Company Quick10K Filing
Quick10K
Ocean Rig Udw
20-F 2017-12-31 Annual: 2017-12-31
20-F 2016-12-31 Annual: 2016-12-31
20-F 2015-12-31 Annual: 2015-12-31
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ORIG 2017-12-31
Part I
Item 1. Identity of Directors, Senior Management and Advisers
Item 2. Offer Statistics and Expected Timetable
Item 3. Key Information
Item 4. Information on The Company
Item 4A. Unresolved Staff Comments
Item 5. Operating and Financial Review and Prospects
Item 6. Directors, Senior Management and Employees
Item 7. Major Shareholders and Related Party Transactions
Item 8. Financial Information
Item 9. The Offer and Listing
Item 10. Additional Information
Item 11. Quantitative and Qualitative Disclosures About Market Risk
Item 12. Description of Securities Other Than Equity Securities
Part II
Item 13. Defaults, Dividend Arrearages and Delinquencies
Item 14. Material Modifications To The Rights of Security Holders and Use of Proceeds
Item 15. Controls and Procedures
Item 16A. Audit Committee Financial Expert
Item 16B. Code of Ethics
Item 16C. Principal Accountant Fees and Services
Item 16D. Exemptions From The Listing Standards for Audit Committees
Item 16E. Purchases of Equity Securities By The Issuer and Affiliated Purchasers
Item 16F. Change in Registrant's Certifying Accountant
Item 16G. Corporate Governance
Item 16H. Mine Safety Disclosure
Part III
Item 17. Financial Statements
Item 18. Financial Statements
Item 19. Exhibits
EX-1.1 d7830035_ex1-1.htm
EX-4.31 d7831738_ex4-31.htm
EX-4.32 d7831593_ex4-32.htm
EX-4.33 d7831361_ex4-33.htm
EX-4.34 d7831422_ex4-34.htm
EX-4.35 d7831333_ex4-35.htm
EX-4.36 d7831588_ex4-36.htm
EX-4.37 d7831564_ex4-37.htm
EX-4.38 d7831525_ex4-38.htm
EX-4.39 d7831301_ex4-39.htm
EX-4.40 d7831383_ex4-40.htm
EX-4.41 d7831591_ex4-41.htm
EX-4.42 d7841778_ex4-42.htm
EX-4.43 d7841788_ex4-43.htm
EX-4.44 d7841785_ex4-44.htm
EX-4.45 d7841789_ex4-45.htm
EX-4.46 d7841790_ex4-46.htm
EX-4.47 d7841802_ex4-47.htm
EX-4.48 d7841870_ex4-48.htm
EX-4.49 d7841911_ex4-49.htm
EX-4.50 d7841884_ex4-50.htm
EX-4.51 d7841769_ex4-51.htm
EX-8.1 d7831037_ex8-1.htm
EX-12.1 d7801495_ex12-1.htm
EX-12.2 d7801495_ex12-2.htm
EX-13.1 d7801495_ex13-1.htm
EX-13.2 d7801495_ex13-2.htm

Ocean Rig Udw Earnings 2017-12-31

ORIG 20F Annual Report

Balance SheetIncome StatementCash Flow

20-F 1 d7801495_20-f.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 20-F

REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to

OR

SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report: Not applicable

Commission file number 001-35298

OCEAN RIG UDW INC.
(Exact name of Registrant as specified in its charter)

(Translation of Registrant's name into English)

The Cayman Islands
(Jurisdiction of incorporation or organization)

Ocean Rig Cayman Management Services SEZC Limited
3rd Floor Flagship Building
Harbour Drive, Grand Cayman, Cayman Islands
(Address of principal executive offices)

Iraklis Sbarounis
c/o Ocean Rig Cayman Management Services SEZC Limited
3rd Floor Flagship Building
Harbour Drive, Grand Cayman, Cayman Islands,
Telephone: +1 345 327 9232
Email: ocrcayman@ocean-rig.com
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of class
 
Name of exchange on which registered
     
Class A Common shares, $0.01 par value
 
The NASDAQ Stock Market LLC

Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer's classes of capital or common shares as of the close of the period covered by the annual report: As of December 31, 2017, there were 90,562,138 Class A shares of the Company's common stock, $0.01 par value, and 1,005,844 Class B shares of the Company's common stock outstanding.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes     No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.  Yes  No
Note—Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definitions of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer 
Accelerated filer 
Non-accelerated filer 

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
 
US GAAP  
International Financial Reporting Standards as issued by the International Accounting Standards Board 
Other  
 

If "Other" has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.   Item 17  Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  No

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes No

TABLE OF CONTENTS

Page
FORWARD-LOOKING STATEMENTS
 
PART I
   
ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
1
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE
1
ITEM 3.
KEY INFORMATION
1
ITEM 4.
INFORMATION ON THE COMPANY
31
ITEM 4A.
UNRESOLVED STAFF COMMENTS
40
ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
40
ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
60
ITEM 8.
FINANCIAL INFORMATION
64
ITEM 9.
THE OFFER AND LISTING
66
ITEM 10.
ADDITIONAL INFORMATION
67
ITEM 11.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
81
ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
82
PART II
   
ITEM 13.
DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
83
ITEM 14.
MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
83
ITEM 15.
CONTROLS AND PROCEDURES
83
ITEM 16A.
AUDIT COMMITTEE FINANCIAL EXPERT
84
ITEM 16B.
CODE OF ETHICS
84
ITEM 16C.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
84
ITEM 16D.
EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
85
ITEM 16E.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
85
ITEM 16F.
CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT
85
ITEM 16G.
CORPORATE GOVERNANCE
85
ITEM 16H.
MINE SAFETY DISCLOSURE
85
PART III
   
ITEM 17.
FINANCIAL STATEMENTS
86
ITEM 18.
FINANCIAL STATEMENTS
86
ITEM 19.
EXHIBITS
86

i

FORWARD-LOOKING STATEMENTS
The Private Securities Litigation Reform Act of 1995 provides safe harbor protections for forward-looking statements in order to encourage companies to provide prospective information about their business. The Company desires to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and is including this cautionary statement in connection with such safe harbor legislation.
This annual report and any other written or oral statements made by us or on our behalf may include forward-looking statements which reflect our current views and assumptions with respect to future events and financial performance and are subject to risks and uncertainties. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements, which are other than statements of historical or present facts or conditions. The words "believe," "anticipate," "intend," "estimate," "forecast," "project," "plan," "potential," "may," "should," "expect" and similar expressions identify forward-looking statements.
The forward-looking statements in this document are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish the expectations, beliefs or projections described in the forward-looking statements contained in this annual report.
In addition to these important factors and matters discussed elsewhere in this annual report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include factors related to:
          our ability to operate business following the Restructuring;
the offshore drilling market, including supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, effects of new rigs and drillships on the market and effects of declines in commodity prices and downturn in global economy on market outlook for our various geographical operating sectors and classes of drilling units;
hazards inherent in the offshore drilling industry and marine operations causing personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations;
customer contracts, including contract backlog, contract commencements, contract amendments or terminations, contract option exercises, contract revenues, contract awards and drilling unit and drillship mobilizations, performance provisions, newbuildings, upgrades, shipyard and other capital projects, including completion, delivery and commencement of operations dates, expected downtime and lost revenue;
political and other uncertainties, including political unrest, risks of terrorist acts, war and civil disturbances, piracy, significant governmental influence over many aspects of local economies, seizure, nationalization or expropriation of property or equipment;
repudiation, nullification, termination, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
the inability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
import-export quotas, wage and price controls imposition of trade barriers;
regulatory or financial requirements to comply with foreign bureaucratic actions, including potential limitations on drilling activity;
ii


changing taxation policies and other forms of government regulation and economic conditions that are beyond our control;
the level of expected capital expenditures and the timing and cost of completion of capital projects; our ability to successfully employ both our existing and newbuilding drilling units, procure or have access to financing, ability to comply with loan covenants, liquidity and adequacy of cash flow for our obligations;
our new capital structure;
continued borrowing availability under our debt agreements and compliance with the covenants contained therein;
our ability to generate sufficient cash flow to service our existing debt and the incurrence of indebtedness in the future;
factors affecting our results of operations and cash flow from operations, including revenues and expenses, uses of excess cash, including debt retirement, dividends, timing and proceeds of asset sales, tax matters, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, legal and regulatory matters, including results and effects of legal proceedings, customs and environmental matters, insurance matters, debt levels, including impacts of the financial and credit crisis;
the effects of accounting changes and adoption of accounting policies;
recruitment and retention of personnel; and
other important factors described in "Item 3. Key Information—D. Risk factors" and our other reports filed or furnished with the U.S. Securities and Exchange Commission.
We caution readers of this annual report not to place undue reliance on these forward-looking statements.
All forward-looking statements made in this annual report are qualified by these cautionary statements. These forward-looking statements are made only as of the date of this annual report, and we expressly disclaim any obligation to update or revise any forward-looking statements to reflect changes in assumptions, the occurrence of unanticipated events, changes in future operating results over time or otherwise.
Please note in this annual report, "we," "us," "our," "Ocean Rig UDW" and "the Company," all refer to Ocean Rig UDW Inc. and its subsidiaries, unless the context otherwise requires.
iii

PART I
Item 1.          Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2.          Offer Statistics and Expected Timetable
Not applicable.
Item 3.          Key Information
A.          Selected Historical Consolidated Financial Data
The following table sets forth our selected historical consolidated financial and other data, at the dates and for the periods indicated. The selected historical consolidated financial data are derived from our audited consolidated financial statements and notes thereto which have been prepared in accordance with U.S. generally accepted accounting principles or U.S. GAAP.
The selected historical consolidated financial and other data should be read in conjunction with "Item 5. Operating and Financial Review and Prospects" and the audited consolidated financial statements, the related notes thereto and other financial information appearing elsewhere in this annual report.
   
Ocean Rig UDW Inc.
 
(U.S. Dollars in
 
As of December 31,
 
thousands except for share and per share data)
 
2013
   
2014
   
2015
   
2016
   
2017
 
                               
 Income statement data:
                             
Total revenues
   
1,180,250
     
1,817,077
     
1,748,200
     
1,653,667
     
1,007,520
 
Drilling units operating expenses
   
504,957
     
727,832
     
582,122
     
454,329
     
295,135
 
Loss on disposals
   
-
     
-
     
5,177
     
25,274
     
238
 
Impairment loss
   
-
     
-
     
414,986
     
3,776,338
     
1,048,828
 
Depreciation and amortization
   
235,473
     
324,302
     
362,587
     
334,155
     
121,193
 
Legal settlements and other, net
   
6,000
     
(721
)
   
(2,591
)
   
(8,720
)
   
(1,519
)
General and administrative expenses
   
126,868
     
131,745
     
100,314
     
103,961
     
73,360
 
Total operating expenses
   
873,298
     
1,183,158
     
1,462,595
     
4,685,337
     
1,537,235
 
                                         
Operating income/ (expenses)
   
306,952
     
633,919
     
285,605
     
(3,031,670
)
   
(529,715
)
Interest and finance costs
   
(220,564
)
   
(300,131
)
   
(280,348
)
   
(226,981
)
   
(248,342
)
Interest income
   
9,595
     
12,227
     
9,811
     
3,449
     
7,442
 
Gain/(loss) on interest rate swaps
   
8,616
     
(12,671
)
   
(11,513
)
   
(4,388
)
   
-
 
Reorganization gain, net
   
-
     
-
     
-
     
-
     
1,029,982
 
Loss from issuance of shares upon restructuring
   
-
     
-
     
-
     
-
     
(204,595
)
Gain from repurchase of Senior Notes
   
-
     
-
     
189,174
     
125,001
     
-
 
Other income/(expense), net
   
3,315
     
4,282
     
(12,899
)
   
(614
)
   
3,321
 
Total other income/ (expenses), net
   
(199,038
)
   
(296,293
)
   
(105,775
)
   
(103,533
)
   
587,808
 
                                         
Income/(loss) before income taxes
   
107,914
     
337,626
     
179,830
     
(3,135,203
)
   
58,093
 
Income taxes
   
(44,591
)
   
(77,823
)
   
(99,816
)
   
(106,315
)
   
(63,495
)
Net income/(loss)
 
$
63,323
   
$
259,803
   
$
80,014
   
$
(3,241,518
)
   
(5,402
)
Net Income/(loss) attributable to common stockholders
 
$
63,221
   
$
259,031
   
$
78,839
   
$
(3,241,518
)
   
(5,402
)
Earnings/(loss) per share of class A and class B attributable to common stockholders, basic and diluted
 
$
4,415.43
   
$
18,075.97
   
$
5,227.36
   
$
(307,602.77
)
 
$
(0.21
)
Weighted average number of class A common shares, basic and diluted (1)
   
14,318
     
14,330
     
15,082
     
10,538
     
25,070,978
 
Weighted average number of class B common shares, basic and diluted (1)
   
-
     
-
     
-
     
-
     
167,314
 
Weighted average number of class A and class B common shares, basic and diluted (1)
   
14,318
     
14,330
     
15,082
     
10,538
     
25,238,292
 

1



   
Ocean Rig UDW Inc.
 
(U.S. Dollars in
 
As of December 31,
 
thousands except for share and per share data)
 
2013
   
2014
   
2015
   
2016
   
2017
 
Balance sheet data:
                             
Cash and cash equivalents
   
605,467
     
528,933
     
734,747
     
718,684
     
736,114
 
Other current assets
   
404,250
     
449,259
     
503,355
     
361,257
     
254,604
 
Total current assets
   
1,009,717
     
978,192
     
1,238,102
     
1,079,941
     
990,718
 
Drilling units, machinery and equipment, net
   
5,777,025
     
6,207,633
     
6,336,892
     
2,438,292
     
1,852,167
 
Intangible assets, net
   
6,175
     
4,732
     
3,289
     
1,845
     
-
 
Other non-current assets
   
165,220
     
228,557
     
47,085
     
25,997
     
9,080
 
Advances for drilling units under construction and related costs
   
662,313
     
622,507
     
394,852
     
545,469
     
-
 
Total assets
   
7,620,450
     
8,041,621
     
8,020,220
     
4,091,544
     
2,851,965
 
Current liabilities, including current portion of long term debt, net of deferred financing costs
   
543,654
     
417,693
     
401,464
     
812,011
     
184,043
 
Long term debt, net of current portion and deferred financing costs
   
3,907,835
     
4,352,592
     
4,271,743
     
3,247,216
     
450,000
 
Other non-current liabilities
   
189,118
     
105,060
     
72,248
     
21,567
     
14,702
 
Total liabilities
   
4,640,607
     
4,875,345
     
4,745,455
     
4,080,794
     
648,745
 
Number of shares issued
   
14,334
     
14,350
     
17,486
     
17,486
     
91,567,982
 
Stockholders' equity
   
2,979,843
     
3,166,276
     
3,274,765
     
10,750
     
2,203,220
 
Common Stock
   
-
     
-
     
-
     
-
     
916
 
Dividends declared, per share
   
-
     
5,244.00
     
3,496.00
     
-
     
-
 
Total liabilities and stockholders' equity
 
$
7,620,450
   
$
8,041,621
   
$
8,020,220
   
$
4,091,544
   
$
2,851,965
 


 
Ocean Rig UDW Inc.
 
(U.S. Dollars in
Year Ended December 31,
 
thousands, except for operating data)
 
2013
 
2014
 
2015
 
2016
 
2017
 
Cash flow data:
                   
Net cash provided by / (used in):
                   
Operating activities
 
$
333,008
   
$
469,817
   
$
593,012
   
$
763,129
   
543,368
 
Investing activities
   
(1,144,230
)
   
(814,984
)
   
(643,717
)
   
(392,547
)
 
(29,481
)
Financing activities
   
1,099,323
     
268,633
     
263,267
     
(386,645
)
 
(496,457
)
Other financial data
                                     
EBITDA (2)
   
554,356
     
949,832
     
812,954
     
(2,577,516
)
 
420,186
 
Cash paid for interest
   
113,337
     
212,014
     
256,056
     
254,207
   
60,862
 
Capital expenditures
   
(1,283,364
)
   
(748,981
)
   
(633,843
)
   
(340,153
)
 
(36,994
)
Operating data, when on hire
                                     
Total Fleet
   
8
     
9
     
10
     
11
   
11
 
_____________________
(1)
All previously reported share and per share amounts have been adjusted to account for the 1-for-9,200 reverse stock split on September 21, 2017.

(2)
EBITDA represents net income/loss before interest, taxes, depreciation and amortization. EBITDA is a non-U.S. generally accepted accounting principles, or U.S. GAAP, measure and does not represent and should not be considered as an alternative to net income /loss or cash flow from operations, as determined by GAAP or other GAAP measures, and our calculation of EBITDA may not be comparable to that reported by other companies. EBITDA is included herein because it is a basis upon which we measure our operations.
2


 
Ocean Rig UDW Inc.
 
                     
(U.S. Dollars in
Year Ended December 31,
 
thousands)
2013
 
2014
 
2015
 
2016
 
2017
 
EBITDA reconciliation
                   
Net income / (loss)
 
$
63,323
   
$
259,803
   
$
80,014
     
(3,241,518
)
 
$
(5,402
)
Add: Depreciation and amortization
   
235,473
     
324,302
     
362,587
     
334,155
     
121,193
 
Add: Net interest expense
   
210,969
     
287,904
     
270,537
     
223,532
     
240,900
 
Add: Income taxes
   
44,591
     
77,823
     
99,816
     
106,315
     
63,495
 
EBITDA
 
$
554,356
   
$
949,832
   
$
812,954
   
$
(2,577,516
)
 
$
420,186
 

B.          Capitalization and Indebtedness
Not applicable.
C.          Reasons for the Offer and Use of Proceeds
Not applicable.
D.          Risk Factors
Some of the following risks relate principally to the industry in which we operate and our business in general. Other risks relate principally to the securities market and ownership of our common shares. The occurrence of any of the events described in this section could significantly and negatively affect our business, financial condition, operating results, cash flows or our ability to pay dividends, if any, in the future, or the trading price of our common shares.
Risks Relating to Our Industry
The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.
The oil and gas drilling industry is currently in the midst of a severe and prolonged downcycle. Crude oil prices have fallen during the past years.  The price of crude oil has fallen from over $100 per barrel in March 2014, to approximately $65 per barrel in February 2018. The significant decrease in oil and natural gas prices is expected to continue to reduce many of our customers' demand for our services in 2018 onwards. In fact, in response to the recent decrease in the prices of oil and gas, a number of our oil and gas company customers have announced significant decreases in budgeted expenditures for offshore drilling.  Declines in capital spending levels, coupled with additional newbuilding supply, have and are likely to continue to put significant pressure on dayrates and utilization. The decline and the perceived risk of a further decline in oil and/or gas prices could cause oil and gas companies to further reduce their overall level of activity or spending, in which case demand for our services may further decline and revenues may continue to be adversely affected through lower drilling unit utilization and/or lower dayrates.
Historically, when drilling activity and spending decline, utilization and dayrates also decline and drilling has been reduced or discontinued, resulting in an oversupply of drilling units. The recent oversupply of drilling units is exacerbated by the entry of a large number of newbuilding drilling units into the market. The supply of available uncontracted units has and is likely to further intensify price competition as scheduled delivery dates occur and additional contracts terminate without renewal and lead to a reduction in dayrates as the active fleet grows.
In general, drilling unit owners are bidding for available work extremely competitively with a focus on utilization over returns, which has and will likely continue to drive rates down to or below cash breakeven levels.  To maintain the continued employment of our units, we may also accept contracts at lower dayrates or on less favorable terms due to market conditions.  In addition, customers have and may in the future request renegotiation of existing contracts to lower dayrates. In an over-supplied market, we may have limited bargaining power to renegotiate on more favorable terms. Lower utilization and dayrates have and will adversely affect our revenues and profitability.
In the current environment our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, resulting in lower dayrates. Since 2014, five of our customers have decided to terminate the drilling contracts for five of our operating units, the Eirik Raude, the Ocean Rig Olympia, the Ocean Rig Apollo, the Ocean Rig Mylos and the Ocean Rig Athena. The effects of the down-cycle may have other impacts on our business as well. In addition, as the market value of our drilling units decreases, and if we sell any drilling unit at a time when prices for drilling units have fallen, such a sale may result in a loss, which would negatively affect our results of operations.
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Prolonged periods of low dayrates, the possible termination or loss of contracts and reduced values of our drilling units could negatively impact our ability to comply with certain financial covenants under the terms of our debt agreements.
We cannot predict the future level of demand for our services or future conditions of the oil and gas industry. Any decrease in exploration, development or production expenditures by oil and gas companies could reduce our revenues and materially harm our business and results of operations.  There can be no assurance that the current demand for drilling units will not further decline in future periods. The continued or future decline in demand for drilling units would adversely affect our financial position, operating results and cash flows.
Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by, among other things, volatile oil and gas prices and may be materially and adversely affected by a decline in the offshore oil and gas industry.
The offshore contract drilling industry is cyclical and volatile. Our business depends on the level of activity in oil and gas exploration, development and production in offshore areas worldwide. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments affect customers' drilling programs. Oil and gas prices and market expectations of potential changes in these prices also significantly affect this level of activity and demand for drilling units.
Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including the following:
worldwide production and demand for oil and gas and any geographical dislocations in supply and demand;
the cost of exploring for, developing, producing and delivering oil and gas;
expectations regarding future energy prices;
advances in exploration, development and production technology;
the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain levels and pricing;
the level of production in non-OPEC countries;
government regulations;
local and international political, economic and weather conditions;
domestic and foreign tax policies;
development and exploitation of alternative fuels;
the policies of various governments regarding exploration and development of their oil and gas reserves; and
the worldwide military and political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities, insurrection or other crises in the Middle East or other geographic areas or further acts of terrorism in the United States, or elsewhere.
In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, including:
the availability of competing offshore drilling vessels and the level of newbuilding activity for drilling vessels;
the level of costs for associated offshore oilfield and construction services;
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oil and gas transportation costs;
the discovery of new oil and gas reserves;
the cost of non-conventional hydrocarbons, such as the exploitation of oil sands; and
regulatory restrictions on offshore drilling.
Any of these factors could reduce demand for our services and adversely affect our business and results of operations.
Instability in the world economy could have a material adverse effect on our revenue, profitability and financial position.
Although there are signs that the economic recession has abated in many countries, there is still considerable instability in the world economy. Further decrease in global economic activity would likely reduce worldwide demand for energy and result in an extended period of lower crude oil and natural gas prices. In addition, the occurrence or threat of terrorist attacks against the United States or other countries could adversely affect the economies of the United States and of other countries. Any prolonged reduction in crude oil and natural gas prices would depress the levels of exploration, development and production activity. Moreover, even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. These factors could cause our revenues and margins to decline, decrease daily rates and utilization of our drilling units and limit our future growth prospects. Any significant decrease in daily rates or utilization of our drilling units could materially reduce our revenues and profitability. In addition, any instability in the financial and insurance markets, as experienced in the financial and credit crisis which took place earlier in the decade, could make it more difficult for us to access capital and to obtain insurance coverage that we consider adequate or is otherwise required by our drilling contracts. An extended period of deterioration in outlook for the world economy could reduce the overall demand for our services and could also adversely affect our ability to obtain financing on terms acceptable to us or at all.
The offshore drilling industry is highly competitive with intense price competition and, as a result, we may be unable to compete successfully with other providers of contract drilling services that have greater resources than we have.
The offshore contract drilling industry is highly competitive with several industry participants, none of which has a dominant market share, and is characterized by high capital and maintenance requirements. Drilling contracts are traditionally awarded on a competitive bid basis. Price competition is often the primary factor in determining which qualified contractor is awarded the drilling contract, although drilling unit availability, location and suitability, the quality and technical capability of service and equipment, reputation and industry standing are key factors which are considered. Mergers among oil and natural gas exploration and production companies have reduced, and may from time to time further reduce the number of available customers, which would increase the ability of potential customers to achieve pricing terms favorable to them.
Many of our competitors are significantly larger than we are and have more diverse drilling assets and significantly greater financial and other resources than we have. In addition, because of our relatively small fleet, we may be unable to take advantage of economies of scale to the same extent as some of our larger competitors. Given the high capital requirements that are inherent in the offshore drilling industry, we may also be unable to invest in new technologies or expand in the future as may be necessary for us to succeed in this industry, while our larger competitors with superior financial resources, and in many cases less leverage than we have, may be able to respond more rapidly to changing market demands and compete more efficiently on price for drilling units employment. We may not be able to maintain our competitive position, and we believe that competition for contracts will continue to be intense in the future. Our inability to compete successfully may reduce our revenues and profitability.
An over-supply of drilling units may lead to a reduction in dayrates and therefore may materially impact our profitability.
During the recent period of high utilization and high dayrates, industry participants have increased the supply of drilling units by ordering the construction of new drilling units. Historically, this has resulted in an over-supply of drilling units and has caused a subsequent decline in utilization and dayrates when the drilling units enter the market, sometimes for extended periods of time until the units have been absorbed into the active fleet. According to industry sources, the worldwide fleet of floating rigs as of January 2018 consisted of 263 units, comprised of 147 semi-submersible rigs and 116 drillships. An additional 14 semi-submersible rigs and 29 drillships were under construction as of the same date, which would bring the total fleet to 306 floating rigs. The entry into service of these new, upgraded or reactivated drilling units will increase supply and has already led to a reduction in dayrates as drilling units are absorbed into the active fleet. In addition, the new construction of high-specification drilling units, as well as changes in our competitors' drilling unit fleets, could require us to make material additional capital investments to keep our fleet competitive. Lower utilization and dayrates could adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these drilling units may not be recoverable.
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Consolidation of suppliers may increase the cost of obtaining supplies, which may have a material adverse effect on our results of operations and financial condition.
We rely on certain third parties to provide supplies and services necessary for our operations, including, but not limited to, drilling equipment suppliers, catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. Such consolidation, combined with a high volume of drilling units under construction, may result in a shortage of supplies and services, thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time, or at all. These cost increases, delays or unavailability could have a material adverse effect on our results of operations and result in drilling unit downtime and delays in the repair and maintenance of our drilling units.
Our international operations involve additional risks, which could adversely affect our business.
We operate in various regions throughout the world. Our drilling unit, the Ocean Rig Corcovado, is operating offshore Brazil, the Ocean Rig Skyros is operating offshore Angola and the Leiv Eiriksson is operating offshore Norway. Our drilling unit the Ocean Rig Poseidon is in "ready-to-drill" state at Walvis Bay until commencement of the new drilling contract with Tullow Namibia Ltd. in the third quarter of 2018. The Ocean Rig Mykonos is scheduled to transit to Las Palmas where it will remain in "ready-to-drill" state. Our  remaining drilling units, the Eirik Raude, the Ocean Rig Olympia, the Ocean Rig Mylos, the Ocean Rig Paros, the Ocean Rig Apollo and the Ocean Rig Athena are cold stacked in Greece.
In the past, our drilling units have operated, among other locations, in the Gulf of Mexico and offshore Canada, Norway, the United Kingdom, Ghana, West Africa, Ivory Coast, offshore Greenland, Turkey, Ireland, west of the Shetland Islands, the Falkland Islands, Tanzania, the North Sea, Brazil, Greenland, Senegal, Angola and Congo, respectively. As a result of our international operations, we may be exposed to political and other uncertainties, including risks of:
terrorist and environmental activist acts, armed hostilities, war and civil disturbances;
acts of piracy, which have historically affected ocean-going vessels trading in regions of the world such as the South China Sea and in the Gulf of Aden off the coast of Somalia and which have generally increased significantly in frequency since 2008, particularly in the Gulf of Aden and off the west coast of Africa;
significant governmental influence over many aspects of local economies;
seizure, nationalization or expropriation of property or equipment;
repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
political unrest;
political corruption;
foreign and U.S. monetary policy, foreign exchange controls, potential repatriation of foreign currency, government debt downgrades and potential defaults and foreign currency fluctuations and devaluations;
the inability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
import-export quotas, wage and price controls, imposition of trade barriers;
regulatory or financial requirements to comply with foreign bureaucratic actions;
changing taxation policies, including confiscatory taxation and uncertainty in application of tax regulations;
other forms of government regulation and economic conditions that are beyond our control; and
governmental corruption.
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In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
the equipping and operation of drilling units;
repatriation of foreign earnings;
oil and gas exploration and development;
taxation of offshore earnings and earnings of expatriate personnel; and
use and compensation of local employees and suppliers by foreign contractors.
Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling units owned by their own citizens, (ii) the use of a local agent or local venture partner or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets.
Our business and operations involve numerous operating hazards.
Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch throughs, craterings, fires, explosions and pollution, including spills similar to the Deepwater Horizon oil spill, in which we were not involved. Contract drilling and well servicing require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, personnel shortages or failure of subcontractors to perform or supply goods or services.
Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, leaks and blowouts or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual indemnity rights with our customers may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all the risks to which we are exposed. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate drilling contracts, including pollution damage in connection with reservoir fluids stemming from operations under the contract, damage to the well or reservoir, loss of subsurface oil and gas and the cost of bringing the well under control. We generally indemnify our customers against pollution from substances in our control that originate from the drilling unit (e.g., diesel used onboard the unit or other fluids stored onboard the unit and above the water surface). However, our drilling contracts are individually negotiated, and the degree of indemnification we receive from the customer against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations. We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. However, pollution and environmental risks generally are not totally insurable. Furthermore, we have no insurance coverage for named storms in the Gulf of Mexico and while trading within war risks excluded areas.
The Deepwater Horizon oil spill in the Gulf of Mexico may result in more stringent laws and regulations governing deep-water drilling, which could have a material adverse effect on our business, operating results or financial condition.
On April 20, 2010, there was an explosion and a related fire on the Deepwater Horizon, an ultra-deep-water semi-submersible drilling unit that is not connected to us, while it was servicing the Macondo well in the Gulf of Mexico. This catastrophic event resulted in the death of 11 workers and the total loss of that drilling unit, as well as the release of large amounts of oil into the Gulf of Mexico, severely impacting the environment and the region's key industries. This event was investigated by several federal agencies, including the U.S. Department of Justice, and by the U.S. Congress, and the subject of numerous lawsuits. On January 11, 2011, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its final report, with recommendations for new regulations.
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We do not currently operate our drilling units in these regions, but we may do so in the future. In any event, changes to leasing and drilling activity requirements as a result of the Deepwater Horizon incident could have a substantial impact on the offshore oil and gas industry worldwide. All drilling activity in the U.S. Gulf of Mexico must be in compliance with enhanced safety requirements contained in the Notice to Lessees 2015-N01. Effective October 22, 2012 all drilling in the U.S. Gulf of Mexico must also comply with the Final Drilling Safety Rule as adopted on August 15, 2012, which enhances safety measures for energy development on the outer continental shelf.  Furthermore, on February 24, 2014, the U.S. Bureau of Ocean Energy Management, BOEM, proposed a rule increasing the limits of liability of damages for off-shore facilities under OPA based on inflation. This rule became effective in January 2015. Compliance with any new requirements of OPA may substantially impact our cost of operations or require us to incur additional expenses to comply with any new regulatory initiatives or statutes.  In April 2015, it was announced that new regulations are expected to be imposed in the U.S. regarding offshore oil and gas drilling and further, in April 2016 the U.S. Bureau of Safety and Environmental Enforcement (BSEE), announced a new Well Control Rule which required the use of certain safety equipment; however, pursuant to orders by the U.S. President in early 2017, the BSEE recently announced in August 2017 that this rule would be revised. In December 2015, the BSEE announced a new pilot inspection program for offshore facilities. Compliance with any new requirements of OPA may substantially impact our cost of operations or require us to incur additional expenses to comply with any new regulatory initiatives or statutes. Additional legislation or regulations applicable to the operation of our vessels that may be implemented in the future could adversely affect our business. In January 2018, the U.S. President unveiled a new proposal to lease new sections of U.S. waters to oil and gas companies for offshore drilling, vastly expanding the U.S. waters that are available for such activity over the next five years.  The effects of such proposal are currently unknown.
We are not able to predict the extent of future leasing plans or the likelihood, nature or extent of additional rulemaking. Nor are we able to predict when the BOEM will enter into leases with our customers or when the BSEE will issue drilling permits to our customers. We are not able to predict the future impact of these events on our operations. The current and future regulatory environment in the Gulf of Mexico could impact the demand for drilling units in the Gulf of Mexico in terms of overall number of drilling units in operations and the technical specification required for offshore drilling units to operate in the Gulf of Mexico. It is possible that short-term potential migration of drilling units from the Gulf of Mexico could adversely impact dayrates levels and fleet utilization in other regions. In addition, insurance costs across the industry have increased as a result of the Macondo well incident and certain insurance coverage has become more costly, less available, and not available at all from certain insurance companies.
Our insurance coverage may not adequately protect us from certain operational risks inherent in the drilling industry.
Our insurance is intended to cover normal risks in our current operations, including insurance against property damage, occupational injury and illness, loss of hire, certain war risks and third-party liability, including pollution liability. For example, the amount of risk we are subject to might increase regarding occupational injuries because on January 12, 2012, the U.S. Supreme Court ruled that the Longshore and Harbor Worker's Compensation Act, whose provisions are incorporated into the U.S. Outer Continental Shelf Lands Act could cover occupational injuries.
Insurance coverage may not, under certain circumstances, be available, and if available, may not provide sufficient funds to protect us from all losses and liabilities that could result from our operations. We have also obtained loss of hire insurance which becomes effective after 45 days of downtime with coverage that extends for approximately one year. This loss of hire insurance is recoverable only if there is physical damage to the drilling unit or equipment which is caused by a peril against which we are insured. The principal risks which may not be insurable are various environmental liabilities and liabilities resulting from reservoir damage caused by our gross negligence. Moreover, our insurance provides for premium adjustments based on claims and is subject to deductibles and aggregate recovery limits. In the case of pollution liabilities, our deductible is $10,000 per event and $250,000 for protection and indemnity claims brought before any U.S. jurisdiction. Our aggregate recovery limit is $500.0 million for all claims arising out of any event covered by our protection and indemnity insurance. Our deductible is $1.5 million per hull and machinery insurance claim. In addition, insurance policies which are extended to cover physical damage claims due to a named windstorm in the Gulf of Mexico generally require additional premium and impose strict recovery limits. Our insurance coverage may not protect fully against losses resulting from a required cessation of drilling unit operations for environmental or other reasons. Insurance may not be available to us at all or on terms acceptable to us, we may not maintain insurance or, if we are so insured, our policy may not be adequate to cover our loss or liability in all cases. The occurrence of a casualty, loss or liability against, which we may not be fully insured against, could significantly reduce our revenues, make it financially impossible for us to obtain a replacement drilling unit or to repair a damaged drilling unit, cause us to pay fines or damages which are generally not insurable and that may have priority over the payment obligations under our indebtedness or otherwise impair our ability to meet our obligations under our indebtedness and to operate profitably.
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If we enter into drilling contracts or engage in certain other activities with countries or government-controlled entities or customers associated with countries that are subject to restrictions imposed by the U.S. government, or engage in certain other activities, including entering into drilling contracts with individuals or entities in such countries that are not controlled by their governments or engaging in operations associated with such countries or entities pursuant to contracts with third parties unrelated to those countries or entities, our ability to conduct our business and access U.S. capital markets and our reputation and the market for our securities could be adversely affected.
Although none of our drilling units have operated during the year ending December 31, 2017 in countries subject to sanctions and embargoes imposed by the U.S. government and other authorities or countries identified by the U.S. government or other authorities as state sponsors of terrorism, including Iran, Sudan and Syria, in the future our drilling units may operate in these countries from time to time on our customers' instructions. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time. In 2010, the U.S. enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or CISADA, which amended the Iran Sanctions Act. Among other things, CISADA introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. In 2012, President Obama signed Executive Order 13608 which prohibits foreign persons from violating or attempting to violate, or causing a violation of any sanctions in effect against Iran or facilitating any deceptive transactions for or on behalf of any person subject to U.S. sanctions. Any persons found to be in violation of Executive Order 13608 will be deemed a foreign sanctions evader and will be banned from all contacts with the United States, including conducting business in U.S. dollars. Also in 2012, President Obama signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which created new sanctions and strengthened existing sanctions. Among other things, the Iran Threat Reduction Act intensifies existing sanctions regarding the provision of goods, services, infrastructure or technology to Iran's petroleum or petrochemical sector. The Iran Threat Reduction Act also includes a provision requiring the President of the United States to impose five or more sanctions from Section 6(a) of the Iran Sanctions Act, as amended, on a person the President determines is a controlling beneficial owner of, or otherwise owns, operates, or controls or insures a vessel that was used to transport crude oil from Iran to another country and (1) if the person is a controlling beneficial owner of the vessel, the person had actual knowledge the vessel was so used or (2) if the person otherwise owns, operates, or controls, or insures the vessel, the person knew or should have known the vessel was so used. Such a person could be subject to a variety of sanctions, including exclusion from U.S. capital markets, exclusion from financial transactions subject to U.S. jurisdiction, and exclusion of that person's vessels from U.S. ports for up to two years.
On July 14, 2015, the P5+1 and the EU announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran's Nuclear Program (the "JCPOA"), which is intended to significantly restrict Iran's ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and does not involve U.S. persons.  On January 16, 2016 ("Implementation Day"), the United States joined the EU and the UN in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency ("IAEA") that Iran had satisfied its respective obligations under the JCPOA.
U.S. sanctions prohibiting certain conduct that is now permitted under the JCPOA have not actually been repealed or permanently terminated at this time.  Rather, the U.S. government has implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders.  These sanctions will not be permanently "lifted" until the earlier of "Transition Day," set to occur on October 20, 2023, or upon a report from the IAEA stating that all nuclear material in Iran is being used for peaceful activities. On October 13, 2017, President Trump announced he would not certify Iran's compliance with the JCPOA.  This did not withdraw the U.S. from the JCPOA or re-instate any sanctions.  However, President Trump must periodically renew sanctions waivers and his refusal to do so could result in the reinstatement of certain sanctions currently suspended under the JCPOA.
Although we believe that we are in compliance with all applicable sanctions and embargo laws and regulations, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and conduct our business, and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the U.S. government as state sponsors of terrorism. The determination by these investors not to invest in, or to divest from, our common shares may adversely affect the price at which our common shares trades. Moreover, our customers may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us or our drilling units, and those violations could in turn negatively affect our reputation. In addition, our reputation and the market for our securities may be adversely affected if we engage in certain other activities, such as entering into drilling contracts with individuals or entities in countries subject to U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments. Investor perception of the value of our common shares may be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.
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The instability of the euro or the inability of Eurozone countries to refinance their debts could have a material adverse effect on our ability to fund our future capital expenditures or refinance our debt.
As a result of the credit crisis in Europe in recent years, in particular in Greece, Italy, Ireland, Portugal and Spain, the European Commission created the European Financial Stability Facility, or the EFSF, and the European Financial Stability Mechanism, or the EFSM, to provide funding to Eurozone countries in financial difficulties that seek such support. In March 2011, the European Council agreed on the need for Eurozone countries to establish a permanent stability mechanism, the European Stability Mechanism, or the ESM, which was activated by mutual agreement, and entered into force in 2013, and assumed the role of the EFSF and the EFSM in providing external financial assistance to Eurozone countries.
Despite these measures, concerns persist regarding the debt burden of certain Eurozone countries and their ability to meet future financial obligations and the overall stability of the euro. An extended period of adverse development in the outlook for European countries could make it difficult for current or potential lenders in the Eurozone to provide new loan facilities we may need to fund our future capital expenditures.
Governmental laws and regulations, including environmental laws and regulations, may add to our costs or limit our drilling activity.
Our business is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate. The offshore drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and, accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity. Our ability to compete in international contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. Offshore drilling in certain areas has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. For example, on December 20, 2016, the United States President invoked a law that banned offshore oil and gas drilling in large areas of the Arctic and the Atlantic Seaboard.  However, in January 2018, the current U.S. President unveiled a new proposal to lease new sections of U.S. waters to oil and gas companies for offshore drilling, vastly expanding the U.S. waters that are available for such activity over the next five years. The effects of such proposal are currently unknown.  Moreover, operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
To the extent new laws are enacted or other governmental actions are taken that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or the offshore drilling industry, in particular, our business or prospects could be materially adversely affected. The operation of our drilling units will require certain governmental approvals, the number and prerequisites of which cannot be determined until we identify the jurisdictions in which we will operate on securing contracts for the drilling units. Depending on the jurisdiction, these governmental approvals may involve public hearings and conditions that result in costly undertakings on our part. We may not obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to timely secure the necessary approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment. The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, operating results or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.
We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to numerous laws and regulations in the form of international conventions and treaties, national, state and local laws and national and international regulations in force in the jurisdictions in which our vessels operate or are registered, which can significantly affect the ownership and operation of our drilling units. These regulations include, but are not limited to, the International Maritime Organization, or IMO, International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended and generally referred to as MARPOL, including designation of Emission Control Areas, or ECAs, thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended and generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the IMO International Convention for the Safety of Life at Sea of 1974, as from time to time amended and generally referred to as SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the IMO International Convention on Load Lines of 1966, as from time to time amended, the International Convention for the Control and Management of Ships' Ballast Water and Sediments in February 2004, or the BWM Convention, the U.S. Oil Pollution Act of 1990, or OPA, requirements of the U.S. Coast Guard, or USCG, and the U.S. Environmental Protection Agency, or EPA, the U.S. Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Clean Water Act, or CWA, the U.S. Clean Air Act, or CAA, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, European Union regulations, and Brazil's National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Law (9966/2000) relating to pollution in Brazilian waters.
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Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or operational changes and may affect the resale value or useful lives of our vessels. Moreover, the manner in which these laws are enforced and interpreted is constantly evolving. We may also incur additional costs in order to comply with other existing and future regulatory obligations, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and insurance coverage or other financial assurance of our ability to address pollution incidents. These costs could have a material adverse effect on our business, results of operations, cash flows and financial condition. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations. Environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under OPA, for example, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil in U.S. waters, including the 200-nautical mile exclusive economic zone around the United States. An oil spill could result in significant liability, including fines, penalties and criminal liability and remediation costs for natural resource damages under other international and U.S. federal, state and local laws, as well as third-party damages. We are required to satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents and our insurance may not be sufficient to cover all such risks. As a result, claims against us could result in a material adverse effect on our business, results of operations, cash flows and financial condition.
Although our drilling units are separately owned by our subsidiaries, under certain circumstances a parent company and all of the ship-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under OPA or other environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
Our drilling units could cause the release of oil or hazardous substances, especially as our drilling units age. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where public interest groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to us, such as costs to upgrade our drilling units, clean up the releases, and comply with more stringent requirements in our discharge permits. Moreover, these releases may result in our customers or governmental authorities suspending or terminating our operations in the affected area, which could have a material adverse effect on our business, results of operation and financial condition.
If we are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases. In addition, we may not be able to obtain such indemnification agreements in the future.
Our insurance coverage may not be available in the future or we may not obtain certain insurance coverage. If it is available and we have the coverage, it may not be adequate to cover our liabilities. Any of these scenarios could have a material adverse effect on our business, operating results and financial condition.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, UNFCCC, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions.  International negotiations are continuing with respect to a successor to the Kyoto Protocol, which set emission reduction targets through 2012 and has been extended with new targets through 2020 pending negotiation of a new climate change treaty that would take effect in 2020. Restrictions on shipping emissions may be included in any new treaty. In December 2009, more than 27 nations, including the U.S. and China, signed the Copenhagen Accord, which includes a non-binding commitment to reduce greenhouse gas emissions.  The 2015 United Nations Climate Change Conference in Paris resulted in the Paris Agreement, which entered into force on November 4, 2016.  The Paris Agreement does not directly limit greenhouse gas emissions from ships.  On June 1, 2017, the U.S. President announced that it is withdrawing from the Paris Agreement.  The timing and effect of such action has yet to be determined.  At the IMO's Marine Environmental Protection Committee recent meetings "MEPC 70" and "MEPC 71", a draft outline of the structure of the initial strategy for developing a comprehensive IMO strategy on reduction of greenhouse gas emissions from ships was approved. In accordance with this roadmap, initial IMO strategy for reduction of greenhouse gas emissions needs to be developed by MEPC 72, which will be held in April 2018.  The IMO may implement market-based mechanisms to reduce greenhouse gas emissions from ships at the upcoming MEPC session.
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As of January 1, 2013, all ships (including drilling units) must comply with mandatory requirements adopted by the MEPC in July 2011 relating to greenhouse gas emissions. Currently operating ships are now required to develop and implement the Ship Energy Efficiency Management Plans, or SEEMPs, and the new ships to be designed in compliance with minimum energy efficiency levels per capacity mile as defined by the Energy Efficiency Design Index, or EEDI. Also, under these measures, by 2025 all new ships built will be 30% more efficient than those built in 2014. These requirements could cause us to incur additional compliance costs. The IMO is also considering the implementation of market-based mechanisms to reduce greenhouse gas emissions from ships.  Starting in January 2018, large ships (over 5,000 gross tons) calling at European ports are required to collect and publish data on carbon dioxide omissions.  In June 2013 the European Commission developed a strategy to integrate maritime emissions into the overall EU Strategy to reduced greenhouse gas emissions. For 2020, the EU made a unilateral commitment to reduce overall greenhouse gas emissions from its member states from 20% of 1990 levels. The EU also committed to reduce its emissions by 20% under the Kyoto Protocol's second period, from 2013 to 2020.
In the United States, the EPA has issued a finding that greenhouse gases endanger public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. However, in April 2017, the U.S. President signed an executive order to review and possibly eliminate the EPA's plan to cut greenhouse gas emissions. The outcome of this order is not yet known. The EPA enforces both the CAA and the international standards found in Annex VI of MARPOL concerning marine diesel engines, their emissions, and the sulfur content in marine fuel. Any passage of climate control legislation or other regulatory initiatives by the IMO, European Union, the U.S. or other countries where we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol, that restrict emissions of greenhouse gases could require us to make significant financial expenditures, including capital expenditures to upgrade our vessels, which we cannot predict with certainty at this time.
Because our business depends on the level of activity in the offshore oil and gas industry, existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and gas. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business.
Failure to comply with the U.S. Foreign Corrupt Practices Act and anti-bribery and anti-corruption regulations in other jurisdictions in which we operate could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.
We currently operate, and historically have operated, our drilling units outside of the United States in a number of countries throughout the world, including some with developing economies. Also, the existence of state or government-owned shipbuilding enterprises puts us in contact with persons who may be considered "foreign officials" under the U.S. Foreign Corrupt Practices Act of 1977, or the FCPA. We are committed to doing business in accordance with applicable anti-corruption laws and have adopted a code of business conduct and ethics which is consistent and in full compliance with the FCPA. We are subject, however, to the risk that we, our affiliated entities or our or their respective officers, directors, employees and agents may take actions determined to be in violation of such anti-corruption laws, including the FCPA and anti-corruption and anti-bribery laws in other jurisdictions in which we operate such as Brazil and the U.K. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Acts of terrorism and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism and political and social unrest, brought about by world political events or otherwise, have caused instability in the world's financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could increase and coverage may be unavailable in the future. U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future. Increased insurance costs or increased cost of compliance with applicable regulations may have a material adverse effect on our results of operations.
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Military action, other armed conflicts, or terrorist attacks have caused significant increases in political and economic instability in geographic regions where we operate and where our newbuilding drilling units are being constructed.
Military tension involving North and South Korea, the Middle East, Africa and other attacks, threats of attacks, terrorism and unrest, have caused instability or uncertainty in the world's financial and commercial markets and have significantly increased political and economic instability in some of the geographic areas where we operate and where we have contracted with a major shipyard in Korea, to build our two newbuilding drilling units. Acts of terrorism and armed conflicts or threats of armed conflicts in these locations could limit or disrupt our operations, including disruptions resulting from the cancellation of contracts or the loss of personnel or assets. In addition, any possible reprisals as a consequence of ongoing military action in the Middle East, such as acts of terrorism in the United States or elsewhere, could materially and adversely affect us in ways we cannot predict at this time.
Acts of piracy have recently increased in frequency, which could adversely affect our business.
Acts of piracy have historically affected ocean-going vessels trading in regions of the world such as the South China Sea, the Indian Ocean, off the coast of West Africa and in the Gulf of Aden off the coast of Somalia. Although the frequency of sea piracy worldwide decreased during 2012 to its lowest level since 2009, sea piracy incidents continue to occur, particularly in the Gulf of Aden off the coast of Somalia and increasingly in the Gulf of Guinea. If these piracy attacks result in regions in which our drilling units are deployed being characterized as "war risk" zones by insurers, or Joint War Committee "war and strikes" listed areas, premiums payable for such coverage could increase significantly and such insurance coverage may be more difficult to obtain. In addition, crew costs, including due to employing onboard security guards, could increase in such circumstances. We may not be adequately insured to cover losses from these incidents, which could have a material adverse effect on us. In addition, any detention hijacking as a result of an act of piracy against our drilling units, or an increase in cost, or unavailability, of insurance for our vessels, could have a material adverse impact on our business, financial condition and results of operations.
The U.S. government recently imposed legislation concerning the deteriorating situation in Somalia, including acts of piracy offshore Somalia. On April 13, 2010, the President of the United States issued an Executive Order, which we refer to as the Order, prohibiting, among other things, the payment of monies to or for the benefit of individuals and entities on the list of Specially Designated Nationals, or SDNs, published by U.S. Department of the Treasury's Office of Foreign Assets Control. Certain individuals associated with piracy offshore Somalia are currently designated persons under the SDN list. The Order is applicable only to payments by U.S. persons and not by foreign entities, such as Ocean Rig UDW Inc. Notwithstanding this fact, it is possible that the Order, and the regulations promulgated thereunder, may affect foreign private issuers to the extent that such foreign private issuers provide monies, such as ransom payments to secure the release of crews and ships in the event of detention hijackings, to any SDN for which they seek reimbursement from a U.S. insurance carrier. While additional regulations relating to the Order may be promulgated by the U.S. government in the future, we cannot predict what effect these regulations may have on our operations.
Hurricanes may impact our ability to operate our drilling units in the Gulf of Mexico or other U.S. coastal waters, which could reduce our revenues and profitability.
Hurricanes Ivan, Katrina, Rita, Gustav, Ike, Harvey and Maria caused damage to a number of drilling units unaffiliated with us in the U.S. Gulf of Mexico. Drilling units that moved off their locations during the hurricanes damaged platforms, pipelines, wellheads and other drilling units. BOEM and the BSEE, the U.S. organizations that issue a significant number of relevant guidelines for the drilling units' activities, had guidelines for tie-downs on drilling units and permanent equipment and facilities attached to outer continental shelf production platforms, and moored drilling unit fitness during hurricane season. These guidelines effectively imposed requirements on the offshore oil and natural gas industry in an attempt to increase the likelihood of survival of offshore drilling units during a hurricane. The guidelines also provided for enhanced information and data requirements from oil and natural gas companies that operate properties in the Gulf of Mexico region of the Outer Continental Shelf. BOEM and BSEE may issue similar guidelines for future hurricane seasons and may take other steps that could increase the cost of operations or reduce the area of operations for our ultra-deepwater drilling units, thereby reducing their marketability. Implementation of new guidelines or regulations that may apply to ultra-deepwater drilling units may subject us to increased costs and limit the operational capabilities of our drilling units. Our drilling units do not currently operate in the Gulf of Mexico or other U.S. coastal waters but may do so in the future.
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Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
New technologies may cause our current drilling methods to become obsolete, resulting in an adverse effect on our business.
The offshore contract drilling industry is subject to the introduction of new drilling techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies, we may be placed at a competitive disadvantage and competitive pressures may force us to implement new technologies at substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to benefit from technological advantages and implement new technologies before we can. We may not be able to implement technologies on a timely basis or at a cost that is acceptable to us.
Risks Relating to Our Company
We have indebtedness, and may incur substantial additional indebtedness, which could adversely affect our financial health.

As of December 31, 2017, on a consolidated basis, we had $450.0 million in aggregate principal amount of indebtedness outstanding, excluding the Ocean Rig Apollo credit facility.
Our current and future indebtedness could have significant adverse consequences for an investment in us and on our business and future prospects, including the following:

we may not be able to satisfy our financial obligations under our indebtedness and our contractual and commercial commitments, which may result in possible defaults on and acceleration of such indebtedness;
we may not be able to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;
we may not be able to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;
we could become more vulnerable to general adverse economic and industry conditions, including increases in interest rates, particularly given our substantial indebtedness, some of which bears interest at variable rates;
our ability to refinance indebtedness may be limited or the associated costs may increase;
less leveraged competitors could have a competitive advantage because they have lower debt service requirements and, as a result, we may not be better positioned to withstand economic downturns;
we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our competitors and our management's discretion in operating our business may be limited; and
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Each of these factors may have a material and adverse effect on our financial condition and viability. Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating income is not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. Any or all of these actions may be insufficient to allow us to service our debt obligations. Further, we may not be able to effect any of these remedies on satisfactory terms, or at all.
The international nature of our operations may make the outcome of any bankruptcy proceedings difficult to predict.
We are domiciled in the Cayman Islands and all but four of our subsidiaries are incorporated in the Republic of the Marshall Islands and certain other countries other than the United States. Practically all of our assets and those of our subsidiaries are located outside the United States, and we conduct operations in countries around the world. Consequently, in the event of any bankruptcy, insolvency or similar proceedings involving us or one of our subsidiaries, bankruptcy laws other than those of the United States could apply. We have limited operations in the United States. If we become a debtor under the United States bankruptcy laws, bankruptcy courts in the United States may seek to assert jurisdiction over all of our assets, wherever located, including property situated in other countries. There can be no assurance, however, that we would become a debtor in the United States or that a United States bankruptcy court would be entitled to, or accept, jurisdiction over such bankruptcy case or that courts in other countries that have jurisdiction over us and our operations would recognize a United States bankruptcy court's jurisdiction if any other bankruptcy court would determine it had jurisdiction.
We may incur additional debt, which could exacerbate the risks associated with our substantial leverage.
Even with our existing level of debt, we and our subsidiaries may incur additional indebtedness in the future. Although the terms of our existing debt agreement, and any future debt agreements we enter into, will limit our ability to incur additional debt, these terms may not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances. If new debt is added to our and our subsidiaries' current debt levels, the related risks that we and they now face could intensify and could further exacerbate the risks associated with our substantial leverage.
The agreements and instruments governing our indebtedness contain restrictions and limitations that could significantly impact our ability to operate our business.
Our secured credit facility, and future financial obligations may impose, certain operating and financial restrictions on us. These restrictions may prohibit or otherwise limit our ability to, among other things:
enter into other financing arrangements;
incur or guarantee additional indebtedness;
create or permit liens on our assets;
consummate a merger, consolidation or sale of our drilling units or the shares of our subsidiaries;
make investments;
change the general nature of our business;
pay dividends, redeem capital shares or subordinated indebtedness or make other restricted payments;
incur dividend or other payment restrictions affecting our restricted subsidiaries;
change the management and/or ownership of our drilling units;
enter into transactions with affiliates;
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transfer or sell assets;
amend, modify or change our organizational documents;
make capital expenditures; and
compete effectively to the extent our competitors are subject to less onerous restrictions.
In addition, our existing secured credit facility require us to maintain and satisfy various financial covenants, including (i) delivery of financial statements, reports, accountants' letters, certificates and SEC filings; (ii) notices of defaults, material litigation and other material events; (iii) continuation of business and maintenance of existence and material rights and privileges; (iv) compliance with laws, including sanctions laws; and (v) maintenance of property and insurance. Any future credit agreement or amendment or debt instrument we enter into may contain similar or more restrictive covenants. Events beyond our control, including changes in the economic and business conditions in the deepwater offshore drilling market in which we operate, may affect our ability to comply with these ratios and covenants. Our ability to maintain compliance will also depend substantially on the value of our assets, our dayrates, our ability to obtain drilling contracts, our success at keeping our costs low and our ability to successfully implement our overall business strategy. We cannot guarantee that we would be able to obtain our lenders' waiver or consent with respect to any noncompliance with the specified financial ratios and financial covenants under our various credit facilities or future financial obligations or that we would be able to refinance any such indebtedness in the event of default.
These restrictions, ratios and financial covenants in our debt agreements could limit our ability to fund our operations or capital needs, make acquisitions or pursue available business opportunities, which in turn may adversely affect our financial condition. A violation of any of these provisions could result in a default under our existing and future debt agreements which could allow all amounts outstanding thereunder to be declared immediately due and payable. An acceleration thereunder would likely in turn trigger cross-acceleration and cross-default rights under the terms of our indebtedness outstanding at such time. If the amounts outstanding under our indebtedness were to be accelerated or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. Furthermore, if our assets are foreclosed upon, we will not have any income-producing assets left, and as such, we may not be able to generate any cash flow in the future.
We may be unable to secure ongoing drilling contracts for any of the drilling units in our fleet, including for our four operating drilling units that have contracts scheduled to expire between the second quarter of 2018 and the third quarter of 2021.
Our future financial and operating performance will be affected by a range of economic, financial, competitive, regulatory, business and other factors that we cannot control, such as general economic and financial conditions in the offshore drilling industry or the economy generally. In particular, our ability to generate steady cash flow will depend on our ability to secure drilling contracts at acceptable rates. Assuming no exercise of any options to extend the terms of our existing drilling contracts, the contracts of our four operating drilling units expire between the second quarter of 2018 and the third quarter of 2021.
We cannot guarantee that we will be able to secure employment for any of the drilling units in our fleet, including the expiration or early termination of the drilling contracts for our four drilling units currently operating. Our ability to renew our existing drilling contracts will depend on prevailing market conditions. We cannot guarantee we will be able to enter into new drilling contracts upon the expiration or termination of the contracts we have in place or at all or that there will not be a gap in employment between our current drilling contracts and subsequent contracts. In particular, if the price of crude oil is low, or it is expected that the price of crude oil will decrease in the future, at a time when we are seeking to arrange employment contracts for our drilling units, we may not be able to obtain employment contracts at attractive rates or at all.
If the rates we receive for the reemployment of our drilling units upon the expiration or termination of our existing drilling contracts are lower than the rates under our existing contracts, we will recognize less revenue from the operations of our drilling units. In addition, delays under existing drilling contracts could cause us to lose future contracts if a drilling unit is not available to start work at the agreed date. Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drilling units at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. If the oil and gas companies do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, including for the seventh generation drilling units under construction, or we may be forced to enter into drilling contracts at unattractive dayrates. Either of these events could impair our ability to generate sufficient cash flow to make principal and interest payments under our indebtedness and meet our capital expenditure and other obligations.
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We may be unable to secure ongoing drilling contracts for the Ocean Rig Olympia, the Eirik Raude, the Ocean Rig Apollo, the Ocean Rig Mylos, the Ocean Rig Paros and the Ocean Rig Athena, our uncontracted drilling units that are cold stacked, or the Ocean Rig Mykonos, our uncontracted drilling unit that is scheduled to transit to Las Palmas where it will remain in "ready-to-drill" state or for our drilling units under construction.
We cannot guarantee that we will be able to secure employment for any of the drilling units in our fleet, including our other drilling units that are uncontracted and are either cold stacked or "ready to drill".  Our ability to renew our existing drilling contracts or obtain new drilling contracts for our drilling units, including the six uncontracted stacked drilling units and the seventh generation drilling units under construction for which we have not yet secured employment will depend on prevailing market conditions. In addition, the counterparties to our existing drilling contracts may seek to renegotiate the terms of such contracts with us.  For example, we are currently in discussions with Total E&P Angola Block 32 for the Ocean Rig Skyros contract to revise its commercial terms. While these discussions may lead to no change to the existing contract terms, to a "blend" and extend arrangement, or to a termination according to the termination for convenience provisions of the contract, they may also lead to contract terms that are less favorable than the terms in our existing drilling contracts, which could, among other things, negatively impact our cash flows and results of operations.  
Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drilling units at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. If the oil and gas companies do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, including for the seventh generation drilling units under construction, or we may be forced to enter into drilling contracts at unattractive dayrates. Either of these events could impair our ability to generate sufficient cash flow to make principal and interest payments under our indebtedness and meet our capital expenditure and other obligations.
We may be unable to secure ongoing drilling contracts for the Ocean Rig Santorini and the Ocean Rig Crete, which are currently scheduled for delivery in June 2018 and January 2019, respectively.
Due to strong competition, in the market we also cannot guarantee that we will be able to secure employment for the Ocean Rig Santorini and the Ocean Rig Crete which are currently scheduled for delivery in June 2018 and January 2019, respectively, if we decide to go ahead with the construction and accept delivery of the two drilling unit newbuildings. If we determine not to go forward with the construction of these rigs we may forfeit all installment payments that we have made to the yard in the amount of $466.3 million.
Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drilling units at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. If the oil and gas companies do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, including for the seventh generation drilling units under construction, or we may be forced to enter into drilling contracts at unattractive dayrates. Either of these events could impair our ability to generate sufficient cash flow to make principal and interest payments under our indebtedness and meet our capital expenditure and other obligations.
Any drilling contracts that we enter into may not provide sufficient cash flow to meet our operating expenses, or debt service obligations with respect to our indebtedness.
If the rates we receive for the reemployment of our drilling units upon the expiration or termination of our existing drilling contracts are lower than the rates under our existing contracts, we will recognize less revenue from the operations of our drilling units. If our operating cash flows are insufficient to service our debt and to fund our other liquidity needs, we may be forced to take actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing our indebtedness, seeking additional capital, or any combination of the foregoing. We cannot assure you that any of these actions could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on our outstanding indebtedness and to fund our other liquidity needs. Also, the terms of existing or future debt agreements may restrict us from pursuing any of these actions. Furthermore, reducing or delaying capital expenditures or selling assets could impair future cash flows and our ability to service our debt in the future.
Construction of drilling units is subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
We have entered into contracts with a major shipyard in Korea, for the construction of three seventh generation drilling units, which were previously scheduled for delivery in 2017, 2018 and 2019, respectively. As part of renegotiations, the delivery of the Ocean Rig Santorini and the Ocean Rig Crete were postponed to June 2018 and January 2019, respectively, certain installments were rescheduled and the total construction costs were increased to $694.8 million and $709.6 million, respectively.
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With respect to the Ocean Rig Santorini, our subsidiary that holds the shipbuilding contract for the Ocean Rig Santorini has received a notice of default in February 2018 for failure to pay an interim installment that was due on February 5, 2018, and is currently in commercial discussions with the shipyard to further postpone the delivery of the drilling unit and amend other terms of the shipbuilding contract. Should our subsidiary that holds the shipbuilding contract and the shipyard fail to renegotiate terms while in default, the contract could be rescinded by the shipyard and all installment payments paid by us in the amount of $309.4 million to date could be forfeited. In addition, if we are unable to fund the amounts due in connection with the delivery of the Ocean Rig Crete, the yard may rescind the shipyard contract and we would forfeit all amounts we have already paid to the yard in the amount of $156.9 million.

With respect to the Ocean Rig Amorgos, we had previously agreed to suspend its construction with an option, subject to our option, to bring it back into force within a period of 18 months after the date of the addendum, which option expired in February 2018.
 From time to time in the future, we may undertake additional new construction projects and conversion projects. In addition, we may make significant upgrade, refurbishment, conversion and repair expenditures for our fleet from time to time, particularly as our drilling units become older. Some of these expenditures are unplanned. These projects together with our existing construction projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:
shipyard unavailability;
shortages of equipment, materials or skilled labor for completion of repairs or upgrades to our equipment;
unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;
financial or operating difficulties experienced by equipment vendors or the shipyard;
unanticipated actual or purported change orders;
local customs strikes or related work slowdowns that could delay importation of equipment or materials;
engineering problems, including those relating to the commissioning of newly designed equipment;
design or engineering changes;
latent damages or deterioration to the hull, equipment and machinery in excess of engineering estimates and assumptions;
work stoppages;
client acceptance delays;
weather interference, storm damage or other events of force majeure;
disputes with shipyards and suppliers;
shipyard failures and difficulties;
failure or delay of third-party equipment vendors or service providers;
unanticipated cost increases; and
difficulty in obtaining necessary permits or approvals or in meeting permit or approval conditions.
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These factors may contribute to cost variations and delays in the delivery of our ultra-deepwater newbuilding drilling units. Delays in the delivery of these newbuilding drilling units or the inability to complete construction in accordance with their design specifications may, in some circumstances, result in a delay in drilling contract commencement, resulting in a loss of revenue to us, and may also cause customers to renegotiate, terminate or shorten the term of a drilling contract for the drilling unit pursuant to applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms or at all. Additionally, capital expenditures for drilling unit upgrades, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our drilling units that may undergo upgrade, refurbishment and repair may not earn a dayrate during the periods they are out of service. In addition, in the event of a shipyard failure or other difficulty, we may be unable to enforce certain provisions under our newbuilding contracts such as our refund guarantee, to recover amounts paid as installments under such contracts. The occurrence of any of these events may have a material adverse effect on our results of operations, financial condition or cash flows. In the event of a default, we may also incur additional costs and liability to the shipyards, which may pursue claims against us for damages under our newbuilding construction contracts and retain and sell our seventh generation drilling units to third parties.
In the event the major shipyard in Korea does not perform under its agreements with us and we are unable to enforce certain refund guarantees, we may lose all or part of our investment, which would have a material adverse effect on our results of operations, financial condition and cash flows. Similarly failure by us to honor our commitments under these shipbuilding contracts would result in events of default and affect our results of operations, financial condition and cash flows.
As of March 12, 2018, we had paid an aggregate of $466.3 million to the major shipyard in Korea in connection with two of our seventh generation drilling units (the Ocean Rig Santorini and the Ocean Rig Crete) which were previously scheduled for delivery in 2017 and 2018, respectively. As part of renegotiations, the delivery of the two drilling units was postponed to June 2018 and January 2019, respectively. If we decide to go ahead with the construction of the two drilling unit newbuildings, the estimated remaining total construction payments, excluding financing costs, will amount to approximately $0.9 billion in aggregate. If we are unable to fund these obligations we may forfeit some or all of the installment payments made to the yard in the amount of $466.3 million. The one drilling unit newbuilding the Ocean Rig Amorgos we had previously agreed to suspend its construction with an option, subject to our option, to bring it back into force within a period of 18 months after the date of the addendum, which option expired in February 2018.
In the event the major shipyard in Korea does not perform under its agreements with us and we are unable to enforce certain refund guarantees with third party bankers due to an outbreak of war, bankruptcy or otherwise, we may lose all or part of our investment, which would have a material adverse effect on our results of operations, financial condition and cash flows. Similarly failure by us to honor our commitments under these shipbuilding contracts would result in events of default and would require us to certain default payments plus interest, including charges and expenses incurred by the shipyard as a direct consequence of the default. Upon default, the shipyard would be entitled to retain installments already paid by us, the cost of supplies already delivered to the shipyard and other claims for damages.

With respect to the Ocean Rig Santorini, our subsidiary that holds the shipbuilding contract for the Ocean Rig Santorini has received a notice of default in February 2018 for failure to pay an interim installment that was due on February 5, 2018, and is currently in commercial discussions with the shipyard to further postpone the delivery of the drilling unit and amend other terms of the shipbuilding contract. To date, our subsidiary has paid $309.4 million in installment payments under the shipbuilding contract. Under the contract, our subsidiary must pay the amount of installments in default plus accrued interest thereon at a rate of 6% per annum. Should our subsidiary that holds the shipbuilding contract and the shipyard fail to renegotiate terms while in default, the contract could be rescinded by the shipyard and all installment payments paid by us in the amount of $309.4 million to date could be forfeited.

 As such, events of default under the shipbuilding contracts for our newbuildings would adversely affect our results of operations, financial condition and cash flows.
As our current operating fleet is comprised of 11 drilling units of which three drilling units are currently employed and one has signed a new drilling contract and is scheduled to commence employment in the third quarter of 2018, we rely heavily on a small number of customers and the loss of a significant customer could have a material adverse impact on our financial results.
As of December 31, 2017, we had five customers for our current total fleet of 11 drilling units. Our two largest customers represented 40% and 33% of our revenues during the fiscal year ended December 31, 2017, respectively, and these two customers represented, 73% of our revenues during the year ended December 31 2017. If our customers terminate, suspend or seek to renegotiate the drilling contracts for drilling units, as they are entitled to do under various circumstances, or cease doing business with us, our results of operations and cash flows will likely be adversely affected. We expect that a limited number of customers will continue to generate a substantial portion of our revenues for the foreseeable future.
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Currently, our revenues depend on 11 drilling units. The damage or loss of any of our drilling units could have a material adverse effect on our results of operations and financial condition.
Our revenues are dependent on the Leiv Eiriksson, which is operating offshore Norway, our drilling unit, the Ocean Rig Corcovado, which is operating offshore Brazil, the Ocean Rig Skyros which is operating offshore Angola, the Ocean Rig Poseidon which is in "ready-to-drill" state at Walvis Bay until commencement of the new drilling contract with Tullow Namibia Ltd. in the third quarter of 2018 and the Ocean Rig Mykonos, which is scheduled to transit to Las Palmas where it will remain in "ready-to-drill" state, while the Eirik Raude, the Ocean Rig Olympia, the Ocean Rig Mylos, the Ocean Rig Athena, the Ocean Rig Paros and the Ocean Rig Apollo are currently uncontracted and cold stacked.
Our drilling units may be exposed to risks inherent in deepwater drilling and operating in harsh environments that may cause damage or loss. The drilling of oil and gas wells, particularly exploratory wells where little is known of the subsurface formations involves risks, such as extreme pressure and temperature, blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch throughs, craterings, fires, explosions, pollution and natural disasters such as hurricanes and tropical storms.
In addition, offshore drilling operations are subject to perils peculiar to marine operations, either while on-site or during mobilization, including capsizing, sinking, grounding, collision, marine life infestations, and loss or damage from severe weather. The replacement or repair of a drilling unit could take a significant amount of time, and we may not have any right to compensation for lost revenues during that time. As long as we have only five drilling units in operation (including the two drilling units which are in "ready-to-drill" state), loss of or serious damage to one of the drilling units could materially reduce our revenues for the time that drilling unit is out of operation. In view of the sophisticated design of the drilling units, we may be unable to obtain a replacement unit that could perform under the conditions that our drilling units are expected to operate, which could have a material adverse effect on our results of operations and financial condition.
Our future contracted revenue for our fleet of drilling units may not be ultimately realized.

As of March 12, 2018, the future contracted revenue for our fleet of operating drilling units, or our contract backlog, was approximately $847.5 million under firm commitments. We may not be able to perform under our drilling contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our drilling contracts for various reasons, including adverse conditions, resulting in lower daily rates. We are currently in discussions with Total E&P Angola Block 32 for the Ocean Rig Skyros contract to revise its commercial terms. These discussions may lead to, among other things, no change to the existing contract term, to a "blend" and extend arrangement, or termination according to the termination for convenience provisions of the contract. Our inability or the inability of our customers, to perform under the respective contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

We are subject to certain risks with respect to our counterparties, including under our drilling contracts, and failure of these counterparties to meet their obligations could cause us to suffer losses or otherwise adversely affect our business.
From time to time, we enter into drilling services contracts with our customers, newbuilding contracts with shipyards, interest rate swap agreements and forward exchange contracts, and have employed and may employ our drilling units and newbuild drilling units on fixed-term and well contracts. Our drilling contracts, newbuilding contracts, and hedging agreements subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control and may include, among other things, general economic conditions, the condition of the offshore contract drilling industry, the overall financial condition of the counterparty, the dayrates received for specific types of drilling units and various expenses. In addition, in depressed market conditions, our customers may no longer need a drilling unit that is currently under contract or may be able to obtain a comparable drilling unit at a lower dayrate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. Should a counterparty fail to honor its obligations under an agreement with us, we could sustain significant losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Most of our offshore drilling contracts may be terminated early due to certain events.
Under most of our current drilling contracts, our customers have the right to terminate the drilling contract upon the payment of an early termination or cancellation fee. However, such payments may not fully compensate us for the loss of the contract.
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In addition, our drilling contracts permit our customers to terminate the contracts early without the payment of any termination fees under certain circumstances, including as a result of major non-performance, longer periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to piracy or force majeure events beyond our control.  In addition, during periods of challenging market conditions, our customers may no longer need a drilling unit that is currently under contract or may be able to obtain a comparable drilling unit at a lower dayrate. As a result, we may be subject to an increased risk of our clients seeking to renegotiate the terms of their existing contracts or repudiate their contracts, including through claims of non-performance. Our customers' ability to perform their obligations under their drilling contracts with us may also be negatively impacted by the prevailing uncertainty surrounding the development of the world economy and the credit markets. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.
If our drilling units fail to maintain their class certification or fail any annual survey or special survey or fail to meet performance standards under each respective drilling contracts, that drilling unit would be unable to operate, thereby reducing our revenues and profitability and violating certain covenants under certain of our debt agreements.
Every drilling unit must be "classed" by a classification society. The classification society certifies that the drilling unit is "in-class," signifying that such drilling unit has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling unit's country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned.  Three of our drilling units are certified as being "in class" by Det Norske Veritas, one of our drillings units is certified as being "in class" by Bureau Veritas while the remaining six are certified as being "in class" by American Bureau of Shipping. The Leiv Eiriksson was credited with completing its last Special Periodical Survey in June 2016 and the Eirik Raude completed the same in December 2012, while their next Special Periodical Survey is scheduled for 2021 and 2017, respectively. However, due to the fact that the Eirik Raude is stacked, class layup has been applied and therefore it will be done as part of its reactivation. Our sixth-generation operating drilling units, Ocean Rig Corcovado, Ocean Rig Poseidon and Ocean Rig Mykonos are due for their second Special Periodical Surveys in 2020, 2020 and 2021 respectively. Our one operating seventh generation drilling unit, Ocean Rig Skyros, is due for its' first Special Periodical Survey in 2018. The stacked drilling units are due for their next Special Periodical Surveys in 2018, 2019, 2020, however, they are class laid up and therefore will be done as part of their reactivation.
Each drilling contract under which the drilling units are employed require certain standards of performance from each unit. Should the unit fail to meet such standards, the contracts could be rescinded by the customer.
 If any drilling unit does not maintain its class and/or fails any annual survey or special survey or fails to meet its performance standards under its drilling contract, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable, which could cause us to be in violation of certain covenants in certain of our debt agreements. Any such inability to carry on operations or be employed, or any such violation of covenants, could have a material adverse impact on our financial condition and results of operations.
Our drilling units, including our seventh generation drilling units under construction following their delivery to us, may suffer damage and we may face unexpected yard costs, which could adversely affect our cash flow and financial condition.
If our drilling units, including our seventh generation drilling units under construction following their delivery to us, suffer damage, they may need to be repaired at a yard. The costs of yard repairs are unpredictable and can be substantial. The loss of earnings while our drilling units are being repaired and repositioned, as well as the actual cost of these repairs, would decrease our earnings. We may not have insurance that is sufficient to cover all or any of these costs or losses and may have to pay dry docking costs not covered by our insurance.
We may not be able to maintain or replace our drilling units as they age.
The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our existing drilling units to compete effectively in the market, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement drilling units.
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We may have difficulty managing our planned growth properly.
We intend to continue to grow our fleet. Our future growth will primarily depend on our ability to:
locate and acquire suitable drilling units;
identify and consummate acquisitions or joint ventures;
enhance our customer base;
locate and retain suitable personnel for our fleet;
manage our expansion; and
obtain required financing on acceptable terms.
Growing any business by acquisition presents numerous risks, such as undisclosed liabilities and obligations, the possibility that indemnification agreements will be unenforceable or insufficient to cover potential losses and difficulties associated with imposing common standards, controls, procedures and policies, obtaining additional qualified personnel, managing relationships with customers and integrating newly acquired assets and operations into existing infrastructure. We may experience operational challenges as we begin operating our new drilling units which may result in low earnings efficiency and/or reduced dayrates compared to maximum dayrates. We may be unable to successfully execute our growth plans or we may incur significant expenses and losses in connection with our future growth which would have an adverse impact on our financial condition and results of operations.
The market value of our current drilling units, and any drilling units we may acquire in the future, including our seventh generation drilling units under construction upon their delivery to us, may decrease, which could cause us to incur losses if we decide to sell them following a decline in their values.
If the offshore contract drilling industry suffers further adverse developments in the future, the fair market value of our drilling units may further decline. The fair market value of the drilling units we currently own or may acquire in the future may increase or decrease depending on a number of factors, including:
prevailing level of drilling services contract dayrates;
general economic and market conditions affecting the offshore contract drilling industry, including competition from other offshore contract drilling companies;
types, sizes and ages of drilling units;
supply and demand for drilling units;
costs of newbuildings;
governmental or other regulations; and
technological advances.
In the future, if the market values of our drilling units deteriorate significantly, we may be required to record an impairment charge in our financial statements, which could adversely affect our results of operations. If we sell any drilling unit when drilling unit prices have fallen and before we have recorded an impairment adjustment to our financial statements, the sale may be at less than the drilling unit's carrying amount on our financial statements, resulting in a loss. As a result of the impairment for the year ended December 31, 2017, it was determined that the carrying amount of one drilling unit was not recoverable and, therefore, a charge of $473.3 million was recognized, the impairment of the total advances and related costs provided to the yard, amounting to $573.2 million for the Ocean Rig Crete and the Ocean Rig Santorini and impairment of $2.3 million relating to the reclassification of the drilling units Leiv Eiriksson and Eirik Raude as held and used (previously held for sale) was recognized and included in the "Impairment loss" in the consolidated statement of operations of our financial statements.
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Because we generate most of our revenues in U.S. Dollars, but incur a significant portion of our employee salary and administrative and other expenses in other currencies, exchange rate fluctuations could have an adverse impact on our results of operations.
Our principal currency for our operations and financing is the U.S. Dollar. A substantial portion of the operating dayrates for the drilling units, our principal source of revenues, are quoted and received in U.S. Dollars; however, a portion of our revenue under our contracts is receivable in Brazilian Real and Angolan Kwanza. The principal currency for operating expenses is also the U.S. Dollar; however, a significant portion of employee salaries and administration expenses, as well as parts of the consumables and repair and maintenance expenses for the drilling units, may be paid in Norwegian Kroner (NOK), Great British Pounds (GBP), Canadian dollars (CAD), Euros (EUR) or other currencies depending in part on the location of our drilling operations. For the year ended December 31, 2017, approximately 56% of our expenses were incurred in currencies other than the U.S. Dollars. This exposure to foreign currency could lead to fluctuations in net income and net revenue due to changes in the value of the U.S. Dollar relative to the other currencies. Revenues paid in foreign currencies against which the U.S. Dollar rises in value can decrease, resulting in lower U.S. Dollar denominated revenues. Expenses incurred in foreign currencies against which the U.S. Dollar falls in value can increase, resulting in higher U.S. Dollar denominated expenses. We have employed derivative instruments in order to economically hedge our currency exposure; however, we may not be successful in hedging our future currency exposure and our U.S. Dollar denominated results of operations could be materially and adversely affected upon exchange rate fluctuations determined by events outside of our control.
We are dependent upon key management personnel.
Our operations depend to a significant extent upon the abilities and efforts of our key management personnel, as well as our Manager TMS Offshore Ltd or TMS Offshore, a Company that may be deemed to be beneficially owned by Mr. Economou, the Chairman of our Board of Directors. The loss of our key management personnel's or TMS Offshore Services to us, could adversely affect our efforts to obtain employment for our drilling units and discussions with our lenders and, therefore, could adversely affect our business prospects, financial condition and results of operations. We do not currently, nor do we intend to, maintain "key man" life insurance on any of our personnel.
Failure to attract or retain key personnel, labor disruptions or an increase in labor costs could adversely affect our operations.
We require highly skilled personnel to operate and provide technical services and support for our business in the offshore drilling sector worldwide. As of December 31, 2017, we employed 1,160 employees, the majority of whom are full-time crew employed on our drilling units. Under certain of our employment contracts, we are required to have a minimum number of local crew members on our drilling units. We will need to recruit additional qualified personnel as we take delivery on our newbuilding drilling units. Competition for the labor required for drilling operations has intensified as the number of drilling units activated, added to worldwide fleets or under construction has increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover. If turnover increases, we could see a reduction in the experience level of our personnel, which could lead to higher downtime, more operating incidents and personal injury and other claims, which in turn could decrease revenues and increase costs. In response to these labor market conditions, we are increasing efforts in our recruitment, training, development and retention programs as required to meet our anticipated personnel needs. If these labor trends continue, we may experience further increases in costs or limits on our offshore drilling operations.
Currently, our employees in Brazil and Norway are covered by collective bargaining agreements. In the future, some of our employees or contracted labor may be covered by collective bargaining agreements in certain jurisdictions. As part of the legal obligations in some of these agreements, we may be required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals could be working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance. Labor disruptions could hinder our operations from being carried out normally and if not resolved in a timely cost-effective manner, could have a material impact our business. If we choose to cease operations in one of those countries or if market conditions reduce the demand for our drilling services in such a country, we would incur costs, which may be material, associated with workforce reductions.
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Our operating and maintenance costs with respect to our offshore drilling units will not necessarily fluctuate in proportion to changes in operating revenues, which may have a material adverse effect on our results of operations, financial condition and cash flows.
Operating revenues may fluctuate as a function of changes in supply of offshore drilling units and demand for contract drilling services, which, in turn, affect dayrates and the utilization and performance of our drilling units. However, costs for operating drilling units are generally fixed regardless of the dayrate being earned. Therefore, our operating and maintenance costs with respect to our offshore drilling units will not necessarily fluctuate in proportion to changes in operating revenues. In addition, should our drilling units incur idle time between contracts, we typically will not de-man those drilling units but rather use the crew to prepare the units for its next contract. During times of reduced activity, reductions in costs may not be immediate, as portions of the crew may be required to prepare drilling units for stacking, after which time the crew members are assigned to active drilling units or dismissed. In addition, as our drilling units are mobilized from one geographic location to another, labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are incurred. If we experience increased operating costs without a corresponding increase in earnings, this may have a material adverse effect on our results of operations, financial condition and cash flows.
The derivative contracts we may enter into to hedge our exposure to fluctuations in interest rates could result in higher than market interest rates and charges against our income.

We recognize fluctuations in the fair value of interest rate swap and cap floor agreements in our statement of operations. In addition, our financial condition could be materially adversely affected to the extent we do not hedge our exposure to interest rate fluctuations under our financing arrangements, under which loans have been advanced at a floating rate based on LIBOR and for which we have not entered into an interest rate swap or other hedging arrangement. Any hedging activities we engage in may not effectively manage our interest rate exposure or have the desired impact on our financial conditions or results of operations. As of December 31, 2017, we had no interest rate swap and cap and floor agreements. Please refer to the discussion on financial instruments and fair value measurements of our audited consolidated financial statements.

An increase in interest rates would increase the cost of servicing our indebtedness and could reduce our profitability.
We may also incur indebtedness in the future with variable interest rates. As a result, an increase in market interest rates would increase the cost of servicing our indebtedness and could materially reduce our profitability and cash flows. The impact of such an increase would be more significant for us than it would be for some other companies because of our substantial indebtedness.
A cyber-attack could materially disrupt our business.
We rely on information technology systems and networks in our operations and administration of our business. Our business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to unauthorized release of information or alteration of information in our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.
A change in tax laws, treaties or regulations, or their interpretation, of any country in which we operate could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.
We conduct our worldwide drilling operations through various subsidiaries. Tax laws and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate. Our income tax expense is based upon our interpretation of tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, treaties or regulations, or in the interpretation thereof, or in the valuation of our deferred tax assets, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings, and such change could be significant to our financial results. If any tax authority successfully challenges our operational structure, inter-company pricing policies or the taxable presence of our operating subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, particularly in the United States, Canada, the U.K., Brazil, Angola, Cyprus, Ghana, Netherlands, Ivory Coast, Tanzania, Falkland Islands, Ireland, Congo, Senegal, Equatorial Guinea or Norway, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from our operations could be materially adversely affected.
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Our subsidiaries are subject to taxation in the jurisdictions in which their offshore drilling activities are conducted. Such taxation results in decreased earnings available to our shareholders.
United States tax authorities may treat us as a "passive foreign investment company" for United States federal income tax purposes, which may have adverse tax consequences to U.S. shareholders.
A foreign corporation will be treated as a "passive foreign investment company," or PFIC, for U.S. federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50% of the average value of the corporation's assets produce or are held for the production of those types of "passive income". For purposes of these tests, "passive income" includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties other than rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute "passive income." U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC and the gain, if any, they derive from the sale or other disposition of their shares in the PFIC.
We do not believe that we are currently a PFIC, although we may have been a PFIC for certain prior taxable years. Based on our current operations and future projections, we do not believe that we have been, are, or will be a PFIC with respect to any taxable year beginning with the 2009 taxable year.
However, no assurance can be given that the U.S. Internal Revenue Service, or IRS, or a court of law will accept our position, and there is a risk that the IRS or a court of law could determine that we or one of our subsidiaries is a PFIC. Moreover, no assurance can be given that we or one of our subsidiaries would not constitute a PFIC for any future taxable year if there were to be changes in the nature and extent of its operations.
If the IRS were to find that we are or have been a PFIC for any taxable year, our U.S. shareholders will face adverse U.S. tax consequences.  Under the PFIC rules, unless those shareholders make an election available under the Code (which election could itself have adverse consequences for such shareholders, as discussed below under "Taxation—U.S. Federal Income Tax Considerations"), such shareholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of the common shares, as if the excess distribution or gain had been recognized ratably over the shareholder's holding period of the common shares. In the event that our shareholders face adverse U.S. tax consequences as a result of investing in our common shares, this could adversely affect our ability to raise additional capital through the equity markets.  See "Taxation—U.S. Federal Income Tax Considerations" for a more comprehensive discussion of the U.S. federal income tax consequences to U.S. shareholders if we are treated as a PFIC.
Our business restructuring efforts may not attain their desired objectives.

We completed a financial restructuring of our balance sheet in September 2017. As a result of the restructuring, a total of $99.1 million in restructuring charges has been recorded in the fiscal year ended December 31, 2017. Restructuring charges are recorded primarily in "Reorganization gain, net" and thus adversely affect our net income/ (loss) attributable to our stockholders as detailed in Note 2 and Note 9 of our audited consolidated financial statements.
Due to internal or external factors, efficiencies and cost savings from the restructuring may not be realized as scheduled and, even if those benefits are realized, we may not be able to achieve the level of profitability expected due to market conditions worsening beyond our expectations. The inability to fully and successfully implement our restructuring initiatives may adversely affect our operating results and financial condition.
We may be subject to litigation that, if not resolved in our favor and not sufficiently insured against, could have a material adverse effect on us.
We are and may be, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment matters, governmental claims for taxes or duties, and other litigation, including such litigation that arises in the ordinary course of our business and/or in connection with the Restructuring. We cannot predict with certainty the outcome or effect of any claim or other litigation matter, and the ultimate outcome of any litigation or the potential costs to resolve them may have a material adverse effect on us. Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent and policies may not be located. See "Item 8.  Financial Information -- A. Consolidated statements and other financial information – Legal Proceedings."
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Investor confidence may be adversely impacted if we are unable to comply with Section 404 of the Sarbanes-Oxley Act of 2002.
We have implemented procedures in order to meet the evaluation requirements of Rules 13a-15(c) and 15d-15(c) under the Securities Exchange Act of 1934, or the Exchange Act, for the assessment under Section 404 of the Sarbanes-Oxley Act of 2002, or Section 404. Section 404 requires us to include in our annual reports on Form 20-F (i) our management's report on, and assessment of, the effectiveness of our internal controls over financial reporting and (ii) our independent registered public accounting firm's attestation to and report on the effectiveness of our internal controls over financial reporting in our annual report. If we fail to maintain the adequacy of our internal controls over financial reporting, we will not be in compliance with all of the requirements imposed by Section 404. Any failure to comply with Section 404 could result in an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which ultimately could harm our business.
We are domiciled in the Cayman Islands and most of our subsidiaries are incorporated in the Republic of the Marshall Islands, which does not have a well-developed body of corporate law, and as a result, shareholders may have fewer rights and protections under Marshall Islands law than under a typical jurisdiction in the United States.
Our corporate affairs are governed by our second amended and restated memorandum and articles of association (as may be amended from time to time), the Companies Law (2016 Revision) of the laws of the Cayman Islands (as may be amended from time to time), and the common law of the Cayman Islands. The rights of shareholders to take legal action against our directors and us, actions by minority shareholders and the fiduciary responsibilities of our directors to us under Cayman Islands law are to a large extent governed by the common law of the Cayman Islands. The common law of the Cayman Islands is derived in part from judicial precedent in the Cayman Islands as well as from English common law, which has persuasive, but not binding, authority on a court in the Cayman Islands. It should be noted that because the Cayman Islands law has no legislation specifically dedicated to the rights of investors in securities, and thus no statutorily defined private causes of action to investors in securities such as those found under the Securities Act or the Exchange Act in the United States, it provides significantly less statutory protection to investors.

The corporate affairs of many of our subsidiaries are governed by the Marshall Islands Business Corporations Act, or the BCA. The provisions of the BCA resemble provisions of the corporation laws of a number of states in the United States. However, there have been few judicial cases in the Republic of the Marshall Islands interpreting the BCA. The rights and fiduciary responsibilities of directors under the law of the Republic of the Marshall Islands are not as clearly established as the rights and fiduciary responsibilities of directors under statutes or judicial precedent in existence in certain United States jurisdictions. Shareholders' rights may differ as well. While the BCA does specifically incorporate the non-statutory law, or judicial case law, of the State of Delaware and other states with substantially similar legislative provisions, shareholders may have more difficulty in protecting their interests in the face of actions by management, directors or controlling shareholders than would shareholders of a corporation incorporated in a United States jurisdiction.

It may not be possible for investors to enforce U.S. judgments against us.
All but four of our subsidiaries are incorporated in jurisdictions outside the United States and a substantial portion of our assets and those of our subsidiaries are located outside the United States. In addition, all but two of our directors and officers reside outside the United States and a substantial portion of the assets of our directors and officers are located outside the United States. As a result, it may be difficult or impossible for U.S. investors to serve process within the United States upon us, our subsidiaries or our directors and officers or to enforce a judgment against us for civil liabilities in U.S. courts. In addition, you should not assume that courts in the countries in which we or our subsidiaries are incorporated or where our assets or the assets of our subsidiaries and directors and officers are located (i) would enforce judgments of U.S. courts obtained in actions against us or our subsidiaries and directors and officers based upon the civil liability provisions of applicable U.S. federal and state securities laws or (ii) would enforce, in original actions, liabilities against us or our subsidiaries and directors and officers based on those laws.  There is no statutory recognition in the Cayman Islands of judgments obtained in the U.S., although the courts of the Cayman Islands will generally recognize and enforce a monetary judgment of a foreign court of a competent jurisdiction without retrial on the merits, which: (a)  is final; (b)  is not in respect of taxes, a fine or a penalty; (c) was not obtained in a manner and is not of a kind the enforcement of which is contrary to natural justice or the public policy of the Cayman Islands
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We depend on officers and directors who are associated with related parties which may create conflicts of interest.
Our officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our shareholders. However, our Chairman of the Board Mr. George Economou, may be deemed to beneficially own TMS Offshore, with which we signed a management services agreement on September 22, 2017 to provide certain management services related to our drilling units including but not limited to executive management, commercial, financing, accounting, reporting, information technology, legal, manning, insurance, catering and superintendency services. These services may have conflicts of interest in matters involving or affecting us and our customers or shareholders. The resolution of these conflicts may not always be in our best interest or that of our shareholders and could have a material adverse effect on our business, results of operations, cash flows and financial condition.
See "Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions". If any of these conflicts of interest are not resolved in our favor, this could have a material adverse effect on our business.
Our executive officers do not devote all of their time to our business, which may hinder our ability to operate successfully.

Mr. Pankaj Khanna, our President and Chief Executive Officer, Mr. Iraklis Sbarounis, our Chief Financial  Officer, Mr. David Cusiter, our Chief Operations Officer and certain other officers who perform executive officer functions for us, are not required to work full-time on our affairs and are involved in business activities not related to us, which may result in their spending less time than is appropriate or necessary to manage our business successfully.  While we estimate that certain of our executive officers may spend a substantial portion of their monthly business time on business activities not related to our business, the actual allocation of time could vary significantly from time to time depending on various circumstances and needs of the other businesses, such as the relative levels of strategic activities of such businesses. As a result, there could be material competition for the time and effort of our officers who also provide services to other businesses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are a "foreign private issuer", which could make our common shares less attractive to some investors or otherwise harm our stock price.

We are a "foreign private issuer," as such term is defined in Rule 405 under the Securities Act.  As a "foreign private issuer" the rules governing the information that we disclose differ from those governing U.S. corporations pursuant to the Securities and Exchange Act of 1934, as amended, or the Exchange Act. We are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant events within four days of their occurrence. In addition, our officers and directors are exempt from the reporting and "short-swing" profit recovery provisions of Section 16 of the Exchange Act and related rules with respect to their purchase and sales of our securities. Our exemption from the rules of Section 16 of the Exchange Act regarding sales of ordinary shares by insiders means that you will have less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. Moreover, we are exempt from the proxy rules, and proxy statements that we distribute will not be subject to review by the SEC. Accordingly there may be less publicly available information concerning us than there is for other U.S. public companies.  These factors could make our common shares less attractive to some investors or otherwise harm our stock price.
Risks Relating to Our Common Shares
We cannot assure you that an active and liquid public market for our common shares will continue.
Our common shares commenced "regular way" trading on the NASDAQ Global Select Market on October 6, 2011 and commenced trading in the Norwegian OTC market maintained by the Norwegian Security Dealers Association in December 2010. In the past we received written notifications from NASDAQ, indicating that because the closing bid price of the Company's common shares for 30 consecutive business days, was below the minimum $1.00 per share bid price requirement for continued listing on the Nasdaq Global Select Market, the Company is not in compliance with Nasdaq Listing Rule 5550(a)(2) which we have since cured. We cannot assure you that we will be able to maintain the minimum bid price level in the future. Also, we cannot assure you that an active and liquid public market for our common shares will continue.
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Since 2008, the U.S. stock market has experienced extreme price and volume fluctuations. In addition, the offshore drilling industry has been highly unpredictable and volatile. If the volatility in the market or the offshore drilling industry continues or worsens, it could have an adverse effect on the market price of our common shares and may impact a potential sale price if holders of our common shares decide to sell their shares. The market price of our common shares may be influenced by many factors, many of which are beyond our control, including those described above in "—D. Risk Factors" and market reaction to any of the following:
the final terms of any comprehensive deleveraging plan that we seek to implement;
actual or anticipated variations in our operating results;
changes in our cash flow, EBITDA or earnings estimates;
changes in the price of oil;
publication of research reports about us or the industry in which we operate;
increases in market interest rates that may lead purchasers of common shares to demand a higher expected yield which, would mean our share price would fall;
changes in applicable laws or regulations, court rulings and enforcement and legal actions;
changes in market valuations of similar companies;
announcements by us or our competitors of significant contracts, acquisitions or capital commitments;
increased indebtedness we incur in the future;
additions or departures of key personnel;
actions by institutional shareholders or other key stakeholders;
speculation in the press or investment community;
terrorist attacks;
economic and regulatory trends; and
general market conditions.
As a result of these and other factors, investors in our common shares may not be able to resell their shares at or above the price they paid for such shares or at all. These broad market and industry factors may materially reduce the market price of our common shares, regardless of our operating performance.
Future issuances of our common shares could have an adverse effect on our share price.
In order to finance the currently contracted and future growth of our fleet, we will have to incur substantial additional indebtedness and possibly issue additional equity securities. Future common share issuances, directly or indirectly through convertible or exchangeable securities, options or warrants, will generally dilute the ownership interests of our existing common shareholders, including their relative voting rights, and could require substantially more cash to maintain the then existing level, if any, of our dividend payments to our common shareholders, as to which no assurance can be given. Preferred shares, if issued, will generally have a preference on dividend payments, which could prohibit or otherwise reduce our ability to pay dividends to our common shareholders. Our debt will be senior in all respects to our common shares, will generally include financial and operating covenants with which we must comply and will include acceleration provisions upon defaults thereunder, including our failure to make any debt service payments, and possibly under other debt. Because our decision to issue equity securities or incur debt in the future will depend on a variety of factors, including market conditions and other matters that are beyond our control, we cannot predict or estimate the timing, amount or form of our capital raising activities in the future, but such activities could cause the price of our common shares to decline significantly. Furthermore, we expect that any comprehensive deleveraging plan will result in the issuance of equity to our existing creditors, which will cause significant dilution to current shareholders and the price of our common shares to decline significantly.
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Our Principal Shareholders (defined below) each have a substantial ownership stake in us, and their interests could conflict with the interests of our other shareholders.

Our principal shareholders, or Principal Shareholders,  include certain funds managed by Avenue Capital Group, BlueMountain Capital Management, LLC, Elliott Funds, Canyon Capital Advisors LLC, Pacific Investment Management Company LLC and Oz Management LP and an entity that may be deemed to be beneficially owned by George Economou, and as of the date of this annual report, they each own 7.76, 10.8% 20.2%, 7.7%, 5.5%, 5.1% and 9.3%, respectively, of our total shares outstanding. George Economou, Blue Mountain Capital Management LLC, Elliott Funds and Avenue Capital are represented on our Board of Directors, and each of Blue Mountain Capital Management LLC, Elliott Funds and Avenue Capital has also appointed non-voting observers to our Board. As a result of this substantial ownership interest and, as applicable, their participation on the Board of Directors, our Principal Shareholders currently have the ability to influence certain actions requiring shareholders' approval, including increasing or decreasing the authorized share capital, the election of directors, declaration of dividends, the appointment of management, and other policy decisions. While future transactions with our Principal Shareholders could potentially benefit us, their interests may at times conflict with the interests of the Company and our other shareholders. Conflicts of interest may arise between us and our Principal Shareholders or their affiliates, which may result in the conclusion of transactions on terms not determined by market forces or favorable to us. Any such conflicts of interest could adversely affect our business, financial condition and results of operations, and the trading price of our common shares. Moreover, the concentration of ownership may delay, deter or prevent acts that would be favored by the Company or our other shareholders, including potential opportunities to receive a premium for their shares as part of a sale of our business. Similarly, this concentration of share ownership may adversely affect the trading price of our shares because investors may perceive disadvantages in owning shares in a company with concentrated ownership.  In addition, holders of more than 10% of our common shares are entitled to customary demand and piggyback registration rights of their common shares with under the Securities Act.  Any actual sales or the perceived selling of our common shares by our Principal Shareholders could have a negative impact on the trading price of our common stock. See "Item 7. Major Shareholders and Related Party Transactions".
Under our Second Amended and Restated Memorandum and Articles of Association, certain "Major Actions" require the approval of a majority of the Lender Directors which vests substantial control in the Lender Directors.

Until the Termination Date, the Company will not, and will not permit any of the Group Companies (as defined below) to take certain actions unless such action has been expressly approved by the board of directors, which approval must include at least two of the Lender Directors, or the Majority Lender Directors. These actions include, among other actions as set forth in the Second Amended and Restated Memorandum and Articles of Association:
·
the issuance of our common shares or other securities, or the redemption of any equity interests;
·
the payment of dividends, if any, on our common shares;
·
the incurrence or modification of debt;
·
amendments to the Second Amended and Restated Memorandum and Articles of Association;
·
the entering into of certain extraordinary transactions;
·
commitments to construct or the construction of, any new vessel, or any purchase or acquisition of any vessel;
·
the adoption of, amendment or modification to, termination of, or waiver of any provision under, any equity incentive plan, bonus incentive plan, severance plan, or employee benefit plan;
·
the grant or award of any severance, equity or non-cash bonus entitlement to any director, officer or employee of the Company or any of its subsidiaries, or any amendment to or waiver of any term of any such grant or award;
·
the entering into of any Related Party Transaction other than a Permitted Related Party Transaction (as defined below), or the amendment, modification or termination of any Related Party Transaction (as defined below) (including any Permitted Related Party Transaction); and
·
the exercise of any termination rights and remedies under, the amendment, modification or supplement of, or the waiver of any provision under, the Management Services Agreement.

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As of March 12, 2018 our Chairman, Mr. George Economou, was deemed to beneficially own 8,525,596, or approximately 9.3% of our outstanding common shares. The common shares beneficially owned by Mr. Economou are "restricted securities" within the meaning of Rule 144 under the U.S. Securities Act of 1933, as amended, or the Securities Act, and may not be transferred unless they have been registered under the Securities Act or an exemption from registration is available. Upon satisfaction of certain conditions, Rule 144 permits the sale of certain amounts of restricted securities six months following the date of acquisition of the restricted securities from us. As our common shares become eligible for sale under Rule 144, the volume of sales of our common shares on applicable securities markets may increase, which could reduce the market value of our common shares.
Anti-takeover provisions contained in our organizational documents could make it difficult for our shareholders to replace or remove our current board of directors or have the effect of discouraging, delaying or preventing a merger or acquisition, which could adversely affect the market price of our securities.
Several provisions of our second amended and restated memorandum and articles of association (the "Second Amended and Restated Memorandum and Articles of Association") could make it difficult for hostile shareholders to change the composition of our board of directors, preventing them from changing the composition of management. In addition, the same provisions may discourage, delay or prevent a merger or acquisition that shareholders may consider favorable.
These provisions include:
authorizing our board of directors to issue "blank check" preferred shares without shareholder approval;
limiting the persons who may call special meetings of shareholders; and
establishing advance notice requirements for nominations for election to our board of directors or for proposing matters that can be acted on by shareholders at shareholder meetings.
Under the Second Amended and Restated Memorandum and Articles of Association, the right to remove a director will be limited to the persons entitled to designate such director or for cause by either the affirmative vote of at least two-thirds of the board of directors or at least two of the Lender Directors until the Termination Date. Following the Termination Date, the Second Amended and Restated Memorandum and Articles of Association will authorize the removal of directors only for cause and only upon the affirmative vote of the holders of a majority of the outstanding Class A common shares entitled to vote generally in the election of directors. Further, upon the Termination Date, the board of directors will be divided into three classes with staggered, three-year terms and cumulative voting in the election of directors will be prohibited.

In addition, prior to the Termination Date, if we are approached by or otherwise receive an Acquisition Proposal, as defined in the Second Amended and Restated Memorandum and Articles of Association, from one or more potential purchasers or any of their respective representatives:

• we and TMS Offshore Services Ltd., our manager, will be required to deliver such Acquisition Proposal (or, in the case of an Acquisition Proposal provided orally, a written summary thereof) to the Lender Directors, and all amendments, modifications and supplements thereto, in each case promptly, and in no event later than two business days, following its receipt thereof;

the Lender Directors will have the power and authority to direct us and the board of directors to, as promptly as practicable, bring such Acquisition Proposal to a vote of the shareholders, without any recommendation to reject such proposal from us, the board of directors or any other person unless approved by the Lender Directors; and

if such Acquisition Proposal is approved by the affirmative vote of holders of a majority of the then-outstanding shares, we will be required to use commercially reasonable efforts to pursue and consummate such Acquisition Proposal and all shareholders will become subject to certain drag-along rights to be held by the Lender Directors. See "Description of Share Capital—Description of Common Shares—Drag-Along Rights."

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These provisions may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common shares.


Item 4.          Information on the Company
A.          History and Development of the Company
Ocean Rig UDW Inc. is an exempted company incorporated with limited liability under the laws of the Cayman Islands.  We were initially organized in the Republic of the Marshall Islands on December 10, 2007 under the name Primelead Shareholders Inc., as a subsidiary of DryShips Inc. (Nasdaq:DRYS), a company founded by our Chairman Mr. Economou in which two of our directors currently serve as directors and officers.  Following our partial spin off from DryShips to its existing shareholders, our shares commenced trading on the NASDAQ Global Select Market under the symbol "ORIG" on October 6, 2011. As of April 5, 2016, DryShips no longer holds any equity interests in our Company and no registrable securities under the registration rights agreement we entered into with DryShips on March 20, 2012 remain outstanding. As of April 14, 2016, we redomiciled from the Republic of the Marshall Islands to the Cayman Islands. Each of our drilling units is owned by a separate wholly-owned vessel-owning subsidiary.
We maintain our principal executive offices at c/o Ocean Rig Cayman Management Services SEZC Limited, 3rd Floor Flagship Building, Harbour Drive, Grand Cayman, Cayman Islands. Our telephone number is +1 345 327 9232. Our website address is www.ocean-rig.com. Information contained on our website does not constitute part of this annual report.
Restructuring
On March 23, 2017, we and certain of our subsidiaries, Drillships Financing Holding Inc., or DFH, Drillships Ocean Ventures Inc., or DOV, and Drill Rigs Holdings Inc., or DRH, which are collectively referred to as the Scheme Companies entered into a Restructuring Support Agreement (the "RSA"), with certain creditors of our then-outstanding consolidated indebtedness to implement a financial restructuring plan, (the "Restructuring") under Section 86 of the Companies Law (2016 Revision). Pursuant to the terms of the RSA, the Scheme Companies presented winding up petitions to the Grand Court of the Cayman Islands (the "Grand Court"), on March 24, 2017, and filed applications seeking the appointment of joint provisional liquidators ("the JPLs"), under section 104(3) of the Companies Law (2016) Revision. On March 27, 2017, following a hearing before the Grand Court, the JPLs were appointed in respect to each of the Scheme Companies.
The RSA proposed that the Restructuring of each of the Scheme Companies be effected by way of a scheme of arrangement under Cayman Islands law (the "Schemes"). The Schemes provided for substantial deleveraging of the Scheme Companies through an exchange by their creditors, or the Scheme Creditors, of approximately $3.7 billion principal amount of debt (plus accrued interest) for new equity of the Company, approximately $288 million in cash (excluding the early consent fee) and $450 million of new secured debt.
On March 27, 2017, the JPLs as "foreign representatives" of each of the Scheme Companies filed petitions with the U.S. Bankruptcy Court under Chapter 15 of the Bankruptcy Code seeking recognition of the provisional liquidation proceedings and the contemplated Schemes as "foreign main proceedings." On April 3, 2017, the U.S. Bankruptcy Court granted provisional relief extending the protections of the temporary restraining order pending a recognition hearing, which was held on August 16, 2017. Following the recognition hearing, the U.S. Bankruptcy Court granted an order granting recognition to the provisional liquidation proceedings and the Schemes, pursuant to the terms sought by the JPLs.
On July 20, 2017, the Grand Court gave permission to the Scheme Companies to convene meetings of the Scheme Creditors for the purpose of considering, and if found appropriate, approving the Schemes.
On August 11, 2017, the Scheme Meetings were held and each of the Schemes was approved by a majority in number of the Scheme Creditors holding at least 75% in value of claims present and voting at the respective Scheme Meeting. The Schemes were approved by Scheme Creditors holding over 97% of our then-outstanding indebtedness.
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On August 22, 2017, the JPLs filed an application for an order of the U.S. Bankruptcy Court recognizing and giving full force and effect to the Schemes in the United States. Following the sanction of the Schemes by the Grand Court, a hearing was held before the U.S. Bankruptcy Court on September 20, 2017 to consider the relief requested in the JPLs' application. Shortly after the conclusion of this hearing, the U.S. Bankruptcy Court entered an order giving full force and effect to the Grand Court's orders, the Schemes, and all documents and other agreements related thereto.
On August 25, 2017, the U.S. Bankruptcy Court issued a memorandum opinion and an order granting recognition of the provisional liquidation and scheme of arrangement proceedings for us and our subsidiaries, DRH, DFH, and DOV pending in the Grand Court as foreign main proceedings, and of the JPLs as the foreign representatives of the Scheme Companies in the United States. If the Schemes were approved by the Cayman Court, the U.S. Bankruptcy Court would conduct a hearing on September 20, 2017, to consider the entry of an order giving full force and effect to the Schemes in the United States.
On September 15, 2017, following a hearing held between September 4, 2017 and September 6, 2017, the Grand Court issued orders sanctioning the Schemes. On September 21, 2017, canceled 22,222,222 of its treasury shares and 56,079,533 shares of the Company previously held by its subsidiary, Ocean Rig Investments Inc. On the same day, we effected a 1-for-9,200 reverse stock split of our then-outstanding common shares. Our common shares commenced trading on a split-adjusted basis on September 22, 2017. The reverse stock split reduced the number of our issued and outstanding common shares from 82,586,851 shares (including the aforementioned treasury shares and shares held by Ocean Rig Investments, Inc.) to approximately 8,975 shares and affected all issued and outstanding common shares. The number of our authorized common shares and the par value and other terms of our common shares were not affected by the reverse stock split. No fractional shares were issued in connection with the reverse stock split. Shareholders of record who would have otherwise been entitled to receive a fractional share as a result of the reverse stock split received a cash payment in lieu thereof. The reverse stock split was completed in connection with our Restructuring and in order to comply with NASDAQ's listing requirements and meet the minimum bid requirement for continued listing on NASDAQ's Global Select Market.
Successful Emergence from Restructuring
On September 22, 2017, which we refer to as the Restructuring Effective Date, the Restructuring took effect. Pursuant to the Schemes, on the Restructuring Effective Date, Scheme Creditors exchanged their existing claims against the respective Scheme Companies for cash, new debt and new equity issued by the Company, as outlined above. The existing claims were either transferred to our Company or released. In particular, Scheme Creditors or their nominees received shares equivalent to 90.68% of the post-Restructuring equity of our Company and aggregate cash consideration of $320.8 million (including the early consent fee) across all of the Schemes, and the Scheme Companies and certain subsidiaries entered into a new credit agreement with the DOV and DFH Scheme Creditors (the "New Credit Agreement"). The New Credit Agreement contains limited restrictive covenants that are customary for facilities of this type. The remaining 9.32% of post-Restructuring equity was issued to Prime Cap Shipping Inc., a company that may be deemed to be beneficially owned by the Company's Chairman, Mr. George Economou, pursuant to the management services agreement with TMS Offshore Services Ltd. as described below.
On September 26, 2017, we received formal notice from NASDAQ that we had demonstrated compliance with all applicable requirements for the continued listing of the Company's common shares on NASDAQ and confirmed that, as a result of its favorable determination, our common shares would continue to be listed on the Nasdaq Global Select Market.
On October 4, 2017, the Grand Court issued an order discharging the JPLs effective as of October 18, 2017.
Recent Developments

Effective January 1, 2018 our Board of Directors appointed Mr. Pankaj Khanna as President and Chief Executive Officer of the Company, Mr. Iraklis Sbarounis as Chief Financial Officer, Mr. David Cusiter as Chief Operations Officer and Mr. Anthony Kandylidis as Executive Vice Chairman of our Company.

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During January 2018 and February 2018, we converted an aggregate of 349,711 Class B Common Shares, par value $0.01 (the "Class B Common Shares"), into 349,711 Class A Common Shares, par value $0.01 (the "Class A Common Shares"). Pursuant to our Second Amended and Restated Memorandum and Articles of Association each Class B Common Share is convertible once, at any time or from time to time, in each case, at the option of the respective holder, into a Class A Common Share at a one for one conversion ratio.
On January 12, 2018, Lundin Norway AS ("Lundin") declared its sixth option to extend the existing contract of the Leiv Eiriksson, which is now expected to have firm employment secured until August 2018. Should Lundin exercise its remaining six one-well options, the rig could be employed until the second half of 2019.
On February 7, 2018, the drilling rig Leiv Eiriksson commenced its shipyard stay at Olen, Norway where it will undergo certain enhancements related to its contract with Lundin, its intermediate survey and upgrade its BOP to 5-rams. The Leiv Eiriksson is expected to complete its yard stay by the end of the first quarter of 2018.

On February 23, 2018, the Company signed a new drilling contract with Tullow Namibia Ltd., for a one-well drilling program plus options for drilling offshore West Africa. The contract is expected to commence in the third quarter of 2018 and to be performed by the Ocean Rig Poseidon.

On March 5, 2018, we held our 2018 annual general meeting of shareholders.

Our drilling contract of the Ocean Rig Poseidon with Statoil, for a one-well drilling program offshore Tanzania, has been successfully completed. The Ocean Rig Poseidon is in Walvis Bay, where it will remain in "ready-to-drill" state and be actively marketed for employment until commencement of the new drilling contract with Tullow Namibia Ltd. in the third quarter of 2018 .

Our drilling unit the Ocean Rig Mykonos, which is expected to complete her current drilling contract with Petrobras during March 2018, is planned to transit to Las Palmas, where it will remain in "ready-to-drill" state, and be actively marketed for employment. During the Ocean Rig Mykonos stay in Las Palmas, the unit will be fitted with a full Managed Pressure Drilling (MPD) package.


We are currently in discussions with Total E&P Angola Block 32 for the Ocean Rig Skyros contract to revise its commercial terms. These discussions may lead to no change to the contract, to a blend and extend arrangement, or termination according to the termination for convenience provisions of the contract.
Capital Expenditures
During the year ended December 31, 2015, our principal capital expenditures related to the construction expenses of the Ocean Rig Apollo, which was delivered in March 2015 with a total cost of approximately $727.7 million, the Ocean Rig Santorini, the Ocean Rig Crete and the Ocean Rig Amorgos. During the year ended December 31, 2016, our principal capital expenditures related to the purchase of the Ocean Rig Paros which was acquired through an auction on April 28, 2016 for a purchase price of $65.0 million and the construction expenses of the Ocean Rig Santorini and the Ocean Rig Crete.  For more information on our seventh generation drilling units, please see "—B. Business Overview— Newbuilding drilling units and Options to Purchase Newbuilding Drilling Units." During the year ended December 31, 2016, we had paid an aggregate of $542.9 million to a major shipyard in Korea in connection with our three unfinanced seventh generation drilling units which were previously scheduled for delivery in 2017, 2018 and 2019, respectively. As part of renegotiations, the Ocean Rig Santorini and the Ocean Rig Crete are currently scheduled for delivery in June 2018 and January 2019, respectively, certain installments were rescheduled and the total construction costs were increased to $694,790 and $709,565, respectively. If we decide to go ahead with the construction of the two drilling unit newbuildings, the estimated remaining total construction payments, excluding financing costs, will amount to approximately $0.9 billion in aggregate. With respect to the Ocean Rig Amorgos, we had previously agreed to suspend its construction with an option, subject to our option, to bring it back into force within a period of 18 months after the date of the addendum, which option expired in February 2018. In addition, during the year ended December 31, 2016, the Company impaired the total advances and related costs provided to the yard for the Ocean Rig Amorgos. During the year ended December 31, 2017, the Company determined that the full amount of the carrying value of the two drilling units under construction Ocean Rig Crete and Ocean Rig Santorini was not recoverable and, therefore, impaired their total advances and related costs provided to the yard. If we decide to go ahead with the construction of the two drilling unit newbuildings, we plan to finance these remaining payments with cash on hand, new debt or equity financing, which we have not yet secured in full. With respect to the Ocean Rig Santorini, our subsidiary that holds the shipbuilding contract for the Ocean Rig Santorini has received a notice of default in February 2018 for failure to pay an interim installment that was due on February 5, 2018, and is currently in commercial discussions with the shipyard to further postpone the delivery of the drilling unit and amend other terms of the shipbuilding contract. Should our subsidiary that holds the shipbuilding contract and the shipyard fail to renegotiate terms while in default, the contract could be rescinded by the shipyard and all installment payments paid by us in the amount of $309.4 million to date could be forfeited.

B.          Business Overview
We are an international offshore drilling contractor providing oilfield services for offshore oil and gas exploration, development and production drilling and specializing in the ultra-deepwater and harsh-environment segment of the offshore drilling industry. We seek to utilize our high-specification drilling units to the maximum extent of their technical capability and we believe that we have earned a reputation for operating performance excellence, customer service and safety.
We, through our wholly-owned subsidiaries, currently own two modern, fifth generation harsh weather ultra-deepwater semi-submersible offshore drilling units, the Leiv Eiriksson and the Eirik Raude, five sixth generation advanced capability ultra-deepwater drilling units, the Ocean Rig Corcovado, the Ocean Rig Olympia, the Ocean Rig Poseidon and the Ocean Rig Mykonos, delivered in January 2011, March 2011, July 2011 and September 2011, respectively and the Ocean Rig Paros, acquired on April 28, 2016 through an auction, and four seventh generation drilling units, the Ocean Rig Mylos, the Ocean Rig Skyros, the Ocean Rig Athena and the Ocean Rig Apollo, delivered in August 2013, December 2013, March 2014 and March 2015, respectively. The Ocean Rig Corcovado, the Ocean Rig Olympia, the Ocean Rig Poseidon the Ocean Rig Mykonos and the Ocean Rig Paros are "sister-ships" constructed to the same high-quality vessel design and specifications and are capable of drilling in water depths of 10,000 feet. The design of our seventh generation drilling units reflects additional enhancements that will enable the drilling units to drill in water depths of 12,000 feet. The Ocean Rig Mylos, the Ocean Rig Skyros, the Ocean Rig Athena and the Ocean Rig Apollo, are "sister ships" constructed to the same high – quality drilling unit design and specifications. We believe that owning and operating "sister-ships" helps us maintain our cost efficient operations on a global basis through the shared inventory and use of spare parts and the ability of our offshore maritime crews to work seamlessly across all of our drilling units.
In addition, we have contracts to construct two seventh generation drilling units at a major shipyard in Korea, the Ocean Rig Santorini, and the Ocean Rig Crete which are described above under "—Capital Resources".
We employ our drilling units primarily on a dayrate basis for periods of between one month and six years to drill wells for our customers, typically major oil companies, integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies.
We believe that our drilling units, the Ocean Rig Corcovado, the Ocean Rig Olympia, the Ocean Rig Poseidon, the Ocean Rig Mykonos, the Ocean Rig Mylos, the Ocean Rig Skyros, the Ocean Rig Athena, the Ocean Rig Apollo and the Ocean Rig Paros, as well as our two seventh generation drilling units under construction, are among the most technologically advanced drilling units in the world. The S10000E design, used for our operating drilling units, was originally introduced in 1998 and has been widely accepted by customers. Among other technological enhancements, our drilling units are equipped with dual activity drilling technology, which involves two drilling systems using a single derrick that permits two drilling-related operations to take place simultaneously. We estimate this technology saves between 15% and 40% in drilling time, depending on the well parameters. Each of our sixth generation operating drilling units is capable of drilling 40,000 feet at water depths of 10,000 feet and our seventh generation drilling units have the capacity to drill 40,000 feet at water depths of 12,000 feet, while our fifth generation drilling units are capable of drilling 30,000 feet at water depths of 10,000 feet.
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Our Fleet
Set forth below is summary information concerning our offshore drilling units as of March 12, 2018.
 Drilling Unit
 
Year Built or
Scheduled
Delivery/
Generation
 
Water
Depth to the
Wellhead
(ft)
 
Drilling
Depth to the
Oil Field
(ft)
 
Customer
 
Expected Contract Expiration(1)
 
 
Dayrate (4)
 
Drilling
Location
Operating Drilling Units
                             
Leiv Eiriksson
 
2001/5th
 
10,000
 
30,000
 
Lundin Norway AS
 
Q3 2018
 
$149,525
   
Norway
Ocean Rig Corcovado
 
2011/6th
 
10,000
 
40,000
 
Petroleo Brasileiro S.A.
 
Q2 2018
 
$495,000
(3)
 
Brazil
Ocean Rig Mykonos (5)
 
2011/6th
 
10,000
 
40,000
 
Petroleo Brasileiro S.A.
 
Q1 2018
 
$495,000
(3)
 
Brazil
Ocean Rig Skyros
 
2013/7th
 
12,000
 
40,000
 
Total E&P Angola
 
Q3 2021
 
  $580,755
   
Angola
Ocean Rig Poseidon (6)
 
2011/6th
 
10,000
 
40,000
 
Tullow Namibia Ltd.
 
Q3/Q4 2018
 
$138,889
   
Namibia
 
 
Available for employment
                             
Ocean Rig Mylos (2)
 
2013/7th
 
12,000
 
40,000
                 
Eirik Raude (2)
 
2002/5th
 
10,000
 
30,000
                 
Ocean Rig Paros (2)
 
2011/6th
 
10,000
 
40,000
                 
Ocean Rig Olympia (2)
 
2011/6th
 
10,000
 
40,000
                 
Ocean Rig Apollo (2)
 
2015/7th
 
12,000
 
40,000
                 
Ocean Rig Athena (2)
 
2014/7th
 
12,000
 
40,000
                 

(1)
Not including the exercise of any applicable options to extend the term of the contract and any notification received for the termination of contracts.
(2)
These drilling units are cold stacked in Greece and are available for charter.
(3)
Approximately 20% of the dayrates are service fees paid to us in Brazilian Real (R$). The day rate disclosed in this table is based on the March 12, 2018 exchange rate of R$3.25:$1.00. During the first and second quarter of 2015, the Ocean Rig Mykonos and the Ocean Rig Corcovado, respectively, commenced drilling operations under the new awarded contracts, which are extensions of the previous contracts from Petrobras, for drilling offshore Brazil. The term of each extension was for 1,095 excluding reimbursement by Petrobras for contract related equipment upgrades.
(4)
These rates represent the current operating rates applicable under each contract. Depending on the contract, these rates may be escalated.
(5)
The Ocean Rig Mykonos contract with Petrobras expires in March 2018 and is scheduled to transit to Las Palmas where it will remain in "ready-to-drill" state.
(6)
On February 23, 2018, the Company signed a new drilling contract with Tullow Namibia Ltd., for a one-well drilling program plus options for drilling offshore Namibia. The contract is expected to commence in the third quarter of 2018.
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Newbuilding Drilling Units
We have entered into contracts with a major shipyard in Korea for the construction of three seventh generation drilling units, which were previously scheduled for delivery in 2017, 2018 and 2019, respectively. As part of renegotiations, the Ocean Rig Santorini and the Ocean Rig Crete are currently scheduled for delivery in June 2018 and January 2019, respectively, and certain installments were rescheduled and the total construction costs were increased to $694.78 million and $709.6 million, respectively. With respect to the Ocean Rig Amorgos, we had previously agreed to suspend its construction with an option, subject to our option, to bring it back into force within a period of 18 months after the date of the addendum, which option expired in February 2018. With respect to the Ocean Rig Santorini, our subsidiary that holds the shipbuilding contract for the Ocean Rig Santorini has received a notice of default in February 2018 for failure to pay an interim installment that was due on February 5, 2018, and is currently in commercial discussions with the shipyard to further postpone the delivery of the drilling unit and amend other terms of the shipbuilding contract. Should our subsidiary that holds the shipbuilding contract and the shipyard fail to renegotiate terms while in default, the contract could be rescinded by the shipyard and all installment payments paid by us in the amount of $309.4 million to date could be forfeited. As of December 31, 2016, the Company impaired the total advances and related costs provided to the yard for the Ocean Rig Amorgos. As of December 31, 2017, the Company determined that the full amount of the carrying value of the two drilling units under construction Ocean Rig Crete and Ocean Rig Santorini was not recoverable and, therefore, impaired their total advances and related costs provided to the yard. In connection with the two newbuilding agreements, we had made total payments of $466.3 million as of December 31, 2017. If we decide to go ahead with the construction of the two drilling unit newbuildings, the estimated remaining total construction payments, excluding financing costs, will amount to approximately $0.9 billion in aggregate.

Employment of Our Fleet
Employment of our Drilling Units
On January 12, 2018, Lundin Norway AS ("Lundin") has declared their sixth option to extend the existing contract of the Leiv Eiriksson, which is now expected to have firm employment secured until August 2018. Should Lundin exercise its remaining six one-well options, the drilling unit could be employed until the second half of 2019. As of March 12, 2018, the dayrate is $149,525.
In May 2015, the Ocean Rig Corcovado commenced a three-year extension under the previous contract with Petrobras. The contract includes reimbursement by Petrobras for contract related equipment upgrades. As of March 12, 2018, the dayrate is $495,000, (including service fees of $94,552 based on the contracted rate in Real and the March 12, 2018 exchange rate of R$ 3.25:$1.00).
In March 2015, the Ocean Rig Mykonos commenced a three-year extension under the previous contract with Petrobras. The contract includes reimbursement by Petrobras for contract related equipment upgrades. As of March 12, 2018, the dayrate is $495,000, (including service fees of $94,552 based on the contracted rate in Real and the March, 12, 2018 exchange rate of R$3:25:$1.00). The Ocean Rig Mykonos contract with Petrobras expires in March 2018 and is scheduled to transit to Las Palmas where it will remain in "ready-to-drill" state.
In October 2015, the Ocean Rig Skyros commenced its six year contract with Total E&P Angola for drilling operations offshore Angola. As of March 12, 2018, the dayrate is $580,755.
On February 23, 2018, the Ocean Rig Poseidon has signed a new drilling contract with Tullow Namibia Ltd., for a one-well drilling program plus options for drilling offshore West Africa. The contract is expected to commence in the third quarter of 2018.
The total contracted backlog under our drilling contracts for our drilling units, as of March 12, 2018, was $847.5 million. We calculate our contract backlog by multiplying the contractual dayrate under all of our employment contracts for which we have firm commitments, by the minimum expected number of days committed under such contracts (excluding any options to extend), assuming full earnings efficiency. There can be no assurance that the counterparties to such contracts will fulfill their obligations under the contracts. See the section of this annual report entitled " Risk Factors—Risks Relating to Our Company—Our future contracted revenue for our fleet of drilling units may not be ultimately realized."
Unless otherwise stated, all references to dayrates included in this annual report are exclusive of any applicable annual contract revenue adjustments, which generally result in the escalation of the dayrates payable under the drilling contracts.
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Management of Our Drilling Units
Ocean Rig Management Inc., our wholly owned subsidiary, provides supervisory management services including onshore management to our operating drilling units and drilling units under construction, pursuant to separate management agreements entered with each of the drilling unit – owning subsidiaries. Under the terms of these management agreements, Ocean Rig Management Inc., through its affiliates is responsible for, among other things, (i) assisting in construction contract technical negotiations and (ii) providing technical and operational management for the drilling units.
In addition, up to March 31, 2016 we had engaged Cardiff Drilling Inc., a company that may be deemed to be beneficially owned by our Chairman, Mr. George Economou, to provide us with consulting and other services with respect to the arrangement of employment for, and relating to the purchase and sale of, our drilling units. On March 31, 2016, we entered into an agreement with TMS Offshore Services Ltd., a company that may be deemed to be beneficially owned by Mr. Economou to provide certain management services related to our drilling units including but not limited to commercial, financing, legal and insurance services. This agreement is effective from January 1, 2016 and was amended effective January 1, 2017. On September 22, 2017, the Restructuring Effective Date, as part of the Restructuring, we and each of our drilling-unit-owning subsidiaries terminated the previous agreement with TMS Offshore and entered into the Management Services Agreement with TMS Offshore Services Ltd. to provide certain management services related to our drilling units including but not limited to executive management, commercial, financing, accounting, reporting, information technology, legal, manning, insurance, catering and superintendency services. See "Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions."
The Offshore Drilling Industry
In recent years, the international drilling market has seen an increasing trend towards deep and ultra-deepwater oil and gas exploration. As shallow water resources mature, deep and ultra-deepwater regions are expected to play an increasing role in offshore oil and gas exploration and production. The floating rig fleet as of January 2018 consisted of 263 units. An additional 43 units were under construction or on order as of January 2018. Historically, an increase in supply has caused a decline in utilization and dayrates until drilling units are absorbed into the market. Accordingly, dayrates have been very cyclical. We believe that the largest undiscovered offshore reserves are mostly located in ultra-deepwater fields and primarily located in the "golden triangle" between West Africa, Brazil and the Gulf of Mexico, as well as in East Africa, Australia and Southeast Asia. The location of these large offshore reserves has resulted in more than 90% of the floating drilling unit, or floater, orderbook being represented by ultra-deepwater units. Furthermore, due to increased focus on technically challenging operations and the inherent risk of developing offshore fields in ultra-deepwater, particularly in light of the Deepwater Horizon accident in the Gulf of Mexico, in which we were not involved, oil companies have already begun to show a preference for modern units more capable of drilling in these challenging environments.
Markets
Our operations are geographically dispersed in oil and gas exploration and development areas worldwide. Although the cost of moving a drilling unit and the availability of drilling unit-moving vessels may cause the balance between supply and demand to vary between regions, significant variations do not tend to exist long-term because of rig mobility. Consequently, we operate in a single, global offshore drilling market. Because our drilling units are mobile assets and are able to be moved according to prevailing market conditions, we cannot predict the percentage of our revenues that will be derived from particular geographic or political areas in future periods.
In recent years, there has been increased emphasis by oil companies to expand their proven reserves and thus focus on exploring for hydrocarbons in deeper waters. This deepwater focus is due, in part, to technological developments that have made such exploration more feasible and cost-effective. Therefore, water-depth capability is a key component in determining drilling rig suitability for a particular drilling project. Another distinguishing feature in some drilling market sectors is a drilling rig's ability to operate in harsh environments, including extreme marine and climatic conditions and temperatures.
Our drilling units service the ultra-deepwater sector of the offshore drilling market. Although the term "deepwater" as used in the drilling industry to denote a particular sector of the market can vary and continues to evolve with technological improvements, we generally view the deepwater market sector as that which begins in water depths of approximately 4,500 feet and extends to the maximum water depths in which seventh generation drilling units are capable of drilling, which is currently approximately 12,000 feet.
36


Our Customers
Our customers are generally major oil companies, integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies. We, together with our predecessor, Ocean Rig ASA, have an established history with over 300 wells drilled in 22 countries for 35 different customers as of February 2018.
For the years ended December 31, 2015, 2016 and 2017 the following customers, which represent all of our customers for the years indicated, accounted for more than 10% of our consolidated annual revenues:
   
Year ended December 31,
 
   
2015
   
2016
   
2017
 
Customer A
   
14
%
   
11
%
   
-
 
Customer B
   
19
%
   
20
%
   
33
%
Customer C
   
13
%
   
-
     
-
 
Customer D
   
15
%
   
31
%
   
40
%
Customer E
   
13
%
   
14
%
   
-
 
Customer F
   
15
%
   
18
%
   
-
 

Contract Drilling Services
Our contracts to provide offshore drilling services and drilling units are individually negotiated and vary in their terms and provisions. We generally obtain our contracts through competitive bidding against other contractors. The contracts for our drilling units typically provide for compensation on a "dayrate" basis under which we are paid a fixed amount for each day that the vessel is operating under a contract at full efficiency, with higher rates while the drilling unit is operating and lower rates for periods of mobilization or when drilling operations are interrupted or restricted by equipment breakdowns, adverse environmental conditions or other conditions beyond our control. Under most dayrate contracts, we pay the operating expenses of the drilling units, including planned drilling unit maintenance, crew wages, insurance and the cost of supplies.
A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term, as do the current contracts under which our drilling units are employed. Currently, there is no spot market for offshore drilling units. The length of shorter-term contracts is typically from 25 to 365 days and the longer-term contracts are typically from two to five years. The contract term in some instances may be extended by the client exercising options for the drilling of additional wells or for an additional term. Our contracts also typically include a provision that allows the client to extend the contract to finish drilling a well-in-progress.
From time to time, contracts with customers in the offshore drilling industry may contain terms whereby the customer has an option to cancel upon payment of an early termination payment, but where such payments may not fully compensate for the loss of the contract. Contracts also customarily provide for either automatic termination or termination at the option of the customer typically without the payment of any termination fee, under various circumstances such as major nonperformance, in the event of substantial downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events. Many of these events are beyond our control.
We expect that provisions of future contracts will be similar to those in our current contracts for our drilling units. See "—Employment of our Fleet."
Competition
The offshore contract drilling industry is competitive with numerous industry participants, few of which at the present time have a dominant market share. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Many of our competitors have significantly greater financial and other resources, including more drilling units, than us. We compete with offshore drilling contractors that, as of January 2018, together have approximately 263 floating rigs.
The offshore contract drilling industry is influenced by a number of factors, including global demand for oil and natural gas, current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling units. In addition, mergers among oil and natural gas exploration and production companies have reduced, and may from time to time reduce, the number of available customers.
37


Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a contract. Customers may also consider unit availability, location and suitability, a drilling contractor's operational and safety performance record, and condition and suitability of equipment. We believe that we compete favorably with respect to these factors.
We compete on a worldwide basis, but competition may vary significantly by region at any particular time. Competition for offshore units generally takes place on a global basis, as these units are highly mobile and may be moved from one region to another, at a cost that may be substantial. Competing contractors are able to adjust localized supply and demand imbalances by moving units from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. Significant new unit construction and upgrades of existing drilling units could also intensify price competition.
Seasonality
In general, seasonal factors do not have a significant direct effect on our business as most of our drilling units are contracted for periods of at least 12 months. However, our drilling units may perform drilling operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operational utilization of our drilling units and our ability to relocate units between drilling locations, and as such, limit contract opportunities in the short term. Such adverse weather could include the hurricane season for our operations in the Gulf of Mexico, the winter season in offshore Norway, and the monsoon season in Southeast Asia.
Environmental and Other Regulations
Our offshore drilling operations include activities that are subject to numerous international, federal, state and local laws and regulations, including, the International Maritime Organization, or IMO, International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended and generally referred to as MARPOL, including designation of Emission Control Areas, or ECAs, thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended and generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the IMO International Convention for the Safety of Life at Sea of 1974, as from time to time amended and generally referred to as SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the IMO International Convention on Load Lines of 1966, as from time to time amended, the International Convention for the Control and Management of Ships' Ballast Water and Sediments in February 2004, or the BWM Convention, the U.S. Oil Pollution Act of 1990, or OPA, requirements of the U.S. Coast Guard, or USCG, and the U.S. Environmental Protection Agency, or EPA, the U.S. Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Clean Water Act, or CWA, the U.S. Clean Air Act, or CAA, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, European Union regulations, and Brazil's National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Law (9966/2000) relating to pollution in Brazilian waters. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part.
For example, the IMO has adopted MARPOL Annex VI to regulate harmful air emissions from ships, which include drilling units. Amendments to the Annex VI regulations require a progressive reduction of sulfur oxide levels in heavy bunker fuels—specifically, a global 0.5% m/m sulfur oxide emissions limit starting from January 1, 2020—and create more stringent nitrogen oxide emissions standards for marine engines in the future. Certain coastal areas of North America, the United States Caribbean Sea, and Europe are designated ECAs, and ships operating in these areas are not permitted to use fuel with sulfur content in excess of 0.1%. We may incur costs to comply with these revised standards. Drilling units must comply with MARPOL limits on emissions of sulfur oxide, nitrogen oxide, chlorofluorocarbons and other air pollutants, except that the MARPOL limits do not apply to emissions that are directly related to drilling, production, or processing activities. We believe that all of our drilling units are currently compliant in all material respects with these regulations.
Our drilling units are subject not only to MARPOL regulation of air emissions, but also to the Bunker Convention's strict liability for pollution damage caused by discharges of bunker fuel in jurisdictional waters of ratifying states.
38


Furthermore, any drilling unit that we may operate in United States waters, including the U.S. territorial sea and the 200 nautical mile exclusive economic zone around the United States, would have to comply with OPA and CERCLA requirements, among others, that impose liability (unless the spill results solely from the act or omission of a third party, an act of God or an act of war) for all containment and clean-up costs and other damages arising from discharges of oil or other hazardous substances.  OPA specifically permits individual states to impose their own liability regimes with regard to oil pollution incidents occurring within their boundaries, provided they accept, at a minimum, the levels of liability established under OPA and some states have enacted legislation providing for unlimited liability for oil spills. Furthermore, many U.S. states that border a navigable waterway have enacted environmental pollution laws that impose strict liability on a person for removal costs and damages resulting from a discharge of oil or a release of a hazardous substance.  These laws may be more stringent than U.S. federal law. Moreover, some states have enacted legislation providing for unlimited liability for discharge of pollutants within their waters. Yet, in some cases, states which have enacted such legislation have not yet issued implementing regulations defining vessel owners' responsibilities under these laws.
The BSEE periodically issues guidelines for drilling unit fitness requirements in the Gulf of Mexico and may take other steps that could increase the cost of operations or reduce the area of operations for our units, thus reducing their marketability. Implementation of BSEE guidelines or regulations may subject us to increased costs or limit the operational capabilities of our units and could materially and adversely affect our operations and financial condition.
Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial injunctive relief and administrative, civil and criminal penalties for failure to comply. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance or limit contract drilling opportunities, including changes in response to a serious marine incident that results in significant oil pollution or otherwise causes significant adverse environmental impact, such as the April 2010 Deepwater Horizon oil spill in the Gulf of Mexico, in which we were not involved, could adversely affect our financial results. While we believe that we are in substantial compliance with the current laws and regulations, there is no assurance that compliance can be maintained in the future.
In addition to the MARPOL, OPA, and CERCLA requirements described above, our international operations are subject to various other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, environmental protection, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment. New environmental or safety laws and regulations could be enacted, which could adversely affect our ability to operate in certain jurisdictions. Governments in some countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
Implementation of new environmental laws or regulations that may apply to ultra-deepwater drilling units may subject us to increased costs or limit the operational capabilities of our drilling units and could materially and adversely affect our operations and financial condition.
Insurance for Our Offshore Drilling Units
We maintain insurance for our drilling units in accordance with industry standards. Our insurance is intended to cover normal risks in our current operations, including insurance against property damage, loss of hire, war risk and third-party liability, including pollution liability. The insurance coverage is established according to the Nordic Plan, version 2016, but excluding collision liabilities which are covered by the Protection and Indemnity insurance. We have obtained insurance for the full assessed market value of our drilling units, as assessed by rig brokers. Our insurance provides for premium adjustments based on claims and is subject to deductibles and aggregate recovery limits. In the case of pollution liabilities, our deductible is $10,000 per event and in the case of other hull and machinery claims, our deductible is $1.5 million per event. Our insurance coverage may not protect fully against losses resulting from a required cessation of drilling unit operations for environmental or other reasons. We also have loss of hire insurance cover for approximately one year which becomes effective after 45 days. This loss of hire insurance is recoverable only if there is physical damage to the rig or equipment which is caused by a peril against which we are insured. The principal risks which may not be insurable are various environmental liabilities and liabilities resulting from reservoir damage caused by our negligence. In addition, insurance may not be available to us at all or on terms acceptable to us, and there is no guarantee that even if we are insured, our policy will be adequate to cover our loss or liability in all cases. We plan to maintain insurance for our seventh generation drilling units upon their delivery to us in accordance with the Nordic Plan, version 2016. This insurance would also be intended to cover normal risks in our current operations, including insurance against property damage, loss of hire and war risks. Third-party liability, including pollution liability and collision liability, is covered under our protection and indemnity insurance.
39


Permits and Authorizations
We are required by various governmental and quasi-governmental agencies to obtain certain permits, licenses and certificates with respect to our drilling units. The kinds of permits, licenses and certificates required depend upon several factors, including the waters in which a drilling unit operates, the nationality of a drilling unit's crew and the age of a drilling unit. We have been able to obtain all permits, licenses and certificates currently required to permit our drilling units to operate. Additional laws and regulations, environmental or otherwise, may be adopted which could limit our ability to do business or increase the cost of us doing business.
C.          Organizational Structure
For a full list of our subsidiaries, please see Exhibit 8.1 to this annual report. All of the subsidiaries are, directly or indirectly, wholly-owned by Ocean Rig UDW Inc., except for Olympia Rig Angola Ltd., which is 51% owned by Angolan shareholders and 49% indirectly owned by Ocean Rig UDW Inc. As of December 31, 2016 and December 31, 2017, we also consolidated one additional VIE due to the Trust formed for the purpose of the amendment of the $462 million Senior Secured Credit Facility as detailed in Note 2 of our audited consolidated financial statements.
D.          Property, Plants and Equipment
We do not own any real property. We maintain our principal executive offices in Grand Cayman, Cayman Islands and certain of our subsidiaries lease office space from unaffiliated third parties for offices in Athens, Greece; Luanda, Angola; Rio de Janeiro, Brazil; Stavanger, Norway and Aberdeen, United Kingdom. Our interests in the drilling units in our fleet are our only material properties. See "—B. Business Overview—Our Fleet" in this section.
Item 4A.          Unresolved Staff Comments
Not applicable.
Item 5.          Operating and Financial Review and Prospects
The following is a discussion of financial condition and results of operations of Ocean Rig UDW Inc. and its wholly-owned subsidiaries for the years referenced below. You should read this section together with the historical consolidated financial statements, including the notes to those historical consolidated financial statements, for those same years included in this annual report. All of the consolidated financial statements included herein have been prepared in accordance with U.S. GAAP. See "—Results of operations."
This discussion includes forward-looking statements which, although based on assumptions that we consider reasonable, are subject to risks and uncertainties, which could cause actual events or conditions to differ materially from those currently anticipated and expressed or implied by such forward-looking statements. For a discussion of some of those risks and uncertainties, please see the section entitled "Forward-Looking Statements" at the beginning of this annual report and "Item. 3 Key InformationD. Risk Factors."
A.          Operating Results
Overview
We are an international offshore drilling contractor providing oilfield services and drilling units for offshore oil and gas exploration, development and production drilling, and specializing in the ultra-deepwater and harsh-environment segment of the offshore drilling industry. We, through our wholly-owned subsidiaries, currently own and operate two modern, fifth generation harsh weather ultra-deepwater semi-submersible offshore drilling units, the Leiv Eiriksson and the Eirik Raude, four sixth generation advanced capability ultra-deepwater drilling units, the Ocean Rig Corcovado, the Ocean Rig Olympia, the Ocean Rig Poseidon, and the Ocean Rig Mykonos, which were delivered to us on January 3, 2011, March 30, 2011, July 28, 2011 and September 30, 2011, respectively and four seventh generation advanced capability ultra-deepwater drilling units, the Ocean Rig Mylos, the Ocean Rig Skyros, the Ocean Rig Athena and the Ocean Rig Apollo which were delivered to us on August 19, 2013 and December 20, 2013, March 24, 2014 and March 5, 2015, respectively. On April 28, 2016, we acquired the sixth generation ultra-deepwater drilling unit Cerrado, sold through an auction, for a purchase price of $65.0 million. The drilling unit was built in 2011 to similar design specifications to our existing sixth generation drilling units and was renamed as Ocean Rig Paros. In addition, we had contracts to construct three seventh generation drilling units at a major shipyard in Korea, the Ocean Rig Santorini, the Ocean Rig Crete and the Ocean Rig Amorgos.  These newbuildings were previously scheduled for delivery in 2017, 2018 and 2019, respectively. As part of renegotiations, the Ocean Rig Santorini and the Ocean Rig Crete are currently scheduled for delivery in June 2018 and January 2019, respectively, certain installments were rescheduled and the total construction costs were increased to $694.8 million and $709.6 million, respectively. Our subsidiary that holds the shipbuilding contract for the Ocean Rig Santorini has received a notice of default in February 2018 for failure to pay an interim installment that was due on February 5, 2018, and is currently in commercial discussions with the shipyard to further postpone the delivery of the drilling unit and amend other terms of the shipbuilding contract. Should our subsidiary that holds the shipbuilding contract and the shipyard fail to renegotiate terms while in default, the contract could be rescinded by the shipyard and all installment payments paid by us in the amount of $309.4 million to date could be forfeited.

40


If we decide to go ahead with the construction of the two drilling unit newbuildings, the estimated remaining total construction payments, excluding financing costs, will amount to approximately $0.9 billion in aggregate. With respect to the Ocean Rig Amorgos, we had previously agreed to suspend its construction with an option, subject to our option, to bring it back into force within a period of 18 months after the date of the addendum, which option expired in February 2018.
Our Drilling Units
Our drilling units are marketed for offshore exploration and development drilling programs worldwide, with particular focus on drilling operations in ultra-deepwater and harsh environments. The Leiv Eiriksson, delivered in 2001, has a water depth drilling capacity of 10,000 feet. Since 2001, it has drilled 59 deepwater and ultra-deepwater wells as of in a variety of locations, including Angola, Congo, Greenland, Turkey, Norway, Senegal the United Kingdom and Ireland, in addition to five shallow-water wells.
The Eirik Raude, delivered in 2002, has a water depth drilling capacity of 10,000 feet. Since 2002, it has drilled 82 deepwater and ultra-deepwater wells in countries such as Canada, Ghana, Norway, Ivory Coast and the United Kingdom, and the Gulf of Mexico, in addition to six shallow-water wells.
We took delivery of the Ocean Rig Corcovado, the Ocean Rig Olympia, the Ocean Rig Poseidon and the Ocean Rig Mykonos, our four sixth generation advanced capability ultra-deepwater drilling units on January 3, 2011, March 30, 2011, July 28, 2011 and September 30, 2011, respectively. The total cost of construction and construction-related expenses for the Ocean Rig Corcovado the Ocean Rig Olympia, the Ocean Rig Poseidon and the Ocean Rig Mykonos amounted to approximately $3,088.8 million in aggregate. Construction-related expenses include equipment purchases, commissioning, supervision and commissions to related parties, excluding financing costs.
We took delivery of the Ocean Rig Mylos, the Ocean Rig Skyros, the Ocean Rig Athena and the Ocean Rig Apollo, our four seventh generation advanced capability ultra-deepwater drilling units on August 19, 2013, December 20, 2013, March 24, 2014 and March 5, 2015, respectively. The total cost of construction and construction-related expenses for the Ocean Rig Mylos, the Ocean Rig Skyros, the Ocean Rig Athena and Ocean Rig Apollo amounted to approximately $2,899.0 million in aggregate. Construction-related expenses include equipment purchases, commissioning, supervision and commissions to related parties, excluding financing costs.
On April 28, 2016, we acquired the sixth generation ultra-deepwater drilling unit Cerrado, sold through an auction, for a purchase price of $65.0 million. The drilling unit was built in 2011 to similar design specifications to our existing sixth generation drilling units and was renamed as Ocean Rig Paros.
We have contracts to construct two seventh generation drilling units at a major shipyard in Korea, the Ocean Rig Santorini, and the Ocean Rig Crete.  These newbuildings were previously scheduled for delivery in 2017 and 2018, respectively. As part of renegotiations, the delivery of the Ocean Rig Santorini and the Ocean Rig Crete were postponed to June 2018 and January 2019, respectively, certain installments were rescheduled and the total construction costs were increased to $694.8 million and $709.6 million, respectively. With respect to the Ocean Rig Santorini, our subsidiary that holds the shipbuilding contract for the Ocean Rig Santorini has received a notice of default in February 2018 for failure to pay an interim installment that was due on February 5, 2018, and is currently in commercial discussions with the shipyard to further postpone the delivery of the drilling unit and amend other terms of the shipbuilding contract. Should our subsidiary that holds the shipbuilding contract and the shipyard fail to renegotiate terms while in default, the contract could be rescinded by the shipyard and all installment payments paid by us in the amount of $309.4 million to date could be forfeited. With respect to the Ocean Rig Amorgos, we had previously agreed to suspend its construction with an option, subject to our option, to bring it back into force within a period of 18 months after the date of the addendum, which option expired in February 2018. As of December 31, 2016, the Company impaired the total advances and related costs provided to the yard for the Ocean Rig Amorgos. During the year ended December 31, 2017, the Company impaired the total advances and related costs provided to the yard, amounting to $573.2 million for the Ocean Rig Crete and the Ocean Rig Santorini. If we decide to go ahead with the construction of the two drilling unit newbuildings, the estimated remaining total construction payments, excluding financing costs, will amount to approximately $0.9 billion in aggregate.

Our drilling units, the Eirik Raude, the Ocean Rig Olympia, the Ocean Rig Mylos, the Ocean Rig Paros, the Ocean Rig Apollo, and the Ocean Rig Athena are cold stacked in Greece.
For information on the employment of our drilling units, please see "Item 4. Information on the Company—B. Business Overview—Employment of our Fleet—Employment of Our Drilling Units."
41


Factors Affecting Our Results of Operations
We charter our drilling units to customers primarily pursuant to long-term drilling contracts. Under the drilling contracts, the customer typically pays us a fixed daily rate, depending on the activity and up-time of the drilling unit. The customer bears all fuel costs and logistics costs related to transport to and from the unit. We remain responsible for paying the unit's operating expenses, including the cost of crewing, catering, insuring, repairing and maintaining the unit, the costs of spares and consumable stores and other miscellaneous expenses.
We believe that the most important measures for analyzing trends in the results of our operations consist of the following:
Employment Days: We define employment days as the total number of days the drilling units are employed on a drilling contract.
Dayrates or maximum dayrates: We define drilling dayrates as the maximum rate in U.S. Dollars possible to earn for drilling services for one 24 hour day at 100% efficiency under the drilling contract. Such dayrate may be measured by quarter-hour, half-hour or hourly basis and may be reduced depending on the activity performed according to the drilling contract.
Earnings efficiency: We measure our revenue earning performance over a period as a percentage of the maximum revenues that we could earn under our drilling contracts in such period. More specifically, all drilling contracts provide for an operating or base rate that applies for the period during which the drilling unit is operational and at the client's drilling location. Furthermore, drilling contracts generally provide for a general repair allowance for preventive maintenance or repair of equipment; such allowance varies from contract to contract, and we may be compensated at the full operating dayrate or at a reduced operating day rate for such general repair allowance. In addition, drilling contracts typically provide for situations where the drilling units would operate at reduced operating dayrates, such as, among other things: a standby rate, where the drilling unit is prevented from commencing operations for reasons such as bad weather, waiting for customer orders, waiting on other contractors; a moving rate, where the drilling unit is in transit between locations; a reduced performance rate in the event of major equipment failure; or a force majeure rate in the event of a force majeure that causes the suspension of operations. At these instances we are compensated with a portion of the base rate. In addition there are circumstances that due to equipment failure or other events defined in our drilling contracts, we do not earn the base rate.
Utilization: We define utilization as the employment days divided by the total number of the drilling unit calendar days i.e. the percentage of the period that the drilling unit was under contract.
Mobilization / demobilization fees: In connection with drilling contracts, we may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to the drilling units, dayrate or fixed price mobilization and demobilization fees.
Revenue: For each contract, we determine whether the contract, for accounting purposes, is a multiple element arrangement, meaning it contains both a lease element and a drilling services element, and, if so, identify all deliverables (elements). For each element we determine how and when to recognize revenue.
Term contracts: These are contracts pursuant to which we agree to operate the unit for a specified period of time. For these types of contracts, we determine whether the arrangement is a multiple element arrangement. For revenues derived from contracts that contain a lease, the lease elements are recognized as "Leasing revenues" in the statement of operations on a basis approximating straight line over the lease period. The drilling services element is recognized as "Service revenues" in the period in which the services are rendered at fair value rates. Revenues related to the drilling element of mobilization and direct incremental expenses of drilling services are deferred and recognized over the estimated duration of the drilling period.
Well contracts: These are contracts pursuant to which we agree to drill a certain number of wells. Revenue from dayrate based compensation for drilling operations is recognized in the period during which the services are rendered at the rates established in the contracts. All mobilization revenues, direct incremental expenses of mobilization and contributions from customers for capital improvements are initially deferred and recognized as revenues over the estimated duration of the drilling period.
42


Revenue from Drilling Contracts
Our drilling revenues are driven primarily by the number of drilling units in our fleet, the contractual dayrates and the utilization of the drilling units. This, in turn, is affected by a number of factors, including the amount of time that our drilling units spend on planned off-hire class work, unplanned off-hire maintenance and repair, off-hire upgrade and modification work, reduced dayrates due to reduced efficiency or non-productive time, the age, condition and specifications of our drilling units, levels of supply and demand in the drilling rig market, the price of oil and other factors affecting the market dayrates for drilling units. Historically, industry participants have increased supply of drilling units in periods of high utilization and dayrates. This has resulted in an oversupply and caused a decline in utilization dayrates. Therefore, dayrates have historically been very cyclical.
Drilling Unit Operating Expenses
Drilling unit operating expenses include crew wages and related costs, catering, the cost of insurance, expenses relating to repairs and maintenance, the costs of spares and consumable stores, shore based costs and other miscellaneous expenses. Our drilling unit operating expenses, which generally represent fixed costs, have historically increased as a result of the business climate in the offshore drilling sector. Specifically, wages and vendor supplied spares, parts and services have experienced a significant price increase over the previous three to four years, while during the years ended 2015, 2016 and 2017 there's a decrease in the amount of these operating expenses. Other factors beyond our control, some of which may affect the offshore drilling industry in general, such as exchange rate fluctuations and including developments relating to market prices for insurance, may also cause these expenses to increase. In addition, these drilling units operating expenses are higher when operating in harsh environments, though an increase in expenses is typically offset by the higher dayrates we receive when operating in these conditions.
Depreciation
We depreciate our drilling units on a straight-line basis over their estimated useful lives. Specifically, we depreciate bare-decks over 30 years and other asset parts over five to 30 years. We expense the costs associated with a five-year periodic class work.
General and Administrative Expenses
Our general and administrative expenses mainly include the costs of our offices, including salary and related costs for members of senior management and our shore-side employees, fees for management services and other professional fees.
Interest and Finance Costs
As of December 31, 2017, 2016 and 2015, we had total indebtedness of $531.9 million, $3.9 billion and $4.4 billion, respectively. We capitalize our interest on the debt we have incurred in connection with our drilling units under construction.
Critical Accounting Policies
Drilling unit machinery and equipment, net: Drilling units are stated at historical cost less accumulated depreciation. Such costs include the cost of adding or replacing or increase the earnings capacity parts of drilling unit machinery and equipment when that cost is incurred, if the recognition criteria are met. The recognition criteria require that the cost incurred extends the useful life or increases the earnings capacity of a drilling unit. The carrying amounts of those parts that are replaced are written off and the cost of the new parts is capitalized. Depreciation is calculated on a straight- line basis over the useful life of the assets as follows: bare-deck, 30 years and other asset parts, from five to 30 years for the drilling units.    Effective January 1, 2017, the Company revised its' residual value estimate for each drilling unit. The Company assessed this residual value based on current and historical market trends. The effect of this change in accounting estimate, which did not require retrospective adoption as per ASC 250 "Accounting Changes and Error Corrections," was to increase net loss for the year ended December 31, 2017 by $14.5 million and had also an increase on loss per common share, basic and diluted by $(0.57).
43


Impairment of long-lived assets: We review for impairment long-lived assets whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. To the extent impairment indicators are present; we assesse recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset.  In developing estimates of future undiscounted cash flows, we make assumptions and estimates about the drilling units future performance, with the significant assumptions being related to drilling rates, fleet utilization, operating expenses, capital expenditures, class survey costs,  residual value and the estimated remaining useful life of each drilling unit. The projected net operating cash flows are determined by considering the drilling revenues from existing drilling contracts for the fixed days, while for the unfixed days we use an estimated daily rate equivalent by utilizing available market data. The remaining significant assumptions used to develop estimates of future undiscounted cash flows are based on historical trends as well as future expectations. Although we believe that the assumptions used to evaluate potential impairment are reasonable and appropriate, such assumptions are highly subjective. If the estimate of undiscounted future cash flows for any drilling unit is lower than the carrying value, the carrying value is written down, by recording a charge to operations, to the drilling unit's fair market value if the fair market value is lower than the drilling unit's carrying value. The fair market value for the drilling unit is obtained by independent appraisals. For the year ended December 31, 2016 and 2017, as a result of the impairment review, we determined that the carrying amount of eight and one, respectively, drilling units was not recoverable and, therefore, a charge of $3,658.8 million and $473.3 million, respectively was recognized, and included in "Impairment loss" on the consolidated statements of operations of our financial statements.  In addition, during the year ended December 31, 2017, we impaired the total advances and related costs provided to the yard, amounting to $573.2 million for the Ocean Rig Crete and the Ocean Rig Santorini. Further an impairment charge of $2.3 million relating to the reclassification of the drilling units Leiv Eiriksson and Eirik Raude as held and used (previously held for sale) was recognized and included in the "Impairment loss" in the consolidated statement of operations of our financial statements as of December 31, 2017.
Reorganizations: In accordance with GAAP, the Company has applied ASC 852 "Reorganizations" (ASC 852), in preparing the accompanying consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 15 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the Chapter 15 proceedings are recorded in reorganization gain, net on the accompanying consolidated statement of operations. Upon emerging from Chapter 15 proceedings on September 22, 2017, we did not meet the criteria to qualify for fresh-start reporting.  Therefore, the discharge of debt is reported as an extinguishment of debt and classified in accordance with Subtopic 225-20.
Non-monetary transactions - exchange of the capital stock of an entity for nonmonetary assets or services: Such transactions are measured at the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. Any difference between the fair value and the transaction price is considered as gain or loss for the Company. The Company considered as appropriate date to use to measure the fair value of the equity instruments issued, the restructuring effective date and accounts for such transactions in accordance with ASC 845 at fair value of its common shares on that date.
Revenue and related expenses: Our services and deliverables are generally sold based upon contracts with our customers that include fixed or determinable prices. We recognize revenue when delivery occurs, as directed by our customer, or the customer assumes control of physical use of the asset and collectability is reasonably assured. We evaluate if there are multiple deliverables within our contracts and whether the agreement conveys the right to use the drilling units for a stated period of time and meet the criteria for lease accounting, in addition to providing a drilling services element, which are generally compensated for by dayrates. In connection with drilling contracts, we may also receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to the drilling units and dayrate or fixed price mobilization and demobilization fees. Revenues are recorded net of agents' commissions. There are two types of drilling contracts: well contracts and term contracts.
Well contracts:    Well contracts are contracts under which the assignment is to drill a certain number of wells. Revenue from dayrate-based compensation for drilling operations is recognized in the period during which the services are rendered at the rates established in the contracts. All mobilization revenues, direct incremental expenses of mobilization and contributions from customers for capital improvements are initially deferred and recognized as revenues and expenses, as applicable, over the estimated duration of the drilling period. To the extent that expenses exceed revenue to be recognized, they are expensed as incurred. Demobilization fees and expenses are recognized over the demobilization period. All revenues for well contracts are recognized as "Service revenues" in the statement of operations.
Term contracts:    Term contracts are contracts under which the assignment is to operate the drilling unit for a specified period of time. For these types of contracts we determine whether the arrangement is a multiple element arrangement containing both a lease element and drilling services element. For revenues derived from contracts that contain a lease, the lease elements are recognized as "Leasing revenues" in the statement of operations on a basis approximating straight line over the lease period. The drilling services element is recognized as "Service revenues" in the period in which the services are rendered at fair value. Revenues related to the drilling element of mobilization and direct incremental expenses of drilling services are deferred and recognized over the estimated duration of the drilling periods. To the extent that expenses exceed revenue to be recognized, they are expensed as incurred. Demobilization fees and expenses are recognized over the demobilization period. Contributions from customers for capital improvements are initially deferred and recognized as revenues over the estimated duration of the drilling contract.
44


Other revenues: Other revenues represent the revenues derived from customer contract terminations. The Company recognizes revenues from contract terminations as it has fulfilled obligations for such terminations and when all contingencies have expired.
Reimbursable revenues: Effective January 1, 2017, reimbursements received from the Customers for the provision of catering services in accordance with relevant contracts are recorded as revenue. The related costs are recorded as running expenses in the same period.
Income taxes: Income taxes have been provided for based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. There is no expected relationship between the provision for/or benefit from income taxes and income or loss before income taxes because the countries in which we operate have taxation regimes that vary not only with respect to the nominal rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise because income earned and taxed in any particular country or countries may fluctuate from year to year. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates in effect at the year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. As of December 31, 2017 the Company has adopted the provisions of ASU 2015-17 on the Balance Sheet Classification on Deferred Taxes, which requires all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance did not impact the consolidated financial statements. We accrue interest and penalties related to its liabilities for unrecognized tax benefits as a component of income tax expense.
Inflation
Inflation has not had a material effect on our expenses given current economic conditions. In the event that significant global inflationary pressures appear, these pressures could increase our operating, administrative and financing costs.
Results of Operations
Included in this document are our audited consolidated historical financial statements for the years ended December 31, 2017, 2016, and 2015.
Year Ended December 31, 2017 compared to Year Ended December 31, 2016
   
Year Ended December 31, 2016
   
Year Ended December 31, 2017
   
Change
   
Percentage Change
 
                         
REVENUES:
                       
Revenues
   
1,653,667
     
1,007,520
     
(646,147
)
   
(39.1
)%
                                 
EXPENSES:
                               
Drilling units operating expenses
   
454,329
     
295,135
     
(159,194
)
   
(35.0
)%
Depreciation and amortization
   
334,155
     
121,193
     
(212,962
)
   
(63.7
)%
Impairment loss
   
3,776,338
     
1,048,828
     
(2,727,510
)
   
(72.2
)%
General and administrative expenses
   
103,961
     
73,360
     
(30,601
)
   
(29.4
)%
Loss on sale of fixed assets
   
25,274
     
238
     
(25,036
)
   
(99.1
)%
Legal settlements and other, net
   
(8,720
)
   
(1,519
)
   
7,201
     
(82,6
)%
Operating income/ (loss)
   
(3,031,670
)
   
(529,715
)
   
2,501,955
     
(82.5
)%
                                 
OTHER INCOME/(EXPENSES):
                               
Interest and finance costs
   
(226,981
)
   
(248,342
)
   
(21,361
)
   
9.4
%
Interest income
   
3,449
     
7,442
     
3,993
     
115.8
%
Loss on interest rate swaps
   
(4,388
)
   
-
     
4,388
     
(100.0
)%
Reorganization gain, net
   
-
     
1,029,982
     
1,029,982
     
100.0
%
Loss from issuance of shares upon restructuring
   
-
     
(204,595
)
   
(204,595
)
   
100.0
%
Gain from repurchase of Senior Notes
   
125,001
     
-
     
(125,001
)
   
(100.0
)%
Other, net
   
(614
)
   
3,321
     
3,935
     
(640.9
)%
Total other expenses (income), net
   
(103,533
)
   
587,808
     
691,341
     
(667.7
)%
                                 
Income / (loss) before income taxes
   
(3,135,203
)
   
58,093
     
3,193,296
     
(101.9
)%
Income taxes
   
(106,315
)
   
(63,495
)
   
42,820
     
(40.3
)%
Net Income / (loss)
   
(3,241,518
)
   
(5,402
)
   
3,236,116
     
(99.8
)%

45


Revenues
Revenues from drilling contracts decreased by $646.2 million, or 39.1%, to $1,007.5 million for the year ended December 31, 2017, as compared to $1,653.7 million for the year ended December 31, 2016. The decrease is mainly attributable to the decreased operations of the whole fleet due to the stacking of six drilling units up to the year ended December 31, 2017.
During the years 2016 and 2017, we recorded 57.2% and 41.2% utilization (excluding the days for which we received a termination fee), respectively. Furthermore, our fleet under contract achieved an earnings efficiency of 96.4% for the years ended December 31, 2016 and 2017.
Operating expenses
Drilling units operating expenses decreased by $159.2 million, or 35.0%, to $295.1 million for the year ended December 31, 2017, compared to $454.3 million for the year ended December 31, 2016, mainly due to cost-reduction initiatives for the entire fleet as well as the decreased operations due to the stacking of six drilling units up to the year ended December 31, 2017, compared to the stacking of five drilling units of the total fleet for the year ended December 31, 2016. This decrease was partly offset by the increase in operating expenses of approximately $33.8 million, mainly relating to drilling unit Ocean Rig Mykonos special period survey costs and other various equipment refurbishment during the year ended December 31, 2017, as compared to the year ended December 31, 2016.
Depreciation and amortization expense
Depreciation and amortization expense decreased by $213.0 million, or 63.7%, to $121.2 million for the year ended December 31, 2017, as compared to $334.2 million for the year ended December 31, 2016. The decrease in depreciation and amortization expense was mainly attributable to the decrease in depreciation expense of the whole fleet, due to the lower depreciable value of eight of our drilling units as a result of the impairment charge that was recognized during the year ended December 31, 2016.
Impairment loss
During the year ended, December 31, 2017, we recorded an impairment loss of $1,048.8 million, due to the loss of $2.3 million resulted from the reclassification of the drilling units Leiv Eiriksson and Eirik Raude as held and used (previously held for sale), the reduction of $473.3 million of the carrying amount of the drilling unit Ocean Rig Apollo to its fair value and the impairment of the total advances and related costs provided to the yard regarding the drilling units under construction, Ocean Rig Santorini and Ocean Rig Crete amounting to $573.2 million, as compared to a loss of $3,776.3 million during the year ended December 31, 2016.
General and administrative expenses
General and administrative expenses decreased by $30.6 million, or 29.4%, to $73.4 million for the year ended December 31, 2017, as compared to $104.0 million for year ended December 31, 2016 mainly due to the cost-reduction initiatives implemented and the reduction of our staff due to fewer drilling units in operation.
Loss on sale of fixed assets
For the year ended, December 31, 2017, we incurred losses on sale of fixed assets amounting to $0.2 million which relate mainly to the sale of Company's cars and drill pipes, compared to $25.3 million for the year ended December 31, 2016.
Legal Settlements and other, net
Legal settlements and other, net decreased by $7.2 million, or 82.8%, due to a gain of $1.5 million for the year ended December 31, 2017, as compared to a gain of $8.7 million for the year ended December 31, 2016. This decrease relates mainly to the gain of $7.8 million from an insurance claim during the year ended December 31, 2016, whereas gain of $5.5 million from insurance claims and a provision of $4.0 million have been recorded during the year ended December 31, 2017.
Interest and finance costs
Interest and finance costs increased by $21.3 million, or 9.4%, to $248.3 million for year ended December 31, 2017, as compared to $ 227.0 million for the year ended December 31, 2016. The increase is mainly associated with an increase of $42.7 million of amortization and write off of financing fees and discount on receivable from drilling contract partly offset by a decrease of $20.9 million of interest costs on long term debt during the year ended December 31, 2017, as compared to the same period ended December 31, 2016.
46


Interest income
Interest income increased by $4.0 million, or 117.6%, to $7.4 million for the year ended December 31, 2017, compared to $3.4 million for the year ended December 31, 2016. The increase was mainly due to interest received from time deposits as a result of the Company's cash management.
Loss on interest rate swaps
Loss on interest rate swaps decreased by $4.4 million, or 100.0%, to $0 million for year ended December 31, 2017, as compared to a loss of $4.4 million for the year ended December 31, 2016. As of December 31, 2017, we have no outstanding interest rate swaps.
Reorganization gain, net
For the year ended December 31, 2017, we recognized reorganization gain, net of $1,030.0 million mainly resulting from debt extinguishment and write off totaling to $1,129.1 million. This gain was partly offset by reorganization expenses of $99.1 million, which pertain to professional fees and other expenditures directly related to the restructuring of our debt. No material expenses were incurred for the year ended December 31, 2016.
Loss from issuance of shares upon Restructuring
For the year ended December 31, 2017, we recognized loss from issuance of shares upon restructuring of $204.6 million associated with the issuance of shares to Prime Cap Shipping Inc., a company that may be deemed to be beneficially owned by our Chairman, Mr. George Economou. For the year ended December 31, 2016, no such loss was incurred.
Gain from repurchase of Senior Notes

For the year ended December 31, 2016, we recognized gain of $125.0 million due to the repurchase of the 7.25% Senior Unsecured Notes and 6.50% Senior Secured Notes at a discount due to the market value at which the notes were trading. No such case existed for the year ended December 31, 2017.
Other, net
Other, net increased by $3.9 million, or 650.0%, to a gain of $3.3 million for year ended December 31, 2017, compared to a loss of $0.6 million for the year ended December 31, 2016. The increase is mainly due to foreign currency exchange rate differences between the United States Dollars (USD), the Norwegian Krone (NOK), the Brazilian Real (BRL) and the Angolan Kwanza (AOA).
Income taxes
Income taxes decreased by $42.8 million, or 40.3%, to $63.5 million for year ended December 31, 2017 compared to $106.3 million for the year ended December 31, 2016. The decrease is due to the decreased operations resulting by the stacking of six drilling units up to year ended December 31, 2017. As our drilling units operate around the world, they may become subject to taxation in many different jurisdictions. The basis for such taxation depends on the relevant regulation in the countries in which we operate. Consequently, there is no expected relationship between the income tax expense or benefit for the period and the income or loss before taxes.
Year Ended December 31, 2016 compared to Year Ended December 31, 2015
   
Year Ended December 31, 2015
   
Year Ended December 31, 2016
   
Change
   
Percentage Change
 
                         
REVENUES:
                       
Total revenues
   
1,748,200
     
1,653,667
     
(94,533
)
   
(5.4
)%
                                 
EXPENSES:
                               
Drilling units operating expenses
   
582,122
     
454,329
     
(127,793
)
   
(22.0
)%
Depreciation and amortization
   
362,587
     
334,155
     
(28,432
)
   
(7.8
)%
Impairment loss
   
414,986
     
3,776,338
     
3,361,352
     
810.0
%
General and administrative expenses
   
100,314
     
103,961
     
3,647
     
3.7
%
Loss on sale of fixed assets
   
5,177
     
25,274
     
20,097
     
388.2
%
Legal settlements and other, net
   
(2,591
)
   
(8,720
)
   
(6,129
)
   
236.5
%
Operating income/ (loss)
   
285,605
     
(3,031,670
)
   
(3,317,275
)
   
(1,161.5
)%
                                 
OTHER INCOME/(EXPENSES):
                               
Interest and finance costs
   
(280,348
)
   
(226,981
)
   
53,367
     
(19.0
)%
Interest income
   
9,811
     
3,449
     
(6,362
)
   
(64.8
)%
Loss on interest rate swaps
   
(11,513
)
   
(4,388
)
   
7,125
     
(61.9
)%
Gain from repurchase of Senior Notes
   
189,174
     
125,001
     
(64,173
)
   
(33.9
)%
Other, net
   
(12,899
)
   
(614
)
   
12,285
     
(95.2
)%
Total other expenses, net
   
(105,775
)
   
(103,533
)
   
2,242
     
(2.1
)%
                                 
Income / (loss) before income taxes
   
179,830
     
(3,135,203
)
   
(3,315,033
)
   
(1,843.4
)%
Income taxes
   
(99,816
)
   
(106,315
)
   
(6,499
)
   
6.5
%
Net Income / (loss)
   
80,014
     
(3,241,518
)
   
(3,321,532
)
   
(4,151.2
)%

47


Revenues
Revenues from drilling contracts decreased by $94.5 million, or 5.4%, to $1,653.7 million for the year ended December 31, 2016, as compared to $1,748.2 million for the year ended December 31, 2015, mainly due to lower utilization of the fleet. The drilling units, the Eirik Raude and the Leiv Eiriksson the Ocean Rig Mykonos, the Ocean Rig Poseidon and the Ocean Rig Mylos contributed decreased revenues of $380.1 million for the year ended December 31, 2016, as compared to the year ended December 31, 2015. This decrease was partly offset by the increased revenues from the Ocean Rig Skyros amounting to $162.5 million mainly due to increased operating days during the year ended December 31, 2016 as compared to the year ended, December 31, 2015 and by the increased revenues of the Ocean Rig Apollo, of $84.7 million which mainly relate to termination fees and the revenue of the Ocean Rig Corcovado, the Ocean Rig Olympia and the Ocean Rig Athena which contributed $42.7 million in aggregate more, during the year ended December 31, 2016, as compared to the relevant year ended December 31, 2015.
During the years 2015 and 2016, we recorded 92.2% and 57.2% utilization, respectively. Furthermore, our fleet under contract achieved an earnings efficiency of 96.4% for the year ended December 31, 2016, as compared to 97.6% for the year ended December 31, 2015.
Operating expenses
Drilling units operating expenses decreased by $127.8 million, or 22.0%, to $454.3 million for the year ended December 31, 2016, compared to $582.1 million for the year ended December 31, 2015, mainly due to cost-reduction initiatives implemented and the cold stacking of five drilling units of the total fleet. This decrease was partly offset by the increase in operating expenses by $15.0 million of the Ocean Rig Corcovado mainly due to increased repair and maintenance expenses incurred during the five year class survey, $6.7 million of the Ocean Rig Skyros and $8.9 million of the Ocean Rig Paros, due to the increased number of operating days during the year ended December 31, 2016, as compared to the year ended December 31, 2015.
Depreciation and amortization expense
Depreciation and amortization expense decreased by $28.4 million, or 7.8%, to $334.2 million for the year ended December 31, 2016, as compared to $362.6 million for the year ended December 31, 2015. The decrease in depreciation and amortization expense was mainly attributable to the decrease in depreciation expense of the Leiv Eiriksson and the Eirik Raude amounting to $36.8 million, in aggregate, due to the lower depreciable value of these drilling units as a result of the impairment charge that was recognized as at December 31, 2015. An aggregate decrease of the depreciation expense amounting to $3.5 million was noted for the drilling units the Ocean Rig Olympia, the Ocean Rig Mykonos and the Ocean Rig Mylos. This decrease was partly offset by the increase in depreciation of $4.5 million, $0.9 million, $0.6 million and $5.6 million, of the Ocean Rig Corcovado, the Ocean Rig Skyros, the Ocean Rig Athena and the Ocean Rig Apollo, respectively, (delivered in March 2015) and the increase of $0.7 million in the depreciation of the Ocean Rig Paros, acquired in April 2016. The depreciation expense charged for the remaining drilling units for the year ended December 31, 2016 was consistent with that charged in the corresponding period in 2015.
Impairment loss
During the year ended, December 31, 2016, we recorded an impairment loss of $3,776.3 million due to the reduction of the carrying amount to the fair value of eight of our drilling units, impaired advances of one of our drilling units under construction and a write off of cash flow hedges associated with interest capitalized, as compared to a loss of $415.0 million during the year ended December 31, 2015.
General and administrative expenses
General and administrative expenses increased by $3.7 million, or 3.7%, to $104.0 million for the year ended December 31, 2016, as compared to $100.3 million for year ended December 31, 2015 mainly due to the increase in professional fees.
Loss on sale of fixed assets
For the year ended, December 31, 2016, we incurred losses on sale of fixed assets amounting to $25.3 million which relate mainly to the cancelation of the BOP purchase for the Eirik Raude and extra costs relating to a settlement agreement between us and the supplier, compared to $5.2 million for the year ended December 31, 2015.
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Legal Settlements and other, net
A gain of $8.7 million was realized for the year ended December 31, 2016, as compared to a gain of $2.6 million during the year ended December 31, 2015 resulting in an increase of $6.1 million or 234.5%. The increase relates mainly to the gains from insurance claims during the year ended December 31, 2016.
Interest and finance costs
Interest and finance costs decreased by $53.2 million, or 19.0%, to $227.1 million for year ended December 31, 2016, as compared to $ 280.3 million for the year ended December 31, 2015. The decrease is mainly associated with the lower level of debt during the year ended December 31, 2016, as compared to the corresponding year ended in 2015, mainly due to the repurchase of the 7.25% Senior Unsecured Notes and 6.50% Senior Secured Notes as well as the prepayment of $125.0 million of the $462.0 million Senior Secured Credit Facility during the year ended December 31, 2016.
Interest income
Interest income decreased by $6.4 million, or 65.3%, to $3.4 million for the year ended December 31, 2016, compared to $9.8 million for the year ended December 31, 2015. The decrease was mainly due to the interest income received from the $120.0 million Exchangeable Promissory Note provided to DryShips Inc. during the year ended December 31, 2015.
Loss on interest rate swaps
Loss on interest rate swaps decreased by $7.1 million, or 61.9%, to $4.4 million for year ended December 31, 2016, as compared to a loss of $11.5 million for the year ended December 31, 2015. As of December 31, 2016, we have no outstanding interest rate swaps.
Gain from repurchase of Senior Notes

Gain from repurchase of senior notes, decreased by $64.2 million or 33.9% to $125.0 million for the year ended December 31, 2016, as compared to the year ended December 31, 2015, during which we incurred gains of $189.2 million. The increase is due to the repurchase of the 7.25% Senior Unsecured Notes and 6.50% Senior Secured Notes at a discount due to the market value at which the notes were trading,
Other, net
Other, net resulted to a loss of $0.6 million for year ended December 31, 2016, compared to a loss of $12.9 million for the year ended December 31, 2015. The decrease is mainly due to foreign currency exchange rate differences between the United States Dollars (USD), the Norwegian Krone (NOK), the Brazilian Real (BRL) and the Angolan Kwanza (AOA).
Income taxes
Income taxes increased by $6.5 million, or 6.5%, to $106.3 million for year ended December 31, 2016, compared to $99.8 million for the year ended December 31, 2015. As our drilling units operate around the world, they may become subject to taxation in many different jurisdictions. The basis for such taxation depends on the relevant regulation in the countries in which we operate. Consequently, there is no expected relationship between the income tax expense or benefit for the period and the income or loss before taxes.
B.          Liquidity and Capital Resources
As of December 31, 2017, we had $736.1 million of cash and cash equivalents. Our cash and cash equivalents increased by $17.4 million, or 2.4%, to $736.1 million as of December 31, 2017, compared to $718.7 million as of December 31, 2016. The increase in our cash and cash equivalents was mainly due to cash from operating activities amounting to $543.4 million which were offset by cash used in investing activities amounting to $29.5 million and by cash used in financing activities amounting to $496.5 million. As of December 31, 2017 and upon, the effective date of our Restructuring, on September 22, 2017, we had total indebtedness, on a consolidated basis, of $531.9 million under our outstanding debt agreements, excluding unamortized deferred financing costs compared to $3.9 billion as of December 31, 2016. Our total indebtedness as of December 31, 2017 decreased by $3.4 billion, or 87.2%, to $531.9 million, compared to $3.9 billion as of December 31, 2016 due to the completion of our financial restructuring.
As of December 31, 2017, we had $47.0 million of restricted cash relating mainly to bank deposits which are blocked or pledged as cash collateral. Our restricted cash balances as of December 31, 2017 decreased by $7.3 million, or 13.5%, to $47.0 million, compared to $54.3 million as of December 31, 2016. Restricted cash decreased by $6.6 million under the terms of the $462 million Senior Secured Credit Facility.
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 As of December 31, 2017, we were in compliance with all covenants related to our outstanding debt agreements. Please refer to the discussion on Long-term Debt as detailed in Note 9 of our audited consolidated financial statements.
As of December 31, 2017, our total purchase commitments consisted of the estimated remaining construction expenses of approximately $0.9 billion relating to the construction of our two seventh generation drilling units under construction, which are scheduled to be delivered in 2018 and 2019, respectively. The estimated remaining total project cost per drilling unit under construction, excluding financing costs, is approximately $385.4 million and $552.7 million. If certain of our subsidiaries decide to go ahead with the construction of our two seventh generation drilling unit newbuildings, our total purchase commitments consist of the estimated remaining construction expenses of approximately $0.9 billion relating to their construction.
Working capital is defined as current assets minus current liabilities (including the current portion of long-term debt). Our working capital surplus amounted to $806.7 million as of December 31, 2017, as compared to a working capital surplus of $267.9 million as of December 31, 2016. The increase in working capital surplus as of December 31, 2017, as compared to December 31, 2016, is mainly due to the increase in cash and cash equivalents and the decrease in our long- term debt due to our Restructuring.
Our principal use of funds has been capital expenditures to establish and grow our fleet, maintain the quality of our drilling units, comply with international standards, environmental laws and regulations, fund working capital requirements and make principal repayments on outstanding loan facilities. Our substantially reduced debt is comprised of two Senior Secured Term Loan Facilities with a maturity date of June 2018 and September 2024, respectively and following the Restructuring, our principal source of funds has been cash on hand, cash generated from operations and new bank debt, or a combination thereof.
Following the Restructuring and as of December 31, 2017, we believe that our current cash balances and operating cash flow, together with the proceeds of any debt or equity issuances in the future, will be sufficient to meet our liquidity needs for the next 12 months.
Compliance with Covenants under Our Debt Agreements
On the Restructuring Effect Date, pursuant to the Schemes, we, including certain of our subsidiaries, as borrowers and guarantors, entered into a new credit agreement dated September 22, 2017, or the New Credit Agreement, with the Scheme Creditors participating in the Schemes relating to DOV and DFH, as lenders. The New Credit Agreement contains limited restrictive and financial covenants that are usual and customary for facilities of this type, including, without limitation: (i) delivery of financial statements, reports, accountants' letters, certificates and SEC filings; (ii) notices of defaults, material litigation and other material events; (iii) continuation of business and maintenance of existence and material rights and privileges; (iv) compliance with laws, including sanctions laws; and (v) maintenance of property and insurance.

Events beyond our control, including changes in the economic and business conditions in the deepwater offshore drilling market in which we operate, may affect our ability to comply with these ratios and covenants. Our ability to maintain compliance will also depend substantially on the value of our assets, our dayrates, our ability to obtain drilling contracts, our success at keeping our costs low and our ability to successfully implement our overall business strategy. The prolonged market downturn in the offshore drilling industry and the continued depressed outlook, have led to materially lower levels of investing in for offshore exploration and development by the current and potential customers on a global basis, while at the same time supply of available high specification drilling units has increased, which in turn has affected us with the early termination of five drilling contracts as of December 31, 2017 and also led to the stacking of six drilling units of our fleet as of the date of this report.
As of December 31, 2017, we were in compliance with all covenants related to our debt agreements. Please refer to the discussion on Long-term Debt as detailed in Note 9 and the discussion on Liquidity and Going Concern considerations as detailed in Note 3 of our audited consolidated financial statements.
Our Debt Agreements
$450 million Senior Secured Term Loan Facility
On September 22, 2017 we, including certain of our subsidiaries, as borrowers and guarantors, entered into a New Credit Agreement. The New Credit Agreement contains limited restrictive covenants that are usual and customary for facilities of this type, including, without limitation: (i) delivery of financial statements, reports, accountants' letters, certificates and SEC filings; (ii) notices of defaults, material litigation and other material events; (iii) continuation of business and maintenance of existence and material rights and privileges; (iv) compliance with laws, including sanctions laws; and (v) maintenance of property and insurance.

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We and certain of our subsidiaries will guarantee the obligations of the New Credit Agreement and collateral has been granted to the lenders by way of first priority lien over substantially all existing and newly acquired assets of the borrowers and guarantors. The New Credit Agreement consists of a $450 million Senior Secured Term Loan Facility, bearing interest at 8.00% per annum and with a maturity date of September 20, 2024. In addition, under the terms of the New Credit Agreement, we have the option to refinance the facility in full at no cost until March 22, 2018, at 105% from March 23, 2018 until March 22, 2019, at 103% from March 23, 2019 until March 22, 2020 and at 101% from March 23, 2020 until March 22, 2021.
As of December 31, 2017, we had outstanding borrowings amounting to $450.0 million under this facility.
$462 million Senior Secured Credit Facility
On February 13, 2015, our wholly owned subsidiary, Drillship Alonissos Owners Inc., entered into a secured term loan facility agreement with a syndicate of lenders and DNB Bank ASA, as facility agent and security agent, for up to $475.0 million to partially finance the construction costs of the Ocean Rig Apollo. This facility has a 5 year term and bears interest at LIBOR plus a margin. On March 3, 2015, we drew down an amount of $462.0 million under this facility and pledged restricted cash of $10.0 million associated with the respective loan. On February 11, 2016, the charterer of the Ocean Rig Apollo sent to us a notice of termination of the drilling contract. Under the terms of the $462 million Senior Secured Credit Facility, we were required to find a new Satisfactory Drilling Contract (as defined in the loan agreement). We did not secure a new drilling contract for the Ocean Rig Apollo and, therefore, was required to make a mandatory prepayment of approximately $145,894 on August 22, 2016.
On August 31, 2016, our wholly owned subsidiary, Drillship Alonissos Shareholders Inc., entered into an amendment to the term loan facility agreement in consideration for the lenders agreeing: (i) to reduce the amount of the mandatory prepayment from $145,894 to $125,000;(ii) to release the Company as Guarantor and from all obligations, actual or contingent, joint or several, now or at any time outstanding; (iii) to waive any existing breaches and, (iv) the cold-stacking of the drilling unit. Furthermore, a trust was formed, namely "Drillship Alonissos Stock Trust" (the "Trust"), in which we transferred the shares of Drillship Alonissos Shareholders Inc. together with the shares of Drillship Alonissos Owners Inc., previously held by Drillship Alonissos Shareholders Inc. Additionally, the repayment schedule of the loan was altered to include a cash sweep term authorizing the lenders to transfer any excess cash flow on a monthly basis, as a prepayment pro rata across the loan, therefore, leading to the full repayment of the loan by June 2018, whereas according to the initial repayment schedule it would have been fully repaid by June 2020. Following the repayment, the Trust, will be dissolved and shares will be returned to their initial holders.
As of December 31, 2017, we had outstanding borrowings amounting to $81.9 million under this facility.
Discharged Debt Agreements
6.50% senior secured notes due 2017
On September 20, 2012, our wholly owned subsidiary DRH (the "Issuer"), issued $800.0 million aggregate principal amount of 6.50% Senior Secured Notes due 2017 (the "$800.0 million Senior Secured Notes"), with a semi-annual coupon interest rate of 6.5% per year. The $800.0 million Senior Secured Notes were secured by Issuer's and its subsidiaries' certain assets, including stocks, and guaranteed by us and certain of the existing and future subsidiaries of the Issuer.
As of December 31, 2016, two of our wholly owned subsidiaries had purchased in the open market an aggregate principal amount of $148.0 million, resulting to a gain of $67.8 million included in "Gain from repurchase of senior notes" in the accompanying consolidated statements of operations. Effective March 21, 2017, these notes have been cancelled.
$1.9 billion Term Loan B Facilities, dated July 12, 2013
On July 12, 2013,  we, through our wholly-owned subsidiaries, DFH and Drillships Projects Inc., entered into a $1.8 billion senior secured term loan facility, comprised of two tranches, tranche B-1 of $975.0 million ("Tranche B-1") and tranche B-2 of $825.0 million ("Tranche B-2"), collectively, the "$1.9 billion Term Loan B Facility", with respective maturity dates in the first quarter of 2021, subject to adjustment to the third quarter of 2020 in certain circumstances, and the third quarter of 2016.
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The $1.9 billion Term Loan B Facility was: (i) guaranteed by our and certain existing and future subsidiaries of DFH and (ii) secured by certain assets of, and by a pledge of the stock of, DFH and the subsidiary guarantors. On July 26, 2013, we through DFH and Drillships Projects Inc. entered into an incremental amendment to the $1.8 billion senior term loan for additional Tranche B-1 in an aggregate principal amount of $100.0 million.
On February 7, 2014, we refinanced its then existing short-term Tranche B-2 with a fungible add-on to its existing long-term Tranche B-1 with maturity date at no earlier than the third quarter of 2020.

As of December 31, 2016, we had outstanding borrowings amounting to $1,838.3 million under this facility.
$1.3 billion Senior Secured Term Loan B Facility
On July 25, 2014, our wholly owned subsidiary, DOV, entered into a $1.3 Senior Secured Term Loan B facility ("New Term Loan B facility") to repay the then outstanding balance of $1.3 billion under the $1.35 billion Senior Secured Credit Facility. The New Term Loan B facility, with a maturity date on July 25, 2021, was secured primarily by first priority mortgages on the drilling units, the Ocean Rig Mylos, the Ocean Rig Skyros and the Ocean Rig Athena and bore a fixed interest rate.
As of December 31, 2016, we had outstanding borrowings amounting to $1,270.8 million under this facility.
Ocean Rig's 7.25% senior unsecured notes due 2019
On March 26, 2014, we issued $500.0 million aggregate principal amount of 7.25% Senior Unsecured Notes due 2019 (the "$500 million Senior Unsecured Notes"), with a semi-annual coupon interest rate of 7.25% per year. We used the net proceeds from the offering, amounted to $493.6 million, together with cash on hand, to repurchase the outstanding balance of $462.3 million under its 9.5% Senior Unsecured Notes.
As of December 31, 2016, one of our wholly owned subsidiary, had purchased in the open market an aggregate principal amount of $369.0 million of these notes, reducing the then outstanding balance to $131.0 million. Effective March 21, 2017, these repurchased notes have been cancelled.
During the year ended December 31, 2016, the purchase of the notes, resulted in a gain of $57.2 million and is included in "Gain from repurchase of senior notes" in the accompanying consolidated statement of operations.
Discharge of the 7.25% Senior Unsecured Notes, 6.50% Senior Secured Notes, $1.3 billion Senior Secured Term Loan B Facility and $1.9 billion Term Loan B Facility
On September 22, 2017, the restructuring effective date, the outstanding principal amounts, accrued interest and default interest of the 7.25% Senior Unsecured Notes, $6.50% Senior Secured Notes, $1.3 billion Senior Secured Term Loan B Facility and $1.9 billion Term Loan B Facility were discharged in exchange for new equity in our Company amounting to $1,992.5 million, cash consideration amounting to $320.8 million and the $450 million Senior Secured Term Loan Facility discussed above. The resulted gain amounting to $1,129.1 million is included as a "Reorganization Gain, net" in the accompanying consolidated statement of operations. Deferred finance fees related to discharged notes and facilities have been written off and are included in "interest and finance costs" in the accompanying consolidated statement of operations.
Cash Flows
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Our cash and cash equivalents increased to $736.1 million as of December 31, 2017, compared to $718.7 million as of December 31, 2016. Our working capital surplus was $806.7 million as of December 31, 2017, compared to a $267.9 million working capital surplus as of December 31, 2016, primary due to the decrease in our long- term debt.
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Net Cash Provided by Operating Activities
Net cash provided by operating activities was $543.4 million for the year ended December 31, 2017 compared to 763.1 million provided by operating activities for the year ended December 31, 2016. For the year ended December 31, 2017, net loss of $5.4 million was adjusted for the effects of certain non-cash items including $121.2 million of depreciation, $0.2 million loss on sale of fixed assets, $61.8 million of amortization and write offs of deferred financing and other costs, $1,048.8 million of impairment loss, $1,129.1 million of reorganization gain, and $204.6 million loss from issuance of shares upon Restructuring. The Company had net cash inflows from changes in operating assets and liabilities of approximately $241.2 million for the year ended December 31, 2017.
Net Cash Used in Investing Activities
Net cash used in investing activities was $29.5 million for the year ended December 31, 2017, compared to $392.5 million for the year ended December 31, 2016. Cash was used for expenditures related to advances for drilling units under construction and drilling units, machinery, equipment and other improvements of approximately $37.0 million, compared to $340.2 million in the corresponding period of 2016. The decrease in restricted cash was $7.3 million during the year ended December 31, 2017, compared to an increase of $41.5 million in the corresponding period of 2016. The proceeds from sale of fixed assets were $0.2 million, compared to a loss of $10.9 million in the corresponding period of 2016.
Net Cash Used in Financing Activities
Net cash used in financing activities was $496.5 million for the year ended December 31, 2017, compared to net cash used in financing activities of $386.6 million for the year ended December 31, 2016. For the year ended December 31, 2017, cash was used for principal payments and repayments of long-term debt amounting to $496.5 million whereas for the year ended December 31, 2016, cash was used for repayments of credit facilities amounting to $215.3 million, payments for senior notes repurchase amounting to $121.5 million and repurchase of common stock amounting to $49.9 million.
Effect on exchange rate changes on cash
Effect on exchange rate changes on cash was nil for the years ended December 31, 2017 and 2016.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Our cash and cash equivalents decreased to $718.7 million as of December 31, 2016, compared to $734.7 million as of December 31, 2015, primarily due to cash used in investing and financing activities.  Our working capital surplus was $267.9 million as of December 31, 2016, compared to a $836.6 million working capital surplus as of December 31, 2015.
Net Cash Provided by Operating Activities
Net cash provided by operating activities was $763.0 million for the year ended December 31, 2016. In determining net cash provided by operating activities for the year ended December 31, 2016, the net loss was adjusted for the effects of certain non-cash items, including $3,776.3 million impairment loss, $334.2 million of depreciation and amortization, $21.0 million of amortization of deferred financing costs, $25.3 million of loss on fixed asset disposals, partly offset by the gain from the repurchase of senior notes amounting to $125.0 million. Moreover, for the year ended December 31, 2016, the net loss was also adjusted for the effects of non-cash items, such as the amortization of deferred revenue amounting to $137.0 million. Net cash provided by operating activities was $593.0 million for the year ended December 31, 2015.
Net Cash Used in Investing Activities
Net cash used in investing activities was $392.5 million for the year ended December 31, 2016, compared to $643.7 million for the year ended December 31, 2015. We incurred expenditures related to drilling units under construction and related costs of $243.0 million and drilling units, machinery, equipment and other improvements and upgrades of $97.2 million for the year ended December 31, 2016, compared to $89.9 million and $544.0 million, respectively for the year ended December 31, 2015. A loss of $10.9 million was realized from the sale of fixed assets during 2016. The increase in restricted cash was $41.5 million during the year ended December 31, 2016, compared to an increase of $10.2 million in the corresponding year ended December 31, 2015.
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Net Cash Used in Financing Activities
Net cash used in financing activities was $386.6 million for the year ended December 31, 2016. Net cash consisted of repayments of credit facilities amounting to $215.3 million, payments for senior notes repurchase amounting to $121.5 million and repurchase of common stock amounting to $49.9 million. This compares to net cash provided by financing activities of $263.3 million for the year ended December 31, 2015.
Effect on exchange rate changes on cash
Effect on exchange rate changes on cash was nil for the year ended December 31, 2016 compared to $6.8 million, loss for the year ended December 31, 2015.
Swap Agreements
The interest rate swap and cap and floor agreements were terminated during 2016 and as at December 31, 2017  there are no outstanding agreements.
See "Item 11. Quantitative and Qualitative Disclosures About Market Risk."
Currency Forward Sale Exchange Contracts
As of December 31, 2017, 2016, and 2015, we had no outstanding currency forward sale exchange contracts.
See "Item 11. Quantitative and Qualitative Disclosures About Market Risk."
C.          Research and Development, Patents and Licenses, etc.
Not applicable.
D.          Trend Information
According to industry sources, the in-service fleet as of January 2018 totaled 263 floating rigs and is expected to grow to 306 floating rigs upon the scheduled delivery of the current newbuild orderbook by the end of 2020. Historically, an increase in supply has caused a decline in utilization and dayrates until drilling units are absorbed into the market. Accordingly, dayrates have been very cyclical. We believe that the largest undiscovered offshore reserves are mostly located in ultra-deepwater fields and primarily located in the "golden triangle" between West Africa, Brazil and the Gulf of Mexico, as well as in East Africa, Australia and Southeast Asia. The location of these large offshore reserves has resulted in more than 90% of the floating drilling unit, or floater, orderbook being represented by deepwater rigs. Furthermore, due to increased focus on technically challenging operations and the inherent risk of developing offshore fields in ultra-deepwater, particularly in light of the Deepwater Horizon accident in the Gulf of Mexico, in which we were not involved, oil companies have already begun to show a preference for modern units more capable of drilling in these challenging environments.
Historically, operating results in the offshore contract drilling industry have been cyclical and directly related to the demand for and the available supply of drilling units. Throughout 2014, there was generally a balanced supply-demand situation which led to high utilization for the industry. Currently, we note certain unfavorable trends which we believe may have a material effect on our future results of operations, liquidity or capital resources, or which may cause our reported financial information not to be necessarily indicative of our future operating results of financial position.
The offshore drilling market is currently challenged by both the pace of drilling unit supply additions as well as a reduction in their demand. On the demand side, oil companies are reducing capital expenditure amidst the significant decline in oil prices which has curtailed drilling budgets. New tendering activity remains subdued as oil companies set their budgets at lower levels than seen in recent years. Drilling unit owners, such as ourselves, are bidding for available work extremely aggressively which will likely drive rates lower. On the supply side, based on industry sources, the worldwide fleet of floating rigs will increase from 263 units to up to 306 units assuming delivery of the orderbook as of January 2018. This is due to over-ordering at shipyards during the boom periods. Based on this overcapacity, significant delays and cancellations of newbuild projects can be expected. Furthermore, owners will be forced to makes decisions regarding cold stacking and scrapping of older units.
For more information on risks to our business and our industry, please read "Risk Factors."
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E.          Off-balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
F.          Tabular disclosure of contractual obligations
The following table sets forth our contractual obligations and their maturity dates as of December 31, 2017:
 Obligations
 
Total
   
Less than 1 year
   
1-3 years
   
3-5 years
   
More than 5 years
 
(U.S. Dollars in thousands)
                             
Drilling units under construction (1)
   
938,096
     
417,931
     
520,165
     
-
     
-
 
Loan payments
   
531,632
     
81,632
     
-
     
-
     
450,000
 
Interest payments (2)
   
245,400
     
36,500
     
73,100
     
73,000
     
62,800
 
Total
   
1,715,128
     
536,063
     
593,265
     
73,000
     
512,800
 
_________________
(1)
The figure includes contracted purchase obligations only.
(2)
The figures relate to interest payments under the fixed rate $450 million Senior Secured Term Loan Facility.
Recent Accounting Pronouncements:
Accounting Changes and Error Corrections: In January 2017, FASB issued ASU 2017-03, "Accounting Changes and Error Corrections (Topic 250) and Investments-Equity Method and Joint Ventures (Topic 323)". The ASU amends the Codification for SEC staff announcements made at recent Emerging Issues Task Force (EITF) meetings. The SEC guidance that specifically relates to our combined financial statement was from the September 2016 meeting, where the SEC staff expressed their expectations about the extent of disclosures registrants should make about the effects of the new FASB guidance as well as any amendments issued prior to adoption, on revenue (ASU 2014-09), leases (ASU 2016-02) and credit losses on financial instruments (ASU 2016-13) in accordance with SAB Topic 11.M. Registrants are required to disclose the effect that recently issued accounting standards will have on their financial statements when adopted in a future period. In cases where a registrant cannot reasonably estimate the impact of the adoption, then additional qualitative disclosures should be considered. The ASU incorporates these SEC staff views into ASC 250 and adds references to that guidance in the transition paragraphs of each of the three new standards.
Leases: In February 2016, the FASB issued ASU No. 2016-02, Leases (ASC 842), which requires lessees to recognize most leases on the balance sheet. This is expected to increase both reported assets and liabilities. The new lease standard does not substantially change lessor accounting. The accounting standards update requires (a) lessees to recognize a right to use asset and a lease liability for virtually all leases, and (b) updates previous accounting standards for lessors to align certain requirements with the updates to lessee accounting standards and the revenue recognition accounting standards. The update is effective for interim and annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company previously disclosed its intention to adopt this standard at the same time as it adopted the new revenue standard discussed below; however, the Company now expects to adopt this new guidance in the first quarter of 2019.  The Company is currently evaluating the impact that this new guidance will have on its consolidated financial statements.
 Revenue from Contracts with Customers: In March 2016, the FASB issued ASU 2016-08, "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) ("ASU 2016-08"), which clarifies the implementation guidance on principal versus agent considerations. In May and April 2016, the FASB issued two Updates with respect to Topic 606: ASU 2016-10, "Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing" and ASU 2016-12, "Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients." The amendments in these Updates do not change the core principle of the guidance in Topic 606, which is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by applying the following steps: (1) Identify the contract(s) with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. The amendments in Update 2016-10 simply clarify the following two aspects of Topic 606: (1) identifying performance obligations and (2) licensing implementation guidance. The amendments in Update 2016-12 similarly affect only certain narrow aspects of Topic 606; namely, (1) "Assessing the Collectability Criterion in Paragraph 606-10-25-1(e) and Accounting for Contracts That Do Not Meet the Criteria for Step 1 (Applying Paragraph 606-10-25-7)," (2) "Presentation of Sales Taxes and Other Similar Taxes Collected from Customers," (3) "Noncash Consideration," (4) "Contract Modifications at Transition," (5) "Completed Contracts at Transition," and (6)  "Technical Correction." The amendments in these Updates also affect the guidance in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606), which is not yet effective. The effective date and transition requirements for the amendments in these Updates are the same as the effective date and transition requirements in Topic 606 (and any other Topic amended by Update 2014-09). Accounting Standards Update 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," has deferred the effective date of Update 2014-09 for public business entities to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted.
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The new revenue standard may be applied using either of the following transition methods: (1) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (2) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). On January 1, 2018, the Company adopted the accounting standards update that requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services, using the modified retrospective method. The effect on Company's consolidated financial statements due to the adoption of the new accounting standard is based on the evaluation of the contract specific facts and circumstances and has no material effect on the consolidated balance sheets, statements of operations and cash flows. The company is currently evaluating the requirements and assessing the impact such requirements may have on the disclosures contained in the notes to consolidated financial statements.
Statement of Cash Flows: In August 2016, the FASB issued ASU No. 2016-15- Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments which addresses certain cash flow issues with the objective of reducing the existing diversity in practice: ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 including interim periods within that reporting period, however early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on its consolidated financial statements and notes disclosures. In November 2016, the FASB issued ASU No. 2016-18—Statement of Cash Flows (Topic 230) - Restricted Cash which addresses the requirement that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this Update apply to all entities that have restricted cash or restricted cash equivalents and are required to present a statement of cash flows under Topic 230. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 including interim periods within that reporting period, however early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on its consolidated financial statements and notes disclosures.
Measurement of Credit Losses on Financial Instruments: On June 16, 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), which introduces a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. The new model will apply to: (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and other financial assets measured at fair value through other comprehensive income, and (4) beneficial interests in securitized financial assets. This update is effective for annual and interim periods beginning after January 1, 2020. The Company is currently evaluating the provisions of this guidance and assessing its impact on its consolidated financial statements and notes disclosures.
Tax Accounting for Intra-Entity Asset Transfers: On October 24, 2016, the FASB issued ASU 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory, which requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transaction occurs as opposed to deferring tax consequences and amortizing them into future periods. This update is effective for annual and interim periods, beginning after January 1, 2018, with early adoption permitted and requires a modified retrospective approach with a cumulative-effect adjustment directly to retained earnings at the beginning of the period of adoption. The Company is currently evaluating the provisions of this guidance and assessing its impact on its consolidated financial statements and notes disclosures.
Definition of a Business: In January 2017, the FASB issued ASU 2017-01 Business Combinations to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisition (or disposals) of assets or businesses. Under current implementation guidance the existence of an integrated set of acquired activities (inputs and processes that generate outputs) constitutes an acquisition of business. This ASU provides a screen to determine when a set of assets and activities does not constitute a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This update is effective for public entities with reporting periods beginning after December 15, 2017, including interim periods within those years. The amendments of this ASU should be applied prospectively on or after the effective date. Early adoption is permitted, including adoption in an interim period 1) for transactions for which the acquisition date occurs before the issuance date or effective date of the ASU, only when the transaction has not been reported in financial statements that have been issued or made available for issuance and 2) for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. This FASB standard Update is not expected to have a material effect on the Company's future or historical statements of cash flows; however, Management will assess such impact, if circumstances arise.
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G.          Safe Harbor
See the section entitled "Forward-looking Statements" at the beginning of this annual report.
Item 6.          Directors, Senior Management and Employees
A.          Directors and senior management
Set forth below are the names, ages and positions of our directors and executive officers and the principal officers.
Directors and executive officers of Ocean Rig UDW Inc.(1) –
Name
Age
Position
George Economou
65
Chairman of the Board and Director
Anthony Kandylidis
41
Executive Vice Chairman and Director
Pankaj Khanna
47
President and Chief Executive Officer
Iraklis Sbarounis
33
Chief Financial Officer, Secretary and Director
John Liveris
66
Director
John Simon
63
Director
Karl Blanchard
58
Director
Jim Devine
59
Director
David Cusiter
56
Chief Operations Officer
     

(1)