
|
|
Rig equipment and replacement programs
|
|
|
120,487
|
|
|
|
194,181
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
598,236
|
|
|
$
|
758,342
|
|
|
|
|
|
|
|
|
|
|
Cash Flow.
Cash flow from operations increased approximately $25.3 million during the first
nine months of 2016, compared to the first nine months of 2015, primarily due to a net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, repairs and maintenance, and other rig
operating costs ($499.0 million), partially offset by lower cash receipts for contract drilling services ($490.3 million). The decline in both cash receipts and cash payments related to the performance of contract drilling services reflects the
continued decline in contract drilling activity during the nine-month period ended September 30, 2016, as well as the positive results of our continuing efforts to control costs.
Capital Expenditures.
We currently expect total capital expenditures for 2016 to aggregate approximately $625.0 million, including
construction costs for the
Ocean GreatWhite
and our ongoing capital maintenance and replacement programs. As of September 30, 2016, we had incurred capital expenditures of $582.0 million during 2016, including accrued
expenditures. See Contractual Cash Obligations Rig Construction. We are currently assessing our capital spending requirements for 2017 and have not yet approved a capital program for 2017.
Contractual Cash Obligations
-
Rig Construction
. Shipyard construction of the
Ocean GreatWhite
, a 10,000 foot dynamically
positioned, harsh environment semisubmersible drilling rig, has been completed. In June 2016, we funded the final payment to HHI totaling $402.5 million in final settlement of the contract price for the
Ocean GreatWhite
The
Ocean
GreatWhite
was delivered by the shipyard in mid-July 2016.
Contractual Cash Obligations - Pressure Control by the
Hour.
During the first nine months of 2016, we executed three sale and leaseback transactions with respect to well control equipment on the
Ocean BlackHawk, Ocean BlackHornet
and
Ocean BlackLion
. Future commitments
under the operating leases and contractual services agreements for these rigs are estimated to be approximately $49.0 million per year or an aggregate $491.0 million over the term of the agreements. We expect to complete the remaining sale and
leaseback transaction for the
Ocean BlackRhino
in the fourth quarter of 2016. See Note 13 to our unaudited consolidated financial statements included in Item 1 of Part I of this report.
We had no other purchase obligations for major rig upgrades or any other significant obligations at September 30, 2016, except for those
related to our direct rig operations, which arise during the normal course of business.
Other Obligations.
As of September 30,
2016, the total unrecognized tax benefits related to uncertain tax positions was $102.2 million. In addition, we have recorded a liability, as of September 30, 2016, for potential
32
penalties and interest of $42.6 million and $2.5 million, respectively. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities
recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.
Credit Agreement
At September 30, 2016,
we had $182.1 million in borrowings outstanding under our Credit Agreement, and we were in compliance with all covenants thereunder. As of October 27, 2016, we had $221.5 million in borrowings outstanding and an additional $1.28 billion
available under our Credit Agreement to provide short-term liquidity for our payment obligations.
Credit Ratings
In February 2016, Moodys Investors Service downgraded our senior unsecured credit rating to Ba2 from Baa2, with a stable outlook, and
also downgraded our short-term credit rating to sub-prime. In July 2016, S&P Global Ratings (formerly Standard & Poors Ratings Services) downgraded our senior unsecured credit rating to BBB from BBB+; the outlook remains negative.
Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. A
downgrade in our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that we could issue, and could further restrict our access to capital markets and our ability to raise additional
debt. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.
As a result of a downgrade in our short-term credit rating, in the first quarter of 2016 we canceled our commercial paper program due to our
inability to access the commercial paper market in the foreseeable future. We no longer obtain a short-term credit rating from either rating agency.
Other Commercial Commitments - Letters of Credit
We were contingently liable as of September 30, 2016 in the amount of $57.2 million under certain performance, tax, supersedeas and customs
bonds and letters of credit. Agreements relating to approximately $54.1 million of performance, tax, supersedeas, court and customs bonds can require collateral at any time. As of September 30, 2016, we had not been required to make any
collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below
provides a list of these obligations in U.S. dollar equivalents and their time to expiration.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ending December 31,
|
|
|
|
Total
|
|
|
2016
|
|
|
2017
|
|
|
2018
|
|
|
2020
|
|
|
|
(In thousands)
|
|
Other Commercial Commitments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance bonds
|
|
$
|
40,177
|
|
|
$
|
|
|
|
$
|
16,754
|
|
|
$
|
4,298
|
|
|
$
|
19,125
|
|
Supersedeas bond
|
|
|
9,189
|
|
|
|
9,189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax bond
|
|
|
5,139
|
|
|
|
|
|
|
|
5,139
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
2,684
|
|
|
|
1,420
|
|
|
|
875
|
|
|
|
389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations
|
|
$
|
57,189
|
|
|
$
|
10,609
|
|
|
$
|
22,768
|
|
|
$
|
4,687
|
|
|
$
|
19,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-Balance Sheet Arrangements
At September 30, 2016 and December 31, 2015, we had no off-balance sheet debt or other off-balance sheet arrangements.
New Accounting Pronouncements
See Note 1
General Information to our unaudited consolidated financial statements included in Item 1 of Part I of this report for a discussion of recently issued accounting pronouncements.
33
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by
reference certain written or oral statements that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934,
as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project,
indicate or imply future results, events, performance or achievements, and may contain or be identified by the words expect, intend, plan, predict, anticipate, estimate,
believe, should, could, may, might, will, will be, will continue, will likely result, project, forecast,
budget and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible
actions taken by or against us, which may be provided by management, are also forward-looking statements. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning
our possible or assumed future results of operations and statements about the following subjects:
|
|
|
market conditions and the effect of such conditions on our future results of operations;
|
|
|
|
sources and uses of and requirements for financial resources and sources of liquidity;
|
|
|
|
contractual obligations and future contract negotiations;
|
|
|
|
interest rate and foreign exchange risk;
|
|
|
|
competitive position, including without limitation, competitive rigs entering the market;
|
|
|
|
expected financial position;
|
|
|
|
cash flows and contract backlog;
|
|
|
|
statements regarding the future term of the Petrobras drilling contract for the
Ocean Valor
and the enforcement of our rights under the contract;
|
|
|
|
idling drilling rigs or reactivating stacked rigs;
|
|
|
|
declaration and payment of regular or special dividends;
|
|
|
|
debt levels and the impact of changes in the credit markets and credit ratings for our debt;
|
|
|
|
timing and duration of required regulatory inspections for our drilling rigs;
|
|
|
|
timing and cost of completion of rig upgrades, construction projects and other capital projects;
|
|
|
|
delivery dates and drilling contracts related to rig conversion or upgrade projects, construction projects, other capital projects or rig acquisitions;
|
|
|
|
scrapping retired rigs;
|
|
|
|
asset impairments and impairment evaluations;
|
|
|
|
outcomes of legal proceedings;
|
|
|
|
purchases of our securities;
|
|
|
|
compliance with applicable laws; and
|
|
|
|
availability, limits and adequacy of insurance or indemnification.
|
These types of statements
are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected,
projected or expressed in forward-looking statements. These risks and uncertainties include, among others, those described or referenced under Risk Factors in Item 1A in our Annual Report on Form 10-K for the year ended December 31,
2015.
The risks and uncertainties referenced above are not exhaustive. Other sections of this report and our other filings with the SEC
include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking
statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations
or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we may refer to reports published by third parties that
purport to describe trends or developments in energy production or drilling and exploration activity. We do so for the convenience of our investors and potential investors
34
and in an effort to provide information available in the market intended to lead to a better understanding of the market environment in which we operate. We specifically disclaim any
responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.