Company Quick10K Filing
Quick10K
Helix Energy Solutions Group
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$7.48 148 $1,110
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-04-25 Quarter: 2017-04-25
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2015-02-18 Annual: 2015-02-18
10-Q 2014-10-22 Quarter: 2014-10-22
10-Q 2014-07-23 Quarter: 2014-07-23
10-Q 2014-04-23 Quarter: 2014-04-23
10-K 2014-02-21 Annual: 2014-02-21
8-K 2019-06-28 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-05-15 Officers, Shareholder Vote, Exhibits
8-K 2019-05-03 Officers, Regulation FD, Other Events, Exhibits
8-K 2019-04-22 Earnings, Regulation FD, Exhibits
8-K 2019-03-22 Officers
8-K 2019-02-19 Earnings, Regulation FD, Exhibits
8-K 2019-01-22 Enter Agreement, Other Events, Exhibits
8-K 2018-12-14 Officers, Exhibits
8-K 2018-10-22 Earnings, Regulation FD, Exhibits
8-K 2018-08-21 Officers
8-K 2018-07-23 Earnings, Regulation FD, Exhibits
8-K 2018-05-10 Shareholder Vote
8-K 2018-04-23 Earnings, Regulation FD, Exhibits
8-K 2018-03-20 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-03-13 Enter Agreement, Exhibits
8-K 2018-03-02 Regulation FD, Exhibits
8-K 2018-02-20 Earnings, Regulation FD, Exhibits
UL Unilever 157,930
AON Aon 42,450
ADC Agree Realty 2,540
PRA Proassurance 2,120
FOR Forestar Group 832
FMAO Farmers & Merchants Bancorp 342
TGLS Tecnoglass 310
PETV Petvivo Holdings 0
OMED Oncomed Pharmaceuticals 0
AGGG Antilia Group 0
HLX 2019-03-31
Part I. Financial Information
Item 1. Financial Statements
Note 1 - Basis of Presentation and New Accounting Standards
Note 2 - Company Overview
Note 3 - Details of Certain Accounts
Note 4 - Equity Investments
Note 5 - Leases
Note 6 - Long-Term Debt
Note 7 - Income Taxes
Note 8 - Shareholders' Equity
Note 9 - Revenue From Contracts with Customers
Note 10 - Earnings per Share
Note 11 - Employee Benefit Plans
Note 12 - Business Segment Information
Note 13 - Asset Retirement Obligations
Note 14 - Commitments and Contingencies and Other Matters
Note 15 - Statement of Cash Flow Information
Note 16 - Fair Value Measurements
Note 17 - Derivative Instruments and Hedging Activities
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
EX-31.1 hlx03312019-ex311.htm
EX-31.2 hlx03312019-ex312.htm
EX-32.1 hlx03312019-ex321.htm

Helix Energy Solutions Group Earnings 2019-03-31

HLX 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 hlx03312019-10q.htm HELIX ENERGY SOLUTIONS GROUP, INC. 1Q19 FORM 10-Q Document

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
þ
 
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2019
or
¨
 
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from__________ to__________
Commission File Number 001-32936
logo.jpg
 
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
Minnesota
(State or other jurisdiction
of incorporation or organization)
 
95–3409686
(I.R.S. Employer
Identification No.)
  
 
 
3505 West Sam Houston Parkway North, Suite 400 
Houston, Texas
(Address of principal executive offices)
 
 
77043
(Zip Code)
 
(281) 618–0400
(Registrant's telephone number, including area code)
NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report) 
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. þ Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). þ Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
Accelerated filer ¨
Non-accelerated filer ¨
Smaller reporting company ¨
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No
As of April 22, 2019, 148,792,936 shares of common stock were outstanding.
 




TABLE OF CONTENTS
PART I.
 
FINANCIAL INFORMATION
PAGE
 
 
 
 
Item 1.
 
Financial Statements:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
Item 3.
 
 
 
 
 
Item 4.
 
 
 
 
 
PART II.
 
OTHER INFORMATION
 
 
 
 
 
Item 1.
 
 
 
 
 
Item 2.
 
 
 
 
 
Item 6.
 
 
 
 
 
 
 

2



PART I.  FINANCIAL INFORMATION
Item 1.  Financial Statements
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
 
March 31,
2019
 
December 31,
2018
 
(Unaudited)
 
 
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
220,023

 
$
279,459

Accounts receivable:
 
 
 
Trade, net of allowance for uncollectible accounts of $0
102,072

 
67,932

Unbilled and other
41,364

 
51,943

Other current assets
87,184

 
51,594

Total current assets
450,643

 
450,928

Property and equipment
2,804,271

 
2,785,778

Less accumulated depreciation
(986,202
)
 
(959,033
)
Property and equipment, net
1,818,069

 
1,826,745

Operating lease right-of-use assets
240,332

 

Other assets, net
98,277

 
70,057

Total assets
$
2,607,321

 
$
2,347,730

 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
 
 
 
Accounts payable
$
63,849

 
$
54,813

Accrued liabilities
81,842

 
85,594

Income tax payable

 
3,829

Current maturities of long-term debt
47,888

 
47,252

Current operating lease liabilities
55,241

 

Total current liabilities
248,820

 
191,488

Long-term debt
381,319

 
393,063

Operating lease liabilities
191,545

 

Deferred tax liabilities
107,367

 
105,862

Other non-current liabilities
48,427

 
39,538

Total liabilities
977,478

 
729,951

 


 


Shareholders equity:
 
 
 
Common stock, no par, 240,000 shares authorized, 148,785 and 148,203 shares issued, respectively
1,310,738

 
1,308,709

Retained earnings
388,912

 
383,034

Accumulated other comprehensive loss
(69,807
)
 
(73,964
)
Total shareholders equity
1,629,843

 
1,617,779

Total liabilities and shareholders equity
$
2,607,321

 
$
2,347,730

The accompanying notes are an integral part of these condensed consolidated financial statements.

3



HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except per share amounts) 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
Net revenues
$
166,823

 
$
164,262

Cost of sales
150,569

 
151,279

Gross profit
16,254

 
12,983

Selling, general and administrative expenses
(15,985
)
 
(14,099
)
Income (loss) from operations
269

 
(1,116
)
Equity in losses of investment
(40
)
 
(136
)
Net interest expense
(2,098
)
 
(3,896
)
Loss on extinguishment of long-term debt

 
(1,105
)
Other income, net
1,166

 
925

Royalty income and other
2,345

 
2,855

Income (loss) before income taxes
1,642

 
(2,473
)
Income tax provision
324

 
87

Net income (loss)
$
1,318

 
$
(2,560
)
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
Basic
$
0.01

 
$
(0.02
)
Diluted
$
0.01

 
$
(0.02
)
 
 
 
 
Weighted average common shares outstanding:
 
 
 
Basic
147,421

 
146,653

Diluted
147,751

 
146,653

The accompanying notes are an integral part of these condensed consolidated financial statements.

4



HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
(in thousands)
 
 
 
 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
Net income (loss)
$
1,318

 
$
(2,560
)
Other comprehensive income, net of tax:
 
 
 
Net unrealized gain (loss) on hedges arising during the period
(149
)
 
2,153

Reclassifications to net income (loss)
1,846

 
1,627

Income taxes on hedges
(342
)
 
(815
)
Net change in hedges, net of tax
1,355

 
2,965

Unrealized loss on note receivable arising during the period

 
(629
)
Income taxes on note receivable

 
132

Unrealized loss on note receivable, net of tax

 
(497
)
Foreign currency translation gain
2,802

 
4,691

Other comprehensive income, net of tax
4,157

 
7,159

Comprehensive income
$
5,475

 
$
4,599

The accompanying notes are an integral part of these condensed consolidated financial statements.

5



HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands)
 
Common Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Shareholders’
Equity
 
Shares
 
Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2018
148,203

 
$
1,308,709

 
$
383,034

 
$
(73,964
)
 
$
1,617,779

Net income

 

 
1,318

 

 
1,318

Reclassification of deferred gain from sale and leaseback transaction to retained earnings

 

 
4,560

 

 
4,560

Foreign currency translation adjustments

 

 

 
2,802

 
2,802

Unrealized gain on hedges, net of tax

 

 

 
1,355

 
1,355

Activity in company stock plans, net and other
582

 
(659
)
 

 

 
(659
)
Share-based compensation

 
2,688

 

 

 
2,688

Balance, March 31, 2019
148,785

 
$
1,310,738

 
$
388,912

 
$
(69,807
)
 
$
1,629,843

 
Common Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Shareholders’
Equity
 
Shares
 
Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2017
147,740

 
$
1,284,274

 
$
352,906

 
$
(69,787
)
 
$
1,567,393

Net loss

 

 
(2,560
)
 

 
(2,560
)
Reclassification of stranded tax effect to retained earnings

 

 
1,530

 
(1,530
)
 

Foreign currency translation adjustments

 

 

 
4,691

 
4,691

Unrealized gain on hedges, net of tax

 

 

 
2,965

 
2,965

Unrealized loss on note receivable, net of tax

 

 

 
(497
)
 
(497
)
Equity component of debt discount on convertible senior notes

 
15,424

 

 

 
15,424

Activity in company stock plans, net and other
340

 
(862
)
 

 

 
(862
)
Share-based compensation

 
2,463

 

 

 
2,463

Balance, March 31, 2018
148,080

 
$
1,301,299

 
$
351,876

 
$
(64,157
)
 
$
1,589,018

 
The accompanying notes are an integral part of these condensed consolidated financial statements.


6



HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands) 
 
Three Months Ended
March 31,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income (loss)
$
1,318

 
$
(2,560
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
28,509

 
27,782

Amortization of debt discounts
1,513

 
1,360

Amortization of debt issuance costs
902

 
935

Share-based compensation
2,719

 
2,500

Deferred income taxes
(10
)
 
108

Equity in losses of investment
40

 
136

Loss on extinguishment of long-term debt

 
1,105

Unrealized gain on derivative contracts, net
(829
)
 
(1,534
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable, net
(22,584
)
 
22,761

Other current assets
(13,129
)
 
(3,948
)
Income tax payable
(2,370
)
 
(2,853
)
Accounts payable and accrued liabilities
(17,027
)
 
(12,256
)
Other, net
(13,298
)
 
7,510

Net cash provided by (used in) operating activities
(34,246
)
 
41,046

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(11,655
)
 
(21,214
)
Proceeds from sale of assets
25

 

Other
(326
)
 

Net cash used in investing activities
(11,956
)
 
(21,214
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Issuance of Convertible Senior Notes due 2023

 
125,000

Repurchase of Convertible Senior Notes due 2032

 
(59,478
)
Repayment of Term Loan
(936
)
 
(61,468
)
Repayment of Nordea Q5000 Loan
(8,929
)
 
(8,929
)
Repayment of MARAD Debt
(3,387
)
 
(3,226
)
Debt issuance costs
(113
)
 
(3,774
)
Payments related to tax withholding for share-based compensation
(826
)
 
(1,058
)
Proceeds from issuance of ESPP shares
136

 
159

Net cash used in financing activities
(14,055
)
 
(12,774
)
 
 
 
 
Effect of exchange rate changes on cash and cash equivalents
821

 
335

Net increase (decrease) in cash and cash equivalents
(59,436
)
 
7,393

Cash and cash equivalents:
 
 
 
Balance, beginning of year
279,459

 
266,592

Balance, end of period
$
220,023

 
$
273,985

The accompanying notes are an integral part of these condensed consolidated financial statements.

7



HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 — Basis of Presentation and New Accounting Standards
 
The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its subsidiaries (collectively, “Helix” or the “Company”). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (the “SEC”) and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).
 
The accompanying condensed consolidated financial statements have been prepared in conformity with GAAP in U.S. dollars and are consistent in all material respects with those applied in our 2018 Annual Report on Form 10-K (“2018 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. We have made all adjustments (which were normal recurring adjustments) that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive income, and statements of cash flows, as applicable. The operating results for the three-month period ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019. Our balance sheet as of December 31, 2018 included herein has been derived from the audited balance sheet as of December 31, 2018 included in our 2018 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our 2018 Form 10-K.
 
Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format.
 
New accounting standards adopted
 
In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASC 842”), which was updated by subsequent amendments. ASC 842 requires a lessee to recognize a lease right-of-use asset and related lease liability for most leases, including those classified as operating leases. ASC 842 also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We adopted ASC 842 in the first quarter of 2019 using the modified retrospective method. We also elected the package of practical expedients permitted under the transition guidance that, among other things, allows companies to carry forward their historical lease classification. Our adoption of ASC 842 resulted in the recognition of operating lease liabilities of $259.0 million and corresponding right-of-use (“ROU”) assets of $253.4 million (net of existing prepaid/deferred rent balances) as of January 1, 2019. In addition, we reclassified the remaining deferred gain of $4.6 million (net of deferred taxes of $0.9 million) on a 2016 sale and leaseback transaction to retained earnings. Subsequent to adoption, leases in foreign currencies will generate foreign currency gains and losses, and we will no longer amortize the deferred gain from the aforementioned sale and leaseback transaction. Aside from these changes, ASC 842 is not expected to have a material impact on our net earnings or cash flows.
 
New accounting standards issued but not yet effective
 
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU replaces the current incurred loss model for measurement of credit losses on financial assets (including trade receivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance is effective for annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
 
We do not expect any other recent accounting standards to have a material impact on our financial position, results of operations or cash flows.

8



Note 2 — Company Overview
 
We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We seek to provide services and methodologies that we believe are critical to maximizing production economics. We provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our “life of field” services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities (Note 12).
 
Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and two chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. We also have a semi-submersible well intervention vessel under completion, the Q7000. Our well intervention equipment includes intervention riser systems (“IRSs”), some of which we provide on a stand-alone basis, and subsea intervention lubricators (“SILs”).
 
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and a ROVDrill, which are designed to complement offshore construction and well intervention services, and three ROV support vessels under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III. We also utilize spot vessels as needed.
 
Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamically positioned floating production vessel, the Helix Fast Response System (the “HFRS”) and our ownership interest in Independence Hub, LLC (“Independence Hub”) (Note 4). The HP I has been under contract to the Phoenix field operator since February 2013 and is currently under a fixed fee agreement through at least June 1, 2023. The HFRS, which was developed in 2011 as a culmination of our experience as a responder in the 2010 Macondo well control and containment efforts, combines our HP I, Q4000 and Q5000 vessels with certain well control equipment that can be deployed to respond to a well control incident in the Gulf of Mexico. The Production Facilities segment also includes certain operating depths, along with several wells and related infrastructure, associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244 that we acquired from Marathon Oil Corporation (“Marathon Oil”) on January 18, 2019. All of our production facilities activities are located in the Gulf of Mexico.
Note 3 — Details of Certain Accounts
 
Other current assets consist of the following (in thousands): 
 
March 31,
2019
 
December 31,
2018
 
 
 
 
Contract assets (Note 9)
$
10,770

 
$
5,829

Prepaids
16,957

 
10,306

Deferred costs (Note 9)
26,344

 
27,368

Other receivable (Note 13)
26,000

 

Other
7,113

 
8,091

Total other current assets
$
87,184

 
$
51,594

 

9



Other assets, net consist of the following (in thousands): 
 
March 31,
2019
 
December 31,
2018
 
 
 
 
Prepaids
$
1,028

 
$
5,896

Deferred recertification and dry dock costs, net
21,676

 
8,525

Deferred costs (Note 9)
33,058

 
38,574

Charter deposit (1)
12,544

 
12,544

Other receivable (Note 13)
25,410

 

Other
4,561

 
4,518

Total other assets, net
$
98,277

 
$
70,057

(1)
This amount is deposited with the owner of the Siem Helix 2 to offset certain payment obligations associated with the vessel at the end of the charter term.
 
Accrued liabilities consist of the following (in thousands): 
 
March 31,
2019
 
December 31,
2018
 
 
 
 
Accrued payroll and related benefits
$
18,576

 
$
43,079

Deferred revenue (Note 9)
9,748

 
10,103

Asset retirement obligations (Note 13)
27,500

 

Derivative liability (Note 17)
7,323

 
9,311

Other
18,695

 
23,101

Total accrued liabilities
$
81,842

 
$
85,594

 
Other non-current liabilities consist of the following (in thousands): 
 
March 31,
2019
 
December 31,
2018
 
 
 
 
Investee losses in excess of investment (Note 4)
$
5,466

 
$
6,035

Deferred gain on sale of property (1)

 
5,052

Deferred revenue (Note 9)
13,582

 
15,767

Asset retirement obligations (Note 13)
26,282

 

Derivative liability (Note 17)

 
884

Other
3,097

 
11,800

Total other non-current liabilities
$
48,427

 
$
39,538

(1)
Relates to the sale and lease-back in January 2016 of our office and warehouse property located in Aberdeen, Scotland. The deferred gain had been amortized over a 15-year minimum lease term prior to our adoption of ASC 842 on January 1, 2019. See Note 1 for the effect of ASC 842 on this deferred gain.
Note 4 — Equity Investments
 
We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in the U.S. Gulf of Mexico in a water depth of 8,000 feet. Since we are committed to providing our pro-rata portion of the necessary level of financial support for Independence Hub to pay its obligations as they become due, we recorded a liability of $10.6 million at March 31, 2019 and $11.2 million at December 31, 2018 for our share of the estimated obligations, net of remaining working capital. This liability is reflected in “Accrued liabilities” and “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

10



Note 5 — Leases
 
We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. We also sublease some of our facilities under non-cancelable sublease agreements.
 
Leases with a term greater than one year are recognized on our balance sheet as ROU assets and lease liabilities. We have elected not to recognize on our balance sheet leases with an initial term of one year or less. Lease liabilities and their corresponding ROU assets are recorded at the commencement date based on the present value of lease payments over the expected lease term. We use our incremental borrowing rate, which would be the rate incurred to borrow on a collateralized basis over a similar term in a similar economic environment, to calculate the present value of lease payments. ROU assets are adjusted for any initial direct costs paid or incentives received.
 
We separate our long-term vessel charters between their lease components and non-lease services. We estimate the lease component using the residual estimate approach by estimating the non-lease services, which are primarily crew, repair and maintenance, and regulatory certification costs. For all other leases, we have not separated the lease components and non-lease services. The lease term may include options to extend or terminate the lease when it is reasonably certain that we will exercise the option.
 
We recognize operating lease cost on a straight-line basis over the lease term for both (i) leases that are recognized on the balance sheet and (ii) short-term leases. We recognize lease cost related to variable lease payments that are not recognized on the balance sheet in the period in which the obligation is incurred. The following table details the components of our lease cost (in thousands):
 
Three Months Ended
 
March 31, 2019
 
 
Operating lease cost
$
18,133

Variable lease cost
3,075

Short-term lease cost
4,158

Sublease income
(353
)
Net lease cost
$
25,013

 
Maturities of our operating lease liabilities as of March 31, 2019 are as follows (in thousands):
 
Vessels
 
Facilities and Equipment
 
Total
 
 
 
 
 
 
Remainder of 2019
$
49,454

 
$
5,167

 
$
54,621

2020
60,362

 
6,258

 
66,620

2021
54,611

 
5,510

 
60,121

2022
52,106

 
5,077

 
57,183

2023
34,580

 
4,512

 
39,092

Thereafter
2,470

 
10,434

 
12,904

Total lease payments
$
253,583

 
$
36,958

 
$
290,541

Less: imputed interest
(35,878
)
 
(7,877
)
 
(43,755
)
Total operating lease liabilities
$
217,705

 
$
29,081

 
$
246,786

 
 
 
 
 
 
Current operating lease liabilities
$
50,242

 
$
4,999

 
$
55,241

Non-current operating lease liabilities
167,463

 
24,082

 
191,545

Total operating lease liabilities
$
217,705

 
$
29,081

 
$
246,786

 

11



The following table presents the weighted average remaining lease term and discount rate:
 
March 31, 2019
 
 
Weighted average remaining lease term
4.6 years

Weighted average discount rate
7.54
%
 
The following table presents other information related to our operating leases (in thousands):
 
Three Months Ended
 
March 31, 2019
 
 
Cash paid for operating lease liabilities
$
17,148

ROU assets obtained in exchange for new operating lease obligations
89

 
As previously disclosed in our 2018 Annual Report on Form 10-K and under the previous lease accounting standard, future minimum lease payments for our operating leases as of December 31, 2018 were as follows (in thousands):
 
Vessels
 
Facilities and Equipment
 
Total
 
 
 
 
 
 
2019
$
116,620

 
$
5,881

 
$
122,501

2020
96,800

 
5,340

 
102,140

2021
89,216

 
5,185

 
94,401

2022
90,371

 
5,064

 
95,435

2023
51,266

 
4,533

 
55,799

Thereafter

 
10,448

 
10,448

Total lease payments
$
444,273

 
$
36,451

 
$
480,724

Note 6 — Long-Term Debt
 
Scheduled maturities of our long-term debt outstanding as of March 31, 2019 are as follows (in thousands):
 
Term
Loan (1)
 
2022
Notes
 
2023 Notes
 
MARAD
Debt
 
Nordea
Q5000
Loan
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
Less than one year
$
5,147

 
$

 
$

 
$
7,027

 
$
35,714

 
$
47,888

One to two years
27,610

 

 

 
7,378

 
80,357

 
115,345

Two to three years

 

 

 
7,746

 

 
7,746

Three to four years

 
125,000

 

 
8,133

 

 
133,133

Four to five years

 

 
125,000

 
8,539

 

 
133,539

Over five years

 

 

 
28,258

 

 
28,258

Gross debt
32,757

 
125,000

 
125,000

 
67,081

 
116,071

 
465,909

Unamortized debt discounts (2)

 
(10,305
)
 
(16,984
)
 

 

 
(27,289
)
Unamortized debt issuance costs (3)
(310
)
 
(1,633
)
 
(2,738
)
 
(3,903
)
 
(829
)
 
(9,413
)
Total debt
32,447

 
113,062

 
105,278

 
63,178

 
115,242

 
429,207

Less: current maturities
(5,147
)
 

 

 
(7,027
)
 
(35,714
)
 
(47,888
)
Long-term debt
$
27,300

 
$
113,062

 
$
105,278

 
$
56,151

 
$
79,528

 
$
381,319


12



(1)
Term Loan pursuant to the Credit Agreement (as defined below) matures in June 2020.
(2)
Our Convertible Senior Notes due 2022 (the “2022 Notes”) will increase to their face amount through accretion of the debt discount through May 2022. Our Convertible Senior Notes due 2023 (the “2023 Notes”) will increase to their face amount through accretion of the debt discount through September 2023.
(3)
Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.
 
Below is a summary of certain components of our indebtedness:
 
Credit Agreement
 
On June 30, 2017, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”). The amended and restated credit facility is comprised of a $100 million term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) of up to $150 million (the “Revolving Loans”). The Revolving Credit Facility permits us to obtain letters of credit up to a sublimit of $25 million. Pursuant to the Credit Agreement, subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may request aggregate commitments up to $100 million with respect to an increase in the Revolving Credit Facility, additional term loans or a combination thereof. As of March 31, 2019, we had no borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the applicable leverage ratio covenant, totaled $147.3 million, net of $2.7 million of letters of credit issued under that facility.
 
The Term Loan and the Revolving Loans (together, the “Loans”), at our election, bear interest at Bank of America’s base rate, a LIBOR rate or a combination thereof. The Term Loan bearing interest at the base rate will bear interest at a per annum rate equal to Bank of America’s base rate plus a margin of 3.25%. The Term Loan bearing interest at a LIBOR rate will bear interest per annum at the LIBOR rate selected by us plus a margin of 4.25%. The interest rate on the Term Loan was 6.75% as of March 31, 2019. The Revolving Loans bearing interest at the base rate will bear interest at a per annum rate equal to Bank of America’s base rate plus a margin ranging from 1.75% to 3.25%. The Revolving Loans bearing interest at a LIBOR rate will bear interest per annum at the LIBOR rate selected by us plus a margin ranging from 2.75% to 4.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate Loans times the daily amount available to be drawn under the applicable letter of credit. Margins on the Revolving Loans will vary in relation to the Consolidated Total Leverage Ratio (as defined below) as provided for in the Credit Agreement. We also pay a fixed commitment fee of 0.50% per annum on the unused portion of our Revolving Credit Facility.
 
The Term Loan principal is required to be repaid in quarterly installments totaling 5% in the first loan year, 10% in the second loan year and 15% in the third loan year, with a balloon payment at maturity. Installment amounts are subject to adjustment for any prepayments on the Term Loan. We may prepay indebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay indebtedness outstanding under the Revolving Credit Facility without premium or penalty, and may reborrow any amounts prepaid up to the amount of the Revolving Credit Facility. The Loans mature on June 30, 2020.
 
The Credit Agreement and the other loan documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, which we consider customary for this type of facility. The covenants include certain restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and make capital expenditures. In addition, the Credit Agreement obligates us to meet minimum ratios of EBITDA to interest charges (Consolidated Interest Coverage Ratio) and funded debt to EBITDA (Consolidated Total Leverage Ratio), and provided there are no Loans outstanding, the funded debt ratio requirement permits us to offset a certain amount of cash against the funded debt used in the calculation (Consolidated Net Leverage Ratio). After the Term Loan is repaid in full, if there are any Loans outstanding, including unreimbursed draws under letters of credit issued under the Revolving Credit Facility, we also are required to ensure that the ratio of our total secured indebtedness to EBITDA (Consolidated Secured Leverage Ratio) does not exceed a maximum permitted ratio. The Credit Agreement also obligates us to maintain certain cash levels depending on the type of indebtedness that is outstanding.
 

13



We may from time to time designate one or more of our foreign subsidiaries as subsidiaries not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”). The debt and EBITDA of the Unrestricted Subsidiaries are not included in the calculations of our financial covenants, except for the debt and EBITDA of Helix Q5000 Holdings, S.a.r.l., a wholly owned subsidiary incorporated in Luxembourg (“Q5000 Holdings”). Our obligations under the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I - Title XI, Inc.) and by Canyon Offshore Limited, a wholly owned Scottish subsidiary. Our obligations under the Credit Agreement, and those of our subsidiary guarantors under their guarantee, are secured by (i) most of the assets of the parent company, (ii) the shares of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Canyon Offshore Limited, and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Canyon Offshore Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries.
 
In March 2018, we prepaid $61 million of the Term Loan with a portion of the net proceeds from the 2023 Notes. We recognized a $0.9 million loss to write off the related unamortized debt issuance costs, which loss is presented as “Loss on extinguishment of long-term debt” in the accompanying condensed consolidated statement of operations.
 
On January 18, 2019, contemporaneously with our purchase from Marathon Oil of certain operating depths associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure, we amended our Credit Agreement to permit the issuance of certain security to third parties for required plug and abandonment obligations and to make certain capital expenditures in connection with acquired assets (Notes 2 and 13).
 
Convertible Senior Notes Due 2022
 
On November 1, 2016, we completed a public offering and sale of our 2022 Notes in the aggregate principal amount of $125 million. The 2022 Notes bear interest at a rate of 4.25% per annum and are payable semi-annually in arrears on November 1 and May 1 of each year, beginning on May 1, 2017. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2022 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 71.9748 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.
 
Prior to November 1, 2019, the 2022 Notes are not redeemable. On or after November 1, 2019, if certain conditions are met, we may redeem all or any portion of the 2022 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium” (as defined in the indenture governing the 2022 Notes). Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change” (as defined in the indenture governing the 2022 Notes).
 
The indenture governing the 2022 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2022 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2022 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.
 
The 2022 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million ($11.0 million net of tax) as a result of separating the equity component. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2022 Notes at their inception. For the three-month periods ended March 31, 2019 and 2018, interest expense (including amortization of the debt discount) related to the 2022 Notes totaled $2.1 million and $2.0 million, respectively. The remaining unamortized debt discount of the 2022 Notes was $10.3 million at March 31, 2019 and $11.0 million at December 31, 2018.
 

14



Convertible Senior Notes Due 2023
 
On March 20, 2018, we completed a public offering and sale of our 2023 Notes in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2023 Notes were approximately $121 million after deducting the underwriters’ discounts and commissions and estimated offering expenses. We used the net proceeds from the issuance of the 2023 Notes to fund the required repurchase by us of $59.3 million in principal of Convertible Senior Notes due 2032 (the “2032 Notes”) described below and to prepay $61 million of our Term Loan.
 
The 2023 Notes bear interest at a rate of 4.125% per annum and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2018. The 2023 Notes mature on September 15, 2023 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2023 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 105.6133 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $9.47 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.
 
Prior to March 15, 2021, the 2023 Notes are not redeemable. On or after March 15, 2021, if certain conditions are met, we may redeem all or any portion of the 2023 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium” (as defined in the indenture governing the 2023 Notes). Holders of the 2023 Notes may require us to repurchase the notes following a “fundamental change” (as defined in the indenture governing the 2023 Notes).
 
The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2023 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2023 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.
 
The 2023 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2023 Notes, we recorded a debt discount of $20.1 million ($15.9 million net of tax) as a result of separating the equity component. The effective interest rate for the 2023 Notes is 7.8% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2023 Notes at their inception. For the three-month periods ended March 31, 2019 and 2018, interest expense (including amortization of the debt discount) related to the 2023 Notes totaled $2.1 million and $0.4 million, respectively. The remaining unamortized debt discount of the 2023 Notes was $17.0 million at March 31, 2019 and $17.8 million at December 31, 2018.
 
MARAD Debt
 
This U.S. government-guaranteed financing (the “MARAD Debt”), pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. The MARAD Debt is payable in equal semi-annual installments, matures in February 2027 and bears interest at a rate of 4.93%.
 
Nordea Credit Agreement
 
In September 2014, Q5000 Holdings entered into a credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) in an amount of up to $250 million. The Nordea Q5000 Loan was funded in the amount of $250 million in April 2015 at the time the Q5000 vessel was delivered to us. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., also a wholly owned Luxembourg subsidiary, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.
 

15



The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. Q5000 Holdings may elect to prepay indebtedness outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Quarterly principal installments are subject to adjustment for any prepayments on this debt. In June 2015, we entered into interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 17). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.
 
The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants and prepayment requirements, that we consider customary for this type of transaction. The covenants include restrictions on Q5000 Holdings’s ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, and pay dividends. In addition, the Nordea Credit Agreement obligates Q5000 Holdings to meet certain minimum financial requirements, including liquidity, consolidated debt service coverage and collateral maintenance.
 
Convertible Senior Notes Due 2032 
 
In March 2012, we issued $200 million of 3.25% Convertible Senior Notes, which were originally scheduled to mature on March 15, 2032. In March 2018, we made a tender offer for the repurchase of the 2032 Notes outstanding on the first repurchase date as required by the indenture governing the 2032 Notes, and as a result we repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018. The total repurchase price was $59.5 million, including $0.2 million in fees. We recognized a $0.2 million loss in connection with the repurchase of the 2032 Notes. The loss is presented as “Loss on extinguishment of long-term debt” in the accompanying condensed consolidated statement of operations. On May 4, 2018, we redeemed the remaining $0.8 million in aggregate principal amount of the 2032 Notes.
 
Other 
 
In accordance with our Credit Agreement, the 2022 Notes, the 2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. As of March 31, 2019, we were in compliance with these covenants.
 
The following table details the components of our net interest expense (in thousands): 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
Interest expense
$
7,896

 
$
8,299

Interest income
(758
)
 
(590
)
Capitalized interest
(5,040
)
 
(3,813
)
Net interest expense
$
2,098

 
$
3,896

Note 7 — Income Taxes
 
We believe that our recorded deferred tax assets and liabilities are reasonable. However, tax laws and regulations are subject to interpretation, and the outcomes of tax disputes are inherently uncertain; therefore, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.
 
The effective tax rates for the three-month periods ended March 31, 2019 and 2018 were 19.7% and (3.5)%, respectively. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions.

16



Income taxes are provided based on the U.S. statutory rate and the local statutory rate for each foreign jurisdiction adjusted for items that are allowed as deductions for federal and foreign income tax reporting purposes, but not for book purposes. The primary differences between the U.S. statutory rate and our effective rate are as follows: 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
U.S. statutory rate
21.0
 %
 
21.0
 %
Foreign provision
(2.7
)
 
(19.1
)
Other
1.4

 
(5.4
)
Effective rate
19.7
 %
 
(3.5
)%
Note 8 — Shareholders’ Equity
 
The components of accumulated other comprehensive income (loss) (“accumulated OCI”) are as follows (in thousands): 
 
March 31,
2019
 
December 31,
2018
 
 
 
 
Cumulative foreign currency translation adjustment
$
(67,053
)
 
$
(69,855
)
Net unrealized loss on hedges, net of tax (1)
(2,754
)
 
(4,109
)
Accumulated OCI
$
(69,807
)
 
$
(73,964
)
(1)
Relates to foreign currency hedges for the Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan (Note 17) and is net of deferred income taxes totaling $0.7 million at March 31, 2019 and $1.0 million at December 31, 2018.
Note 9 — Revenue from Contracts with Customers
 
We generate revenue in our Well Intervention segment by supplying vessels, personnel and equipment to provide well intervention services, which involve providing marine access, serving as a deployment mechanism to the subsea well, connecting to and maintaining a secure connection to the subsea well and maintaining well control through the duration of the intervention services. We also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs, trenchers and ROVDrills to provide subsea construction, inspection, repair and maintenance services to oil and gas companies as well as subsea trenching and burial of pipelines and cables for the oil and gas and the renewable energy industries. We also provide integrated robotic services by supplying vessels that deploy the ROVs and trenchers. Our Production Facilities segment generates revenue by supplying vessels, personnel and equipment for oil and natural gas processing, well control response services, and oil and gas production from owned properties.
 
Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities.
 
We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration for these activities as well as contract fulfillment activities is allocated to the single performance obligation on a systematic basis that depicts the pattern of the provision of our services to the customer.
 

17



The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We do not generally provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. The estimated amount of variable consideration is constrained and is only included in the transaction price to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.
 
Dayrate Contracts.  Revenues generated from dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g., operating rate, standby rate and repair rate). Invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month.
 
Dayrate contracts also may include fees charged to the customer for mobilizing and/or demobilizing equipment and personnel. Mobilization and demobilization fees are associated with contract fulfillment activities, and related revenue (subject to any constraint on estimates of variable consideration) is allocated to the single performance obligation and recognized ratably over the initial term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer. See further discussion on contract liabilities under “Contract balances” below.
 
We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.
 
A dayrate contract modification involving an extension of the contract by adding additional days of services is generally accounted for prospectively as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.
 
Lump Sum Contracts.  Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.
 
We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue (either as an increase in or a reduction of revenue) on a cumulative catch-up basis.
 
For additional information regarding revenue recognition, see Notes 2 and 10 to our 2018 Form 10-K.

18



Disaggregation of Revenue
 
The following table provides information about disaggregated revenue by contract duration (in thousands): 
 
 
Well Intervention
 
Robotics
 
Production Facilities
 
Intercompany Eliminations (1)
 
Total Revenue
Three months ended March 31, 2019
 
 
 
 
 
 
 
 
 
 
Short-term
$
29,805

 
$
24,930

 
$

 
$

 
$
54,735

Long-term (2)
92,426

 
14,111

 
15,253

 
(9,702
)
 
112,088

Total
$
122,231

 
$
39,041

 
$
15,253

 
$
(9,702
)
 
$
166,823

 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2018
 
 
 
 
 
 
 
 
 
 
Short-term
$
42,027

 
$
20,324

 
$

 
$

 
$
62,351

Long-term (2)
87,542

 
6,845

 
16,321

 
(8,797
)
 
101,911

Total
$
129,569

 
$
27,169

 
$
16,321

 
$
(8,797
)
 
$
164,262

(1)
Intercompany revenues among our business segments are under agreements that are considered long-term.
(2)
Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.
 
Contract Balances
 
Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable that have been billed to customers are recorded as trade accounts receivable while accounts receivable that have not been billed to customers are recorded as unbilled accounts receivable.
 
Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” on the accompanying condensed consolidated balance sheets (Note 3). Contract assets were $10.8 million at March 31, 2019 and $5.8 million at December 31, 2018. Impairment losses recognized on our accounts receivable and contract assets were immaterial for the three-month periods ended March 31, 2019 and 2018.
 
Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to the single performance obligation and recognized ratably over the contract term and/or (ii) the amount billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” on the accompanying condensed consolidated balance sheets (Note 3). Contract liabilities totaled $23.3 million at March 31, 2019 and $25.9 million at December 31, 2018. Revenue recognized for the three-month periods ended March 31, 2019 and 2018 included $2.5 million and $8.6 million, respectively, that were included in the contract liability balance at the beginning of each period.
 
We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.
 

19



Performance Obligations
 
As of March 31, 2019, $1.1 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $408.4 million in 2019, $396.4 million in 2020 and $277.8 million in 2021 and thereafter. These amounts included fixed consideration and estimated variable consideration for both wholly and partially unsatisfied performance obligations, including mobilization and demobilization fees. These amounts are derived from the specific terms of our contracts, and the expected timing for revenue recognition is based on the estimated start date and duration of each contract according to the information known at March 31, 2019.
 
For the three-month periods ended March 31, 2019 and 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.
 
Contract Fulfillment Costs
 
Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” on the accompanying condensed consolidated balance sheets (Note 3). Our deferred contract costs totaled $59.4 million at March 31, 2019 and $65.9 million at December 31, 2018. For the three-month periods ended March 31, 2019 and 2018, we recorded $7.7 million and $8.9 million, respectively, related to amortization of deferred contract costs existing at the beginning of each period, and there were no associated impairment losses.
Note 10 — Earnings Per Share
 
We have shares of restricted stock issued and outstanding that are currently unvested. Shares of restricted stock are considered participating securities because holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common stock. We are required to compute earnings per share (“EPS”) under the two-class method in periods in which we have earnings. Under the two-class method, the undistributed earnings for each period are allocated based on the participation rights of both common shareholders and the holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. For periods in which we have a net loss we do not use the two-class method as holders of our restricted shares are not obligated to share in such losses.
 
The presentation of basic EPS on the face of the accompanying condensed consolidated statements of operations is computed by dividing net income or loss by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the numerator excludes the effects of dilutive common stock equivalents, if any. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations are as follows (in thousands): 

20



 
Three Months Ended
March 31, 2019
 
Three Months Ended
March 31, 2018
 
Income
 
Shares
 
Income
 
Shares
Basic:
 
 
 
 
 
 
 
Net income (loss)
$
1,318

 
 
 
$
(2,560
)
 
 
Less: Undistributed earnings allocated to participating securities
(12
)
 
 
 

 
 
Undistributed earnings (loss) allocated to common shares
$
1,306

 
147,421

 
$
(2,560
)
 
146,653

 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
Undistributed earnings (loss) allocated to common shares
$
1,306

 
147,421

 
$
(2,560
)
 
146,653

Effect of dilutive securities:
 
 
 
 
 
 
 
Share-based awards other than participating securities

 
330

 

 

Net income (loss)
$
1,306

 
147,751

 
$
(2,560
)
 
146,653

 
 
 
 
 
 
 
 
We had a net loss for the three-month period ended March 31, 2018. Accordingly, our diluted EPS calculation for that period was equivalent to our basic EPS calculation since diluted EPS excluded any assumed exercise or conversion of common stock equivalents, which were deemed to be anti-dilutive. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands): 
 
Three Months Ended
 
March 31, 2018
 
 
Diluted shares (as reported)
146,653

Share-based awards
243

Total
146,896

 
In addition, the following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 2032 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands): 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
2022 Notes
8,997

 
8,997

2023 Notes
13,202

 
1,614

2032 Notes (1)

 
2,113

(1)
The 2032 Notes were fully redeemed in May 2018.

21



Note 11 — Employee Benefit Plans
 
Long-Term Incentive Plan 
 
As of March 31, 2019, there were 1.4 million shares of our common stock available for issuance under our long-term incentive plan, the 2005 Long-Term Incentive Plan, as amended and restated January 1, 2017 (the “2005 Incentive Plan”). During the three-month period ended March 31, 2019, the following grants of share-based awards were made under the 2005 Incentive Plan: 
Date of Grant
 
 
Shares/Units
 
 
 
Grant Date
Fair Value
Per Share/Unit
 
 
Vesting Period
 
 
 
 
 
 
 
 
 
 
 
January 2, 2019 (1)
 
 
688,540

 
 
 
$
5.41

 
 
33% per year over three years
January 2, 2019 (2)
 
 
688,540

 
 
 
7.60

 
 
100% on January 2, 2022
January 2, 2019 (3)
 
 
11,841

 
 
 
5.41

 
 
100% on January 1, 2021
(1)
Reflects grants of restricted stock to our executive officers and select management employees.
(2)
Reflects grants of performance share units (“PSUs”) to our executive officers and select management employees. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum amount of the award being 200% of the original awarded PSUs and the minimum amount being zero.
(3)
Reflects grants of restricted stock to certain independent members of our Board of Directors (our “Board”) who have elected to take their quarterly fees in stock in lieu of cash.
 
Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting period on a straight-line basis. Forfeitures are recognized as they occur. For the three-month periods ended March 31, 2019 and 2018, $1.3 million and $1.5 million, respectively, were recognized as share-based compensation related to restricted stock.
 
The estimated fair value of PSUs is determined using a Monte Carlo simulation model. PSUs granted prior to 2017 could be settled in either cash or shares of our common stock and were accounted for as liability awards. Beginning in 2017, PSUs granted are to be settled solely in shares of our common stock and therefore are accounted for as equity awards. Compensation cost for PSUs that are accounted for as equity awards is measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line basis. For the three-month periods ended March 31, 2019 and 2018, $1.3 million and $1.0 million, respectively, were recognized as share-based compensation related to PSUs. The liability balance for previously unvested PSUs granted in January 2016 was $11.1 million at December 31, 2018, which we settled in cash when those PSUs vested in January 2019.
 
Additionally in 2018 and 2019, we granted $5.2 million and $4.5 million of fixed value cash awards to select management employees under the 2005 Incentive Plan. The value of fixed value cash awards is recognized on a straight-line basis over a vesting period of three years. For the three-month periods ended March 31, 2019 and 2018, $0.8 million and $0.4 million, respectively, were recognized as compensation cost.
 
Employee Stock Purchase Plan 
 
We have an employee stock purchase plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance, of which 0.5 million shares were available for issuance as of March 31, 2019. The ESPP currently has a purchase limit of 130 shares per employee per purchase period.
 
For more information regarding our employee benefit plans, including our long-term incentive stock-based and cash plans and our ESPP, see Note 12 to our 2018 Form 10-K.

22



Note 12 — Business Segment Information
 
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention business segment for financial reporting purposes. Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and the chartered Siem Helix 1 and Siem Helix 2 vessels. Our well intervention equipment includes IRSs, some of which we provide on a stand-alone basis, and SILs. Our Robotics segment includes ROVs, trenchers and a ROVDrill, which are designed to complement offshore construction and well intervention services, and three ROV support vessels under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III. Our Production Facilities segment includes the HP I, the HFRS, our ownership interest in Independence Hub (Note 4) and our ownership of certain oil and gas properties that we acquired from Marathon Oil in January 2019 (Note 13). All material intercompany transactions between the segments have been eliminated.
 
We evaluate our performance based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands): 
 
Three Months Ended
March 31,
 
2019
 
2018
Net revenues —
 
 
 
Well Intervention
$
122,231

 
$
129,569

Robotics
39,041

 
27,169

Production Facilities
15,253

 
16,321

Intercompany eliminations
(9,702
)
 
(8,797
)
Total
$
166,823

 
$
164,262

 
 
 
 
Income (loss) from operations —
 
 
 
Well Intervention
$
9,641

 
$
13,877

Robotics
(3,904
)
 
(14,317
)
Production Facilities
4,405

 
7,359

Segment operating income
10,142

 
6,919

Corporate, eliminations and other
(9,873
)
 
(8,035
)
Total
$
269

 
$
(1,116
)
 
Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties. Intercompany segment revenues are as follows (in thousands): 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
Well Intervention
$
3,225

 
$
1,952

Robotics
6,477

 
6,845

Total
$
9,702

 
$
8,797

 

23



Segment assets are comprised of all assets attributable to each reportable segment. Corporate and other includes all assets not directly identifiable with our business segments, most notably the majority of our cash and cash equivalents. The following table reflects total assets by reportable segment (in thousands): 
 
March 31,
2019
 
December 31,
2018
 
 
 
 
Well Intervention
$
2,104,002

 
$
1,916,638

Robotics
190,473

 
147,602

Production Facilities
182,830

 
120,845

Corporate and other
130,016

 
162,645

Total
$
2,607,321

 
$
2,347,730

Note 13 — Asset Retirement Obligations
 
Our asset retirement obligations (“AROs”) consist of estimated costs for subsea infrastructure plugging and abandonment activities. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the passage of time as accretion expense, which is a component of our depreciation and amortization expense. An ARO liability may also change based on revisions in estimated costs and/or timing to settle the obligations.
 
The following table describes the changes in our AROs (both current and long-term) (in thousands): 
AROs at January 1, 2019
$

Liability incurred during the period (1)
53,294

Accretion expense
488

AROs at March 31, 2019
$
53,782

(1)
In connection with the acquisition on January 18, 2019 of certain assets related to the Droshky Prospect (Note 2), we assumed the AROs for the required plug and abandonment of those assets in exchange for agreed-upon amounts to be paid by Marathon Oil as the plugging and abandonment work is completed. We recognized $53.3 million of ARO liability, $50.8 million of receivables and $2.5 million of acquired property for this transaction.
Note 14 — Commitments and Contingencies and Other Matters
 
Commitments
 
We have charter agreements with Siem Offshore AS (“Siem”) for the Siem Helix 1 and Siem Helix 2 vessels used in connection with our contracts with Petróleo Brasileiro S.A. (“Petrobras”) to perform well intervention work offshore Brazil. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates with options to extend. We have charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The charter agreements expire in October 2019 for the Grand Canyon, in April 2021 for the Grand Canyon II and in May 2023 for the Grand Canyon III.
 
In September 2013, we entered into a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% is due upon the delivery of the vessel, which at our option can be deferred until December 31, 2019. We are also contractually committed to reimburse the shipyard for its costs in connection with the deferment of the Q7000’s delivery beyond 2017. At March 31, 2019, our total investment in the Q7000 was $413.3 million, including $276.8 million of installment payments to the shipyard. Currently, equipment is being manufactured and installed for the completion of the vessel.
 

24



Contingencies and Claims
 
We believe that there are currently no contingencies that would have a material adverse effect on our financial position, results of operations and cash flows.
 
Litigation
 
We are involved in various legal proceedings, some involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act. In addition, from time to time we receive other claims, such as contract and employment-related disputes, in the normal course of business.
Note 15 — Statement of Cash Flow Information
 
We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less. The following table provides supplemental cash flow information (in thousands): 
 
Three Months Ended
March 31,
 
2019
 
2018
 
 
 
 
Interest paid, net of interest capitalized
$
1,604

 
$
2,238

Income taxes paid
2,704

 
3,036

 
Our non-cash investing activities include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions totaled $9.5 million at March 31, 2019 and $9.9 million at December 31, 2018.
Note 16 — Fair Value Measurements
 
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: 
 
Level 1 — Observable inputs such as quoted prices in active markets;
Level 2 — Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
Level 3 — Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.
 
Assets and liabilities measured at fair value are based on one or more of three valuation approaches as follows: 
 
(a)
Market Approach — Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
(b)
Cost Approach — Amount that would be required to replace the service capacity of an asset (replacement cost).
(c)
Income Approach — Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).
 

25



Our financial instruments include cash and cash equivalents, receivables, accounts payable, long-term debt and derivative instruments. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments. The fair value of our derivative instruments (Note 17) reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. The following tables provide additional information relating to those financial instruments measured at fair value on a recurring basis (in thousands): 
 
Fair Value Measurements at
March 31, 2019 Using
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Valuation
Approach
Assets:
 
 
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
717

 
$

 
$
717

 
(c)
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
Foreign exchange contracts — hedging instruments

 
4,167

 

 
4,167

 
(c)
Foreign exchange contracts — non-hedging instruments

 
3,156

 

 
3,156

 
(c)
Total net liability
$

 
$
6,606

 
$

 
$
6,606

 
 
 
 
Fair Value Measurements at
December 31, 2018 Using
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Valuation
Approach
Assets:
 
 
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
1,064

 
$

 
$
1,064

 
(c)
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
Foreign exchange contracts — hedging instruments

 
6,211

 

 
6,211

 
(c)
Foreign exchange contracts — non-hedging instruments

 
3,984

 

 
3,984

 
(c)
Total net liability
$

 
$
9,131

 
$

 
$
9,131

 
 
 
The principal amount and estimated fair value of our long-term debt are as follows (in thousands): 
 
March 31, 2019
 
December 31, 2018
 
Principal Amount (1)
 
Fair
Value (2) (3)
 
Principal Amount (1)
 
Fair
Value (2) (3)
 
 
 
 
 
 
 
 
Term Loan (matures June 2020)
$
32,757

 
$
32,716

 
$
33,693

 
$
33,314

Nordea Q5000 Loan (matures April 2020)
116,071

 
115,200

 
125,000

 
122,500

MARAD Debt (matures February 2027)
67,081

 
70,997

 
70,468

 
74,406

2022 Notes (mature May 2022)
125,000

 
123,438

 
125,000

 
114,298

2023 Notes (mature September 2023)
125,000

 
141,250

 
125,000

 
114,688

Total debt
$
465,909

 
$
483,601

 
$
479,161

 
$
459,206


26



(1)
Principal amount includes current maturities and excludes the related unamortized debt discount and debt issuance costs. See Note 6 for additional disclosures on our long-term debt.
(2)
The estimated fair value of the 2022 Notes and the 2023 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the Term Loan, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.
(3)
The principal amount and fair value of the 2022 Notes and the 2023 Notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.
Note 17 — Derivative Instruments and Hedging Activities
 
Our business is exposed to market risks associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we enter into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative instruments are reflected in the accompanying condensed consolidated balance sheets at fair value.
 
We engage solely in cash flow hedges. Cash flow hedges are entered into to hedge the variability of cash flows related to a forecasted transaction or to be received or paid related to a recognized asset or liability. Changes in the fair value of derivative instruments that are designated as cash flow hedges are reported in OCI. These changes are subsequently reclassified into earnings when the hedged transactions settle. In addition, any change in the fair value of a derivative instrument that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.
 
For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 18 to our 2018 Form 10-K.
 
Interest Rate Risk
 
From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. In June 2015 we entered into interest rate swap contracts to fix the interest rate on $187.5 million of our Nordea Q5000 Loan (Note 6). These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. Our interest rate swap contracts qualify for cash flow hedge accounting treatment. Changes in the fair value of interest rate swaps are reported in accumulated OCI (net of tax). These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense.
 
Foreign Currency Exchange Rate Risk
 
Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. We enter into foreign currency exchange contracts from time to time to stabilize expected cash outflows related to our vessel charters that are denominated in foreign currencies.
 
In February 2013, we entered into foreign currency exchange contracts to hedge our foreign currency exposure associated with the Grand Canyon II and Grand Canyon III charter payments denominated in Norwegian kroner through July 2019 and February 2020, respectively. Unrealized losses associated with our foreign currency exchange contracts that qualify for hedge accounting treatment are included in accumulated OCI (net of tax). Changes in unrealized losses associated with the foreign currency exchange contracts that are not designated as cash flow hedges are reflected in “Other income, net” in the accompanying condensed consolidated statements of operations.
 

27



Quantitative Disclosures Relating to Derivative Instruments 
 
The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments (in thousands): 
 
March 31, 2019
 
December 31, 2018
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Asset Derivative Instruments:
 
 
 
 
 
 
 
Interest rate swaps
Other current assets
 
$
685

 
Other current assets
 
$
863

Interest rate swaps
Other assets, net
 
32

 
Other assets, net
 
201

 
 
 
$
717

 
 
 
$
1,064

 
 
 
 
 
 
 
 
Liability Derivative Instruments:
 
 
 
 
 
 
 
Foreign exchange contracts
Accrued liabilities
 
$
4,167

 
Accrued liabilities
 
$
5,857

Foreign exchange contracts
Other non-current liabilities
 

 
Other non-current liabilities
 
354

 
 
 
$
4,167

 
 
 
$
6,211

 
The following table presents the balance sheet location and fair value of our derivative instruments that were not designated as hedging instruments (in thousands): 
 
March 31, 2019
 
December 31, 2018
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Liability Derivative Instruments:
 
 
 
 
 
 
 
Foreign exchange contracts
Accrued liabilities
 
$
3,156

 
Accrued liabilities
 
$
3,454

Foreign exchange contracts
Other non-current liabilities
 

 
Other non-current liabilities
 
530

 
 
 
$
3,156

 
 
 
$
3,984

 
The following tables present the impact that derivative instruments designated as hedging instruments had on our accumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of March 31, 2019, $2.8 million of net losses in accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.
 
 
Unrealized Gain (Loss) Recognized in OCI
 
 
Three Months Ended
March 31,
 
 
2019
 
2018
 
 
 
 
 
Foreign exchange contracts
 
$
(34
)
 
$
1,588

Interest rate swaps
 
(115
)
 
565

 
 
$
(149
)
 
$
2,153

 

28



 
Location of Gain (Loss) Reclassified from
Accumulated OCI into Earnings
 
Gain (Loss) Reclassified from
Accumulated OCI into Earnings
 
 
Three Months Ended
March 31,
 
 
2019
 
2018
 
 
 
 
 
 
Foreign exchange contracts
Cost of sales
 
$
(2,078
)
 
$
(1,656
)
Interest rate swaps
Net interest expense
 
232

 
29

 
 
 
$
(1,846
)
 
$
(1,627
)
 
The following table presents the impact that derivative instruments not designated as hedging instruments had on our condensed consolidated statements of operations (in thousands): 
 
Location of Gain (Loss)
Recognized in Earnings
 
Gain (Loss) Recognized in Earnings
 
 
Three Months Ended
March 31,
 
 
2019
 
2018
 
 
 
 
 
 
Foreign exchange contracts
Other income, net
 
$
(40
)
 
$
844

 
 
 
$
(40
)
 
$
844

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS
 
This Quarterly Report on Form 10-Q contains various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. and represent our expectations and beliefs concerning future events. This forward-looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. All statements included herein or incorporated herein by reference that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “budget,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements. Included in forward-looking statements are, among other things: 
 
statements regarding our business strategy and any other business plans, forecasts or objectives, any or all of which are subject to change;
statements regarding projections of revenues, gross margins, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;
statements regarding our backlog and long-term contracts and rates thereunder;
statements regarding our ability to enter into and/or perform commercial contracts, including the scope, timing and outcome of those contracts;
statements regarding the acquisition, construction, completion, upgrades or maintenance of vessels or equipment and any anticipated costs or downtime related thereto, including the construction and completion of our Q7000 vessel;
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
statements regarding our trade receivables and their collectability;
statements regarding anticipated developments, industry trends, performance or industry ranking;
statements regarding general economic or political conditions, whether international, national or in the regional and local markets in which we do business;

29



statements regarding our ability to retain our senior management and other key employees;
statements regarding the underlying assumptions related to any projection or forward-looking statement; and
any other statements that relate to non-historical or future information.
 
Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include: 
 
the impact of domestic and global economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;
the impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;
the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;
the ability to effectively bid and perform our contracts;
the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets;
unexpected future capital expenditures, including the amount and nature thereof;
the effectiveness and timing of completion of our vessel upgrades and major maintenance items;
unexpected delays in the delivery, chartering or customer acceptance, and terms of acceptance, of our assets;
the effects of our indebtedness and our ability to reduce capital commitments;
the results of our continuing efforts to control costs and improve performance;
the success of our risk management activities;
the effects of competition;
the availability of capital (including any financing) to fund our business strategy and/or operations;
the impact of current and future laws and governmental regulations, including tax and accounting developments, such as the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”);
the impact of the vote in the U.K. to exit the European Union, known as Brexit, on our business, operations and financial condition, which is unknown at this time;
the effect of adverse weather conditions and/or other risks associated with marine operations;
the impact of foreign currency fluctuations;
the effectiveness of our current and future hedging activities;
the potential impact of a loss of one or more key employees; and
the impact of general, market, industry or business conditions.
 
Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 1A. “Risk Factors” in our 2018 Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

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EXECUTIVE SUMMARY
 
Business Strategy
 
We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We believe that focusing on these services should deliver favorable long-term financial returns. From time to time, we may make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. We expect our well intervention fleet to expand with the completion and delivery in 2019 of the Q7000, a newbuild semi-submersible vessel. Chartering newer vessels with additional capabilities, such as the three Grand Canyon vessels, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also expect to benefit from our fixed fee agreement for the HP I, a dynamically positioned floating production vessel that processes production from the Phoenix field for the field operator until at least June 1, 2023. With the acquisition of certain oil and gas properties from Marathon Oil in January 2019, we expect improved utilization of our well intervention fleet in the Gulf of Mexico as we perform the plugging and abandonment of the acquired assets as our schedule permits, subject to regulatory timelines.
 
In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreement and related agreements for the parties’ strategic alliance to design, develop, manufacture, promote, market and sell on a global basis integrated equipment and services for subsea well intervention. The alliance leverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. We and OneSubsea jointly developed a 15,000 working p.s.i. intervention riser system (“15K IRS”), each owning a 50% interest. The 15K IRS was completed and placed into service in January 2018. Our total investment in the 15K IRS was approximately $17 million. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $6 million for our 50% interest. At March 31, 2019, our total investment in the ROAM was $5.6 million. The ROAM is expected to be available in 2019.
 
Economic Outlook and Industry Influences
 
Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to spend on operational activities as well as capital projects. The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including: 
 
worldwide economic activity and general economic and business conditions, including available access to global capital and capital markets;
supply and demand for oil and natural gas, especially in the United States, Europe, China and India;
political and economic uncertainty and geopolitical unrest, including regional conflicts and economic and political conditions in the Middle East and other oil-producing regions;
actions taken by the Organization of Petroleum Exporting Countries;
the availability and discovery rate of new oil and natural gas reserves in offshore areas;
the exploration and production of onshore shale oil and natural gas;
the cost of offshore exploration for and production and transportation of oil and natural gas;
the level of excess production capacity;
the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;
the sale and expiration dates of offshore leases in the United States and overseas;
technological advances affecting energy exploration, production, transportation and consumption;
potential acceleration of the development of alternative fuels;
shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
weather conditions and natural disasters;
environmental and other governmental regulations; and
domestic and international tax laws, regulations and policies.
 

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West Texas Intermediate oil prices have been volatile, entering the year at $45 per barrel and reaching $60 per barrel at March 31, 2019. Volatility in oil prices causes imbalance in the supply and demand for oil, creating uncertainty in oil and gas exploration and production activities. For instance, an increase in oil and gas exploration and production activities (shale oil production in particular) is expected when major oil producing countries including the U.S. increase output as a result of rising oil prices. Increased supply without adequate levels of increase in demand, however, may weaken oil prices and industry prospects. The resulting industry environment may discourage oil and gas companies from making longer term investments in offshore exploration and production as well as other offshore operational activities. Increased competition for limited offshore oil and gas projects has driven down rates that drilling rig contractors are charging for their services, which affects us, as drilling rigs historically have been the asset class used for intervention work. This rig overhang combined with lower volumes of work may affect the utilization and/or rates we can achieve for our assets. The current volatile and uncertain macroeconomic conditions in some countries around the world, such as Brazil and the U.K. following Brexit, may have a direct and/or indirect impact on our existing contracts and contracting opportunities and may introduce further currency volatility into our operations and/or financial results. In addition, the longer term effects of the 2017 Tax Act on capital spending by oil and gas companies are still uncertain.
 
Many oil and gas companies are increasingly focusing on optimizing production of their existing subsea wells. We believe that we have a competitive advantage in terms of performing well intervention services efficiently. Furthermore, we believe that as oil and gas companies begin to increase overall spending levels, it will likely be weighted towards production enhancement activities rather than for exploration projects. Our well intervention and robotics operations are intended to service the life span of an oil and gas field as well as to provide abandonment services at the end of the life of a field as required by governmental regulations. Thus, we believe that fundamentals for our business remain favorable over the longer term as the need for prolongation of well life in oil and gas production is the primary driver of demand for our services.
 
Our current strategy is to be positioned for future recovery while managing through a sustained period of weak activity. This strategy is based on the following factors: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as plug and abandonment costs are considered; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling as well as extending and enhancing the commercial life of subsea wells; and (3) in past cycles, well intervention and workover have been some of the first activities to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells. We could see the beginnings of an upturn in the demand for our services in the U.S. Gulf of Mexico, which are primarily driven by two factors: (1) long-term rig contracts are not being renewed thus removing some of the rig overhang that was considered by our customers to be a sunk cost; and (2) previously deferred work on aging wells is less likely to be further deferred as well performance declines.
 
Business Activity Summary
 
On January 16, 2019, we renewed the agreements that provide various operators with access to the HFRS for well control purposes through March 31, 2020 on newly agreed-upon rates and terms. These agreements automatically renew on an annual basis absent proper notice of termination by one of the parties.

On January 18, 2019, we acquired from Marathon Oil certain operating depths associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure. As part of the transaction, Marathon Oil will pay us agreed-upon amounts for the required plug and abandonment of the acquired assets, which we can perform as our schedule permits, subject to regulatory timelines. There is limited production associated with two wells that were acquired as part of the transaction.

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RESULTS OF OPERATIONS
 
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our consolidated results of operations.
 
We seek to provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. In addition to serving the oil and gas market, our Robotics assets are contracted for the development of renewable energy projects (wind farms). As of March 31, 2019, our consolidated backlog that is supported by written agreements or contracts totaled $1.1 billion, of which $408 million is expected to be performed over the remainder of 2019. The substantial majority of our backlog is associated with our Well Intervention business segment. As of March 31, 2019, our well intervention backlog was $0.8 billion, including $310 million expected to be performed over the remainder of 2019. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 1 and Siem Helix 2 chartered vessels, and our fixed fee agreement for the HP I represent approximately 86% of our total backlog as of March 31, 2019. Backlog is not necessarily a reliable indicator of revenues derived from these contracts as services may be added or subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than the rates we would have generated had we performed the contract.
 
Non-GAAP Financial Measures
 
A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under GAAP. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.
 
We measure our operating performance based on EBITDA and free cash flow. EBITDA and free cash flow are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA and free cash flow to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA and free cash flow provide useful information to the public regarding our ability to service debt and fund capital expenditures and may help our investors understand our operating performance and compare our results to other companies that have different financing, capital and tax structures.
 
We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. To arrive at our measure of Adjusted EBITDA, we exclude gain or loss on disposition of assets. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments and other than temporary loss on note receivable, which are excluded from EBITDA as a component of net other income or expense. We define free cash flow as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted.
 

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Other companies may calculate their measures of EBITDA, Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA and free cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with GAAP. The reconciliation of our net income (loss) to EBITDA and Adjusted EBITDA is as follows (in thousands):