10-Q 1 hlx09302015-10q.htm HELIX ENERGY SOLUTIONS GROUP, INC. 3Q15 FORM 10-Q 10-Q

 
 
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 September 30, 2015
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
 
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
Accelerated filer ¨
Non-accelerated filer ¨
Smaller reporting company ¨
 
 
(Do not check if a smaller reporting company)
 
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 October 16, 2015, 106,137,010 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)
 
September 30,
2015
 
December 31,
2014
 
(Unaudited)
 
 
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
468,936

 
$
476,492

Accounts receivable:
 
 
 
Trade, net of allowance for uncollectible accounts of $7,775 and $4,735, respectively
114,285

 
104,724

Unbilled revenue
31,870

 
28,542

Costs in excess of billing
774

 
2,034

Current deferred tax assets
36,059

 
31,180

Other current assets
44,500

 
51,301

Total current assets
696,424

 
694,273

Property and equipment
2,515,691

 
2,241,444

Less accumulated depreciation
(581,368
)
 
(506,060
)
Property and equipment, net
1,934,323

 
1,735,384

Other assets:
 
 
 
Equity investments
143,481

 
149,623

Goodwill
61,648

 
62,146

Other assets, net
72,124

 
59,272

Total assets
$
2,908,000

 
$
2,700,698

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
 
 
 
Accounts payable
$
75,781

 
$
83,403

Accrued liabilities
78,718

 
104,923

Income tax payable

 
9,143

Current maturities of long-term debt
71,640

 
28,144

Total current liabilities
226,139

 
225,613

Long-term debt
704,568

 
523,228

Deferred tax liabilities
257,596

 
260,275

Other non-current liabilities
46,412

 
38,108

Total liabilities
1,234,715

 
1,047,224

Commitments and contingencies


 


Shareholders equity:
 
 
 
Common stock, no par, 240,000 shares authorized, 106,116 and 105,586 shares issued, respectively
944,718

 
934,447

Retained earnings
808,166

 
781,279

Accumulated other comprehensive loss
(79,599
)
 
(62,252
)
Total shareholders equity
1,673,285

 
1,653,474

Total liabilities and shareholders equity
$
2,908,000

 
$
2,700,698

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
September 30,
 
2015
 
2014
 
 
 
 
Net revenues
$
182,462

 
$
340,837

Cost of sales
150,493

 
214,590

Gross profit
31,969

 
126,247

Selling, general and administrative expenses
(13,597
)
 
(19,916
)
Income from operations
18,372

 
106,331

Equity in earnings (losses) of investments
(251
)
 
508

Net interest expense
(8,713
)
 
(3,856
)
Other income (expense), net
(5
)
 
598

Other income – oil and gas
571

 
1,837

Income before income taxes
9,974

 
105,418

Income tax provision
94

 
29,832

Net income applicable to common shareholders
$
9,880

 
$
75,586

 
 
 
 
Earnings per share of common stock:
 
 
 
Basic
$
0.09

 
$
0.72

Diluted
$
0.09

 
$
0.71

 
 
 
 
Weighted average common shares outstanding:
 
 
 
Basic
105,438

 
104,997

Diluted
105,438

 
105,338

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 OPERATIONS
(UNAUDITED)
(in thousands, except per share amounts) 
 
Nine Months Ended
September 30,
 
2015
 
2014
 
 
 
 
Net revenues
$
538,119

 
$
899,996

Cost of sales
446,995

 
588,765

Gross profit
91,124

 
311,231

Gain on disposition of assets, net

 
10,418

Selling, general and administrative expenses
(42,750
)
 
(69,614
)
Income from operations
48,374

 
252,035

Equity in earnings (losses) of investments
(553
)
 
709

Net interest expense
(18,018
)
 
(12,856
)
Other expense, net
(6,197
)
 
(229
)
Other income – oil and gas
4,396

 
15,709

Income before income taxes
28,002

 
255,368

Income tax provision
1,115

 
67,778

Net income, including noncontrolling interests
26,887

 
187,590

Less net income applicable to noncontrolling interests

 
(503
)
Net income applicable to common shareholders
$
26,887

 
$
187,087

 
 
 
 
Earnings per share of common stock:
 
 
 
Basic
$
0.25

 
$
1.77

Diluted
$
0.25

 
$
1.77

 
 
 
 
Weighted average common shares outstanding:
 
 
 
Basic
105,362

 
105,038

Diluted
105,362

 
105,374

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 COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
(in thousands)
 
Three Months Ended
September 30,
 
2015
 
2014
 
 
 
 
Net income applicable to common shareholders
$
9,880

 
$
75,586

Other comprehensive loss, net of tax:
 
 
 
Unrealized loss on hedges arising during the period
(14,779
)
 
(9,209
)
Reclassification adjustments for loss included in net income
4,255

 
812

Income taxes on unrealized loss on hedges
3,772

 
2,939

Unrealized loss on hedges, net of tax
(6,752
)
 
(5,458
)
Foreign currency translation loss
(10,383
)
 
(15,706
)
Other comprehensive loss, net of tax
(17,135
)
 
(21,164
)
Comprehensive income (loss) applicable to common shareholders
$
(7,255
)
 
$
54,422

  
 
Nine Months Ended
September 30,
 
2015
 
2014
 
 
 
 
Net income, including noncontrolling interests
$
26,887

 
$
187,590

Other comprehensive loss, net of tax:
 
 
 
Unrealized loss on hedges arising during the period
(23,144
)
 
(9,283
)
Reclassification adjustments for loss included in net income
9,186

 
2,080

Income taxes on unrealized loss on hedges
4,974

 
2,521

Unrealized loss on hedges, net of tax
(8,984
)
 
(4,682
)
Foreign currency translation loss
(8,363
)
 
(7,428
)
Other comprehensive loss, net of tax
(17,347
)
 
(12,110
)
Comprehensive income
9,540

 
175,480

Less comprehensive income applicable to noncontrolling interests

 
(503
)
Comprehensive income applicable to common shareholders
$
9,540

 
$
174,977

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) 
 
Nine Months Ended
September 30,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income, including noncontrolling interests
$
26,887

 
$
187,590

Adjustments to reconcile net income, including noncontrolling interests, to net cash provided by operating activities:
 
 
 
Depreciation and amortization
86,333

 
81,274

Amortization of deferred financing costs
4,117

 
3,653

Stock-based compensation expense
7,941

 
5,711

Amortization of debt discount
4,409

 
4,149

Deferred income taxes
(2,403
)
 
24,728

Excess tax from stock-based compensation
98

 
(120
)
Gain on disposition of assets, net

 
(10,418
)
Unrealized loss and ineffectiveness on derivative contracts, net
2,222

 
69

Changes in operating assets and liabilities:
 
 
 
Accounts receivable, net
(13,326
)
 
(16,496
)
Other current assets
6,610

 
(19,388
)
Income tax payable, net of income tax receivable
(12,152
)
 
25,440

Accounts payable and accrued liabilities
(52,045
)
 
25,127

Other noncurrent, net
(19,164
)
 
(9,758
)
Net cash provided by operating activities
39,527

 
301,561

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(280,523
)
 
(204,528
)
Distributions from equity investments, net
5,853

 
5,041

Proceeds from sale of assets
7,500

 
11,074

Acquisition of noncontrolling interests

 
(20,085
)
Net cash used in investing activities
(267,170
)
 
(208,498
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from Nordea Q5000 Loan
250,000

 

Repayment of Nordea Q5000 Loan
(8,929
)
 

Repayment of Term Loan
(15,000
)
 
(11,250
)
Repayment of MARAD Debt
(5,644
)
 
(5,376
)
Deferred financing costs
(1,611
)
 
(3,143
)
Distributions to noncontrolling interests

 
(1,018
)
Repurchases of common stock
(1,056
)
 
(8,538
)
Excess tax from stock-based compensation
(98
)
 
120

Proceeds from issuance of ESPP shares
3,484

 
3,223

Net cash provided by (used in) financing activities
221,146

 
(25,982
)
 
 
 
 
Effect of exchange rate changes on cash and cash equivalents
(1,059
)
 
1,248

Net increase (decrease) in cash and cash equivalents
(7,556
)
 
68,329

Cash and cash equivalents:
 
 
 
Balance, beginning of year
476,492

 
478,200

Balance, end of period
$
468,936

 
$
546,529

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 wholly and majority owned 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 wholly and majority owned 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.
 
The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) and are consistent in all material respects with those applied in our 2014 Annual Report on Form 10-K (“2014 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. The operating results for the three- and nine-month periods ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. Our balance sheet as of December 31, 2014 included herein has been derived from the audited balance sheet as of December 31, 2014 included in our 2014 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 2014 Form 10-K.
 
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 (loss), and statements of cash flows, as applicable. Our operating results for the nine-month period ended September 30, 2015 included an out-of-period adjustment to correct an error related to a well intervention project performed in 2014 in which our revenues included certain income tax withholding payments made on our behalf and which now will have to be refunded to the counterparty. This adjustment affects our 2015 operating results by reducing our net revenues by $2.5 million and increasing our net loss by $1.7 million. The amounts were not deemed material with respect to prior year or the anticipated results and the trend of earnings for fiscal year 2015.
 
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.
 
In May 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU provides a single five-step approach to account for revenue arising from contracts with customers. The ASU requires an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This revenue standard was originally effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods. In August 2015, the FASB issued ASU No. 2015-14 to defer the effective date of ASU No. 2014-09 by one year to December 15, 2017. Adoption as of the original effective date is permitted. The guidance permits companies to either apply the requirements retrospectively to all prior periods presented, or apply the requirements in the year of adoption through a cumulative adjustment. We are currently evaluating which transition approach to use and the potential impact the adoption of this standard may have on our consolidated financial statements.

8



 
In April 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This ASU requires that debt issuance costs related to a recognized debt liability be reported on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance is effective retrospectively beginning in the first quarter of fiscal 2017 and early adoption is permitted. We do not expect this guidance to materially affect our balance sheets as amounts will be reclassified from long-term assets to partial offsets to long-term debt. The guidance will not affect our statements of operations or statements of cash flows.
 
In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires inventory that is measured using first-in, first-out or average cost method to be recorded at the lower of cost and net realizable value. The guidance is effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods. Early adoption is permitted. We do not expect this guidance to materially affect our consolidated financial statements.
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 developing offshore reservoirs and maximizing production economics. We provide services primarily in deepwater in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and expect to expand our operations offshore Brazil. Our “life of field” services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities (Note 11).

Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the Gulf of Mexico and North Sea regions. Our Well Intervention segment also includes intervention riser systems (“IRSs”) that may be available on a rental basis. Our well intervention vessels include the Q4000, the Helix 534, the Seawell, the Well Enhancer and the Skandi Constructor, which is a chartered vessel. Our well intervention fleet also includes the Q5000, a newbuild semi-submersible well intervention vessel that was delivered to us at the end of April 2015 and is currently working for a client in the Gulf of Mexico. We are currently constructing another well intervention vessel, the Q7000. We have also contracted to charter two newbuild monohull vessels, to be used in connection with our contracts to provide well intervention services offshore Brazil.

Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates five chartered ROV and trencher support vessels including the Grand Canyon II, which was delivered to us in late April 2015.

Our Production Facilities segment includes the Helix Producer I vessel (“HP I”) as well as our equity investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) (Note 5). The Production Facilities segment also includes the Helix Fast Response System (“HFRS”), which provides certain operators access to our Q4000 and HP I vessels in the event of a well control incident in the Gulf of Mexico.

9



Note 3 — Details of Certain Accounts 
 
Other current assets and other assets, net consist of the following (in thousands): 
 
September 30,
2015
 
December 31,
2014
 
 
 
 
Note receivable (1)
$
10,000

 
$
17,500

Other receivables
597

 
423

Prepaid insurance
7,968

 
6,582

Other prepaids
9,295

 
15,541

Spare parts inventory
5,022

 
1,857

Income tax receivable
3,477

 

Value added tax receivable
8,060

 
9,326

Other
81

 
72

Total other current assets
$
44,500

 
$
51,301

  
 
September 30,
2015
 
December 31,
2014
 
 
 
 
Note receivable (1)
$
10,000

 
$
10,000

Deferred dry dock expenses, net
27,207

 
11,631

Deferred financing costs, net (Note 6)
21,182

 
23,399

Intangible assets with finite lives, net
736

 
696

Charter fee deposit (Note 12)
12,544

 
12,544

Other
455

 
1,002

Total other assets, net
$
72,124

 
$
59,272

  
(1)
Relates to the remaining balance of the promissory note we received in connection with the sale of our Ingleside spoolbase in January 2014. The balance at December 31, 2014 included $7.5 million, which was paid in January 2015. Interest on the note is payable quarterly at a rate of 6% per annum. Under the terms of the note, the remaining $20 million principal balance is required to be paid with a $10 million payment on December 31, 2015 and December 31, 2016.
 
Accrued liabilities consist of the following (in thousands): 
 
September 30,
2015
 
December 31,
2014
 
 
 
 
Accrued payroll and related benefits
$
19,598

 
$
61,246

Current asset retirement obligations
553

 
575

Unearned revenue
17,879

 
11,461

Accrued interest
2,086

 
4,221

Derivative liability (Note 14)
22,790

 
13,222

Taxes payable excluding income tax payable
7,229

 
6,236

Other
8,583

 
7,962

Total accrued liabilities
$
78,718

 
$
104,923


10



Note 4 — 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): 
 
Nine Months Ended
September 30,
 
2015
 
2014
 
 
 
 
Interest paid, net of interest capitalized
$
11,823

 
$
11,671

Income taxes paid
$
16,008

 
$
53,390

 
Our non-cash investing activities include accruals for property and equipment capital expenditures. These non-cash investing accruals totaled $20.4 million and $14.1 million as of September 30, 2015 and December 31, 2014, respectively. Additionally, our investing activities for the nine-month period ended September 30, 2014 included a $30 million non-cash transaction related to the promissory note we received in connection with the sale of our Ingleside spoolbase in January 2014 (Note 3).
Note 5 — Equity Investments
 
As of September 30, 2015, we had two investments that we account for using the equity method of accounting: Deepwater Gateway and Independence Hub, both of which are included in our Production Facilities segment.
 
Deepwater Gateway, L.L.C.  In June 2002, we, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, each with a 50% interest, to design, construct, install, own and operate a tension leg platform production hub primarily for Anadarko Petroleum Corporation’s Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $77.5 million and $80.9 million as of September 30, 2015 and December 31, 2014, respectively (including net capitalized interest of $1.2 million at September 30, 2015 and December 31, 2014, respectively).
 
Independence Hub, LLC.  In December 2004, we acquired a 20% interest in Independence Hub, then an affiliate of Enterprise. Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. Our investment in Independence Hub was $66.0 million and $68.8 million as of September 30, 2015 and December 31, 2014, respectively (including capitalized interest of $3.7 million and $3.9 million at September 30, 2015 and December 31, 2014, respectively).
 
In July 2015, Enterprise sold its offshore Gulf of Mexico pipelines and services business to Genesis Energy, L.P. for approximately $1.5 billion. Enterprise’s ownership interests in both Deepwater Gateway and Independence Hub were included in the sale.
 
We received the following distributions from our equity method investments (in thousands): 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
Deepwater Gateway
$
1,200

 
$
500

 
$
3,900

 
$
4,250

Independence Hub
560

 
200

 
1,400

 
1,500

Total
$
1,760

 
$
700

 
$
5,300

 
$
5,750


11



Note 6 — Long-Term Debt
 
Scheduled maturities of our long-term debt outstanding as of September 30, 2015 are as follows (in thousands):
 
Term
Loan
 
Nordea
Q5000 Loan
 
MARAD
Debt
 
2032
Notes (1)
 
Total
 
 
 
 
 
 
 
 
 
 
Less than one year
$
30,000

 
$
35,714

 
$
5,926

 
$

 
$
71,640

One to two years
30,000

 
35,715

 
6,222

 

 
71,937

Two to three years
202,500

 
35,714

 
6,532

 

 
244,746

Three to four years

 
35,714

 
6,858

 

 
42,572

Four to five years

 
98,214

 
7,200

 

 
105,414

Over five years

 

 
56,410

 
200,000

 
256,410

Total debt
262,500

 
241,071

 
89,148

 
200,000

 
792,719

Current maturities
(30,000
)
 
(35,714
)
 
(5,926
)
 

 
(71,640
)
Long-term debt, less current maturities
232,500

 
205,357

 
83,222

 
200,000

 
721,079

Unamortized debt discount (2)

 

 

 
(16,511
)
 
(16,511
)
Long-term debt
$
232,500

 
$
205,357

 
$
83,222

 
$
183,489

 
$
704,568

 
(1)
Beginning in March 2018, the holders of our Convertible Senior Notes due 2032 may require us to repurchase these notes or we may at our option elect to repurchase these notes. The notes will mature in March 2032.
 
(2)
Our Convertible Senior Notes due 2032 will increase to their face amount through accretion of non-cash interest charges through March 2018.
 
Below is a summary of certain components of our indebtedness:
 
Credit Agreement
 
In June 2013, we entered into a credit agreement (the “Credit Agreement”) with a group of lenders pursuant to which we borrowed $300 million under the Credit Agreement’s term loan (the “Term Loan”) and, subject to the terms of the Credit Agreement, may borrow additional amounts (the “Revolving Loans”) and/or obtain letters of credit under a revolving credit facility (the “Revolving Credit Facility”) up to $600 million. Subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may obtain an increase of up to $200 million in aggregate commitments with respect to the Revolving Credit Facility, additional term loans or a combination thereof. At September 30, 2015, we had no borrowings under the $600 million Revolving Credit Facility and our available borrowing capacity under that facility, based on the leverage ratio covenant, totaled $243.4 million, net of $17.5 million of letters of credit issued.
 
The Term Loan and the Revolving Loans (together, the “Loans”) bear interest, at our election, in relation to either the base rate established by Bank of America N.A. or to a LIBOR rate, provided that all Swing Line Loans (as defined in the Credit Agreement) will be base rate loans.
 

12



The Loans or portions thereof bearing interest at the base rate currently bear interest at a per annum rate equal to the base rate plus a margin ranging from 1.00% to 3.00%. The Loans or portions thereof bearing interest at a LIBOR rate currently bear interest at the LIBOR rate selected by us plus a margin ranging from 2.00% to 4.00%. A letter of credit fee is payable by us equal to our applicable margin for LIBOR rate Loans multiplied by the daily amount available to be drawn under outstanding letters of credit. Margins on the Loans will vary in relation to the consolidated coverage ratio, as provided by the Credit Agreement. We currently also pay a fixed commitment fee of 0.50% on the unused portion of our Revolving Credit Facility. The Term Loan currently bears interest at the one-month LIBOR rate plus 2.50%. In September 2013, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on $148.1 million of our borrowings under the Term Loan. The fixed LIBOR rates are between 74 and 75 basis points.
 
The Term Loan is repayable in scheduled principal installments of 5% in each of the initial two loan years ($15 million per year), and 10% in each of the remaining three loan years ($30 million per year), payable quarterly, with a balloon payment of $180 million at maturity. These installment amounts are subject to adjustment for any prepayments on the Term Loan. We may elect to prepay amounts outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay amounts outstanding under the Revolving Loans without premium or penalty, and may reborrow any amounts paid up to the amount of the Revolving Credit Facility. The Loans mature on June 19, 2018. In certain circumstances, we will be required to prepay the Loans.
 
The Credit Agreement and the other documents entered into in connection with the Credit Agreement (together, the “Loan Documents”) include terms and conditions, including covenants, which we consider customary for this type of transaction. The covenants include restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and incur capital expenditures. In addition, the Credit Agreement obligates us to meet certain financial ratios, including the Consolidated Interest Coverage Ratio and the Consolidated Leverage Ratio (as defined in the Credit Agreement). In May 2015, we amended the Credit Agreement to revise the maximum permitted Consolidated Leverage Ratio as follows: 4.00 to 1.00 for the second quarter of 2015, 4.50 to 1.00 for the third quarter of 2015 through the fourth quarter of 2016, 4.00 to 1.00 for the first quarter of 2017, and 3.50 to 1.00 for the second quarter of 2017 and thereafter. Prior to the amendment, the leverage ratio was 3.50 to 1.00, which applied to all periods after January 1, 2014.
 
We have designated five of our foreign subsidiaries, and may designate any newly established foreign subsidiaries, as subsidiaries that are not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”), provided we meet certain liquidity requirements, in which case EBITDA (net of cash distributions to the parent) of the Unrestricted Subsidiaries is not included in the calculations with respect to our financial covenants. Our obligations under the Credit Agreement are guaranteed by our wholly owned domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, a wholly owned Scottish subsidiary. Our obligations under the Credit Agreement, and of the guarantors under their guaranty, are secured by most of our assets of the parent and our wholly owned domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, plus pledges of up to two-thirds of the shares of certain foreign subsidiaries.
 

13



Convertible Senior Notes Due 2032 
 
In March 2012, we completed a public offering and sale of $200 million in aggregate principal amount of Convertible Senior Notes due 2032 (the “2032 Notes”). The 2032 Notes bear interest at a rate of 3.25% per annum, and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012. The 2032 Notes mature on March 15, 2032 unless earlier converted, redeemed or repurchased. The 2032 Notes are convertible in certain circumstances and during certain periods at an initial conversion rate of 39.9752 shares of common stock per $1,000 principal amount (which represents an initial conversion price of approximately $25.02 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2032 Notes. We have the right and the intention to settle any such future conversions in cash.
 
Prior to March 20, 2018, the 2032 Notes are not redeemable. On or after March 20, 2018, we, at our option, may redeem some or all of the 2032 Notes in cash, at any time upon at least 30 days’ notice, at a price equal to 100% of the principal amount plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the redemption date. In addition, the holders of the 2032 Notes may require us to purchase in cash some or all of their 2032 Notes at a repurchase price equal to 100% of the principal amount of the 2032 Notes, plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022 and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a fundamental change (as defined in the Indenture governing the 2032 Notes).
 
In connection with the issuance of the 2032 Notes, we recorded a discount of $35.4 million as required under existing accounting rules. To arrive at this discount amount, we estimated the fair value of the liability component of the 2032 Notes as of the date of their issuance (March 12, 2012) using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 6.0 years. In selecting the expected life, we selected the earliest date the holders could require us to repurchase all or a portion of the 2032 Notes (March 15, 2018). The effective interest rate for the 2032 Notes is 6.9% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2032 Notes at their inception. We recorded $22.5 million related to the carrying amount of the equity component of the 2032 Notes.
 
MARAD Debt
 
This U.S. government guaranteed financing (the “MARAD Debt”) is pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, and was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures in February 2027. The MARAD Debt is collateralized by the Q4000, is guaranteed 50% by us, and initially bore interest at a floating rate that approximated AAA Commercial Paper yields plus 20 basis points. As required by the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date.
 

14



Nordea Credit Agreement
 
In September 2014, a wholly owned subsidiary incorporated in Luxembourg, Helix Q5000 Holdings S.à r.l. (“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 at the end of April 2015 at the time the Q5000 vessel was delivered. 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 nonrecourse to Helix.
 
The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%, with an undrawn fee of 0.875% prior to funding on April 30, 2015. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled principal installments of $8.9 million, payable quarterly, with a balloon payment of $80.4 million at maturity. Q5000 Holdings may elect to prepay amounts outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Installment amounts are subject to adjustment for any prepayments on this debt. In certain circumstances, Q5000 Holdings will be required to prepay the loan. In June 2015, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on $187.5 million of our borrowings under the Nordea Q5000 Loan. The fixed LIBOR rates are between 149 and 152 basis points.
 
The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants, that are considered 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. As of September 30, 2015, Q5000 Holdings was in compliance with these covenants.
 
Other 
 
In accordance with our Credit Agreement, the 2032 Notes, the MARAD Debt agreements, and the Nordea Credit Agreement, we are required to comply with certain covenants, including certain financial ratios such as a consolidated interest coverage ratio and consolidated leverage ratio, as well as the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of September 30, 2015, we were in compliance with these covenants.
 
Unamortized deferred financing costs are included in “Other assets, net” in the accompanying condensed consolidated balance sheets and are amortized over the life of the respective debt agreements. The following table reflects the components of our deferred financing costs (in thousands): 
 
September 30, 2015
 
December 31, 2014
 
Gross
Carrying Amount
 
Accumulated
Amortization
 
Net
 
Gross
Carrying Amount
 
Accumulated
Amortization
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
Term Loan (matures June 2018)
$
3,638

 
$
(1,637
)
 
$
2,001

 
$
3,638

 
$
(1,091
)
 
$
2,547

Revolving Credit Facility (matures June 2018)
14,787

 
(6,137
)
 
8,650

 
13,275

 
(3,982
)
 
9,293

2032 Notes (mature March 2032)
3,759

 
(2,224
)
 
1,535

 
3,759

 
(1,763
)
 
1,996

MARAD Debt (matures February 2027)
12,200

 
(6,589
)
 
5,611

 
12,200

 
(6,223
)
 
5,977

Nordea Q5000 Loan (matures April 2020)
3,685

 
(300
)
 
3,385

 
3,586

 

 
3,586

Total deferred financing costs
$
38,069

 
$
(16,887
)
 
$
21,182

 
$
36,458

 
$
(13,059
)
 
$
23,399

 

15



The following table details the components of our net interest expense (in thousands): 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
Interest expense
$
10,897

 
$
8,952

 
$
29,057

 
$
24,474

Interest income
(470
)
 
(2,741
)
 
(1,577
)
 
(4,113
)
Capitalized interest
(1,714
)
 
(2,355
)
 
(9,462
)
 
(7,505
)
Net interest expense
$
8,713

 
$
3,856

 
$
18,018

 
$
12,856

Note 7 — Income Taxes 
 
Our estimated annual effective tax rate, adjusted for discrete tax items, is applied to interim periods’ pretax earnings. We believe that our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, and 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- and nine-month periods ended September 30, 2015 were 0.9% and 4.0%, respectively. The effective tax rates for the three- and nine-month periods ended September 30, 2014 were 28.3% and 26.5%, respectively. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions.
 
Income taxes have been provided based on the U.S. statutory rate of 35% and at the local statutory rate for each foreign jurisdiction. The primary differences between the U.S. statutory rate and our effective rate are as follows: 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
U.S. statutory rate
35.0
 %
 
35.0
 %
 
35.0
 %
 
35.0
 %
Foreign provision
(35.3
)
 
(7.2
)
 
(32.9
)
 
(7.8
)
Other
1.2

 
0.5

 
1.9

 
(0.7
)
Effective rate
0.9
 %
 
28.3
 %
 
4.0
 %
 
26.5
 %
Note 8 — Accumulated Other Comprehensive Income (Loss) (“OCI”)
 
The components of Accumulated OCI are as follows (in thousands): 
 
September 30,
2015
 
December 31,
2014
 
 
 
 
Cumulative foreign currency translation adjustment
$
(38,524
)
 
$
(30,161
)
Unrealized loss on hedges, net (1)
(41,075
)
 
(32,091
)
Accumulated other comprehensive loss
$
(79,599
)
 
$
(62,252
)
 
(1)
Amounts relate to foreign currency hedges for the Grand Canyon, the Grand Canyon II and the Grand Canyon III charters as well as interest rate swap contracts for the Term Loan and the Nordea Q5000 Loan, and are net of deferred income taxes totaling $22.3 million at September 30, 2015 and $17.3 million at December 31, 2014 (Note 14).

16



Note 9 — Earnings Per Share 
 
We have shares of restricted stock issued and outstanding, which currently are unvested. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding unrestricted common stock and the shares are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and 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. Further, we are required to compute earnings per share (“EPS”) amounts under the two class method in periods in which we have earnings from continuing operations.
 
The presentation of basic EPS amounts on the face of the accompanying condensed consolidated statements of operations is computed by dividing the net income applicable to our common shareholders by the weighted average shares of our outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact 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): 
 
Three Months Ended
September 30, 2015
 
Three Months Ended
September 30, 2014
 
Income
 
Shares
 
Income
 
Shares
Basic:
 
 
 
 
 
 
 
Net income applicable to common shareholders
$
9,880

 
 
 
$
75,586

 
 
Less: Undistributed income allocated to participating securities
(52
)
 
 
 
(392
)
 
 
Undistributed income allocated to common shares
$
9,828

 
105,438

 
$
75,194

 
104,997

 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
Undistributed income allocated to common shares
$
9,828

 
105,438

 
$
75,194

 
104,997

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

 

 

 
341

Undistributed income reallocated to participating securities

 

 
1

 

Net income applicable to common shareholders
$
9,828

 
105,438

 
$
75,195

 
105,338

  

17



 
Nine Months Ended
September 30, 2015
 
Nine Months Ended
September 30, 2014
 
Income
 
Shares
 
Income
 
Shares
Basic:
 
 
 
 
 
 
 
Net income applicable to common shareholders
$
26,887

 
 
 
$
187,087

 
 
Less undistributed income allocated to participating securities
(149
)
 
 
 
(980
)
 
 
Undistributed income allocated to common shares
$
26,738

 
105,362

 
$
186,107

 
105,038

 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
Undistributed income allocated to common shares
$
26,738

 
105,362

 
$
186,107

 
105,038

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

 

 

 
336

Undistributed income reallocated to participating securities

 

 
3

 

Net income applicable to common shareholders
$
26,738

 
105,362

 
$
186,110

 
105,374

 
Approximately 8.0 million of potentially dilutive shares related to the 2032 Notes were excluded from the diluted EPS calculation for the three- and nine-month periods ended September 30, 2015 and 2014 because we have the right, intention and ability to settle any such future conversions in cash (Note 6).
Note 10 — Employee Benefit Plans 
 
Long-Term Incentive Stock-Based Plan 
 
As of September 30, 2015, there were 6.2 million shares of our common stock available for issuance under our active long-term incentive stock-based plan, the 2005 Long-Term Incentive Plan, as amended and restated effective May 9, 2012 (the “2005 Incentive Plan”). During the nine-month period ended September 30, 2015, the following grants of share-based awards were made under the 2005 Incentive Plan: 
Date of Grant
 
 
Shares
 
 
 
Grant Date
Fair Value
Per Share
 
 
Vesting Period
 
 
 
 
 
 
 
 
 
 
 
January 2, 2015 (1)
 
 
289,163

 
 
 
$
21.70

 
 
33% per year over three years
January 2, 2015 (2)
 
 
289,163

 
 
 
$
25.06

 
 
100% on January 1, 2018
January 5, 2015 (3)
 
 
3,946

 
 
 
$
21.66

 
 
100% on January 1, 2017
January 12, 2015 (1)
 
 
3,866

 
 
 
$
19.40

 
 
33% per year over three years
January 12, 2015 (2)
 
 
3,866

 
 
 
$
25.06

 
 
100% on January 11, 2018
February 1, 2015 (1)
 
 
2,664

 
 
 
$
18.77

 
 
33% per year over three years
February 1, 2015 (2)
 
 
2,664

 
 
 
$
25.06

 
 
100% on January 31, 2018
April 1, 2015 (3)
 
 
6,476

 
 
 
$
14.96

 
 
100% on January 1, 2017
July 1, 2015 (3)
 
 
6,631

 
 
 
$
12.63

 
 
100% on January 1, 2017
 
(1)
Reflects the grant of restricted stock to our executive officers and selected management employees.
 

18



(2)
Reflects the grant of performance share units (“PSUs”) to our executive officers and selected 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. The vested PSUs may be settled in either cash or shares of our common stock at the discretion of the Compensation Committee of our Board of Directors.
 
(3)
Reflects the grant of restricted stock to certain members of our Board of Directors who have made an election to take their quarterly fees in stock in lieu of cash.
 
Compensation cost for restricted stock is recognized over its vesting period on a straight-line basis. For the three- and nine-month periods ended September 30, 2015, $1.5 million and $4.4 million, respectively, were recognized as stock-based compensation expense related to restricted stock. For the three- and nine-month periods ended September 30, 2014, $1.1 million and $3.6 million, respectively, were recognized as stock-based compensation expense related to restricted stock and restricted stock units.
 
The estimated fair value of the PSUs on grant date was determined using a Monte Carlo simulation model. Until December 2014, the PSUs were being treated as an equity award. Accordingly, compensation expense associated with the PSUs was fixed, as represented by the number of PSUs multiplied by their respective grant date fair value, and the fixed amount was amortized on a straight-line basis over the three-year vesting period. In connection with the vesting of the 2012 PSU awards that occurred in January 2015, the decision was made by the Compensation Committee of our Board of Directors to settle these PSUs with a cash payment of $4.5 million (rather than an equivalent number of shares of our common stock, which was the default provision of the PSU awards). Accordingly, PSUs are now accounted for as a liability plan and changes in fair value of the awards are recognized in earnings. To the extent the recognized fair value of the modified liability awards is less than the recognized compensation cost associated with the grant date fair value of the original equity awards, the higher amount is recorded in stock-based compensation expense. The amount of cumulative compensation expense recognized in excess of the fair value of the modified liability awards is recorded in equity. For the three-month period ended September 30, 2015, $0.6 million was recognized as stock-based compensation expense related to PSUs. For the nine-month period ended September 30, 2015, we recorded a net reduction of $0.3 million of previously recognized compensation cost to reflect the estimated fair value of unvested PSUs as of September 30, 2015. For the three- and nine-month periods ended September 30, 2014, $0.6 million and $1.6 million, respectively, were recognized as stock-based compensation expense related to PSUs. The liability balance for the PSU awards was $0.3 million at September 30, 2015 and $7.9 million at December 31, 2014.
 
Long-Term Incentive Cash Plans 
 
We have certain long-term incentive cash plans (the “LTI Cash Plans”) that provide long-term cash-based compensation to eligible employees. Cash awards historically have been both fixed sum amounts payable (for non-executive management only) as well as cash awards indexed to our common stock with the payment amount at each vesting date fluctuating based on the performance of our common stock (for both executive and non-executive management). Payment amounts under these awards are calculated based on the ratio of the average stock price during the applicable measurement period over the original base price determined by the Compensation Committee of our Board of Directors at the time of the award. Cash payments under these awards are made each year during the vesting period on the anniversary date of the award. Cash awards granted since 2012 have a vesting period of three years while those granted prior to 2012 have a vesting period of five years. The LTI Cash Plans are considered liability plans and as such are re-measured to fair value each reporting period with corresponding changes in the liability amount being reflected in our results of operations.
 

19



The cash awards granted under the LTI Cash Plans to our executive officers and selected management employees totaled $8.9 million in 2014. No long-term incentive cash awards were granted in 2015. For the three- and nine-month periods ended September 30, 2015, we recorded reductions of $1.2 million and $3.7 million, respectively, of previously recognized compensation expense associated with the cash awards issued pursuant to the LTI Cash Plans, reflecting the effect the decrease in our stock price since December 31, 2014 had on the value of our liability plan. For the nine-month period ended September 30, 2014, total compensation expense associated with the cash awards issued pursuant to the LTI Cash Plans was $5.4 million. Overall, compensation expense recorded for the three-month period ended September 30, 2014 was immaterial reflecting the effect the decrease in our stock price at the end of September 30, 2014 had on the value of our liability plan. The liability balance for the cash awards issued under the LTI Cash Plans was $0.1 million at September 30, 2015 and $12.8 million at December 31, 2014.
 
Employee Stock Purchase Plan 
 
We also have an employee stock purchase plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance, of which 0.9 million shares were available for issuance as of September 30, 2015. The total value of the ESPP awards is calculated using the component approach where each award is computed as the sum of 15% of a share of non-vested stock, a call option on 85% of a share of non-vested stock, and a put option on 15% of a share of non-vested stock. Share-based compensation expense with respect to the ESPP was $0.3 million and $0.9 million, respectively, for the three- and nine-month periods ended September 30, 2015. For the three- and nine-month periods ended September 30, 2014, share-based compensation expense with respect to the ESPP was $0.3 million and $0.7 million, respectively.
 
For more information regarding our employee benefit plans, including our long-term incentive stock-based and cash plans and our employee stock purchase plan, see Note 8 to our 2014 Form 10-K.
Note 11 — Business Segment Information 
 
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the Gulf of Mexico and North Sea regions. Our well intervention vessels include the Q4000, the Q5000, the Helix 534, the Seawell, the Well Enhancer and the Skandi Constructor, which is a chartered vessel. Our well intervention segment also includes certain intervention riser systems that are available on a rental basis. Our Robotics segment includes ROVs, trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates five chartered ROV and trencher support vessels. The Production Facilities segment includes the HP I as well as our investments in Deepwater Gateway and Independence Hub that are accounted for under the equity method. The results of our previously reported Subsea Construction segment are immaterial and thus no longer meet the threshold to be separately reported as a business segment. These results are now aggregated within “Other” for all periods presented in this Quarterly Report on Form 10-Q. All material intercompany transactions between the segments have been eliminated.
 
We evaluate our performance primarily based on operating income of each reportable segment. 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. Certain financial data by reportable segment are summarized as follows (in thousands): 

20



 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Net revenues —
 
 
 
 
 
 
 
Well Intervention
$
94,895

 
$
205,139

 
$
284,621

 
$
546,057

Robotics
83,310

 
131,707

 
238,582

 
339,301

Production Facilities
19,133

 
24,184

 
57,811

 
71,373

Other

 

 

 
358

Intercompany elimination
(14,876
)
 
(20,193
)
 
(42,895
)
 
(57,093
)
Total
$
182,462

 
$
340,837

 
$
538,119

 
$
899,996

 
 
 
 
 
 
 
 
Income (loss) from operations —
 
 
 
 
 
 
 
Well Intervention
$
6,233

 
$
80,789

 
$
25,162

 
$
194,297

Robotics
14,329

 
28,397

 
28,089

 
60,415

Production Facilities
6,938

 
11,284

 
19,960

 
33,127

Corporate and other
(8,965
)
 
(14,242
)
 
(24,581
)
 
(34,754
)
Intercompany elimination
(163
)
 
103

 
(256
)
 
(1,050
)
Total
$
18,372

 
$
106,331

 
$
48,374

 
$
252,035

 
 
 
 
 
 
 
 
Equity in earnings (losses) of investments
$
(251
)
 
$
508

 
$
(553
)
 
$
709

 
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
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
Well Intervention
$
7,324

 
$
8,635

 
$
18,687

 
$
22,052

Robotics
7,552

 
11,558

 
24,208

 
35,041

Total
$
14,876

 
$
20,193

 
$
42,895

 
$
57,093

 
The following table reflects total assets by reportable segment (in thousands): 
 
September 30,
2015
 
December 31,
2014
 
 
 
 
Well Intervention
$
1,757,962

 
$
1,470,349

Robotics
295,617

 
299,701

Production Facilities
437,839

 
459,427

Corporate and other
416,582

 
471,221

Total
$
2,908,000

 
$
2,700,698


21



Note 12 — Commitments and Contingencies and Other Matters 
 
Commitments 
 
In February 2013, we contracted to charter the Grand Canyon II and the Grand Canyon III for use in our robotics operations. The terms of the charters are for five years from the respective delivery dates. We took delivery of the Grand Canyon II in late April 2015 and received a $4.7 million non-refundable payment from the shipyard that constructed the vessel related to the delayed delivery of the vessel. This payment will be amortized as a reduction in our cost of sales over the five-year charter for the vessel. The delivery of the Grand Canyon III has been extended until February 2016.
 
In September 2013, we executed a second contract with the same shipyard in Singapore that constructed the Q5000. This contract is for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is to be built to North Sea standards. This $346.0 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the original terms of this contract, 20% of the contract price was paid upon the signing of the contract and the remaining 80% was to be paid upon the delivery of the vessel. Pursuant to an amendment we entered into with the shipyard in June 2015, the remaining 80% will now be paid in two installments, with 20% in June 2016 and 60% upon the delivery of the vessel. We agreed to pay the shipyard incremental costs of up to $14.5 million to extend the scheduled delivery of the Q7000 from mid-2016 to July 30, 2017. These costs are capitalizable as they are incurred during the construction of the vessel. We paid $7.3 million of these costs in July 2015 and the remaining costs will be paid upon the delivery of the vessel. At September 30, 2015, our total investment in the Q7000 was $108.9 million, including the $69.2 million paid to the shipyard upon signing the contract.
 
In February 2014, we entered into agreements with Petróleo Brasileiro S.A. (“Petrobras”) to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with options to extend. In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two newbuild monohull vessels, the first of which is expected to be in service for Petrobras in 2016 and the second in late 2016 or early 2017. At September 30, 2015, our total investment in the topside equipment for the two vessels was $99.9 million. In November 2014, we paid a charter fee deposit of $12.5 million, which will be used to reduce our future charter payments.
 
In September 2015, we extended the charter of the Skandi Constructor through April 1, 2017 at reduced rates to be effective October 15, 2015.
 
Contingencies and Claims 
 
We believe that there are currently no contingencies which would have a material effect on our financial position, results of operations or cash flows.
 
Litigation 
 
On July 31, 2015, a purported stockholder, Parviz Izadjoo, filed a class action lawsuit styled Parviz Izadjoo v. Owen Kratz and Helix Energy Solutions Group, Inc. against the Company and Mr. Owen Kratz, our Chief Executive Officer, in the United States District Court for the Southern District of Texas on behalf of a putative class of all purchasers of shares of our common stock between October 21, 2014, and July 21, 2015, inclusive. The lawsuit asserts violations of Section 10(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and SEC Rule 10b-5 as to both us and Mr. Kratz, and Section 20(a) of the Exchange Act against Mr. Kratz based on alleged misrepresentations and omissions in SEC filings and other public disclosures regarding projections for 2015 dry docks of two of the Company’s vessels working in the Gulf of Mexico, which allegedly caused the price at which putative class members bought stock during the proposed class period to be artificially inflated. The complaint

22



seeks, among other relief, undisclosed damages. The deadline to apply for appointment as lead plaintiff was September 29, 2015. A lead plaintiff has not yet been appointed in this case. The Court has set an initial conference on November 16, 2015. We believe this lawsuit to be without merit and intend to vigorously defend against it.
 
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 based on alleged negligence. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.
Note 13 — 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 techniques 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).
 
Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, long-term debt and various derivative instruments. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the short-term nature of these instruments. The following tables provide additional information relating to other financial instruments measured at fair value on a recurring basis (in thousands): 
 
Fair Value Measurements at
September 30, 2015 Using
 
 
 
 
 
Level 1
 
Level 2 (1)
 
Level 3
 
Total
 
Valuation
Technique
Liabilities:
 
 
 
 
 
 
 
 
 
Foreign exchange contracts
$

 
$
62,379

 
$

 
$
62,379

 
(c)
Interest rate swaps

 
3,171

 

 
3,171

 
(c)
Total liability
$

 
$
65,550

 
$

 
$
65,550

 
 
 

23



 
Fair Value Measurements at
December 31, 2014 Using
 
 
 
 
 
Level 1
 
Level 2 (1)
 
Level 3
 
Total
 
Valuation
Technique
Assets:
 
 
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
369

 
$

 
$
369

 
(c)
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
Foreign exchange contracts

 
50,428

 

 
50,428

 
(c)
Interest rate swaps

 
561

 

 
561

 
(c)
Total net liability
$

 
$
50,620

 
$

 
$
50,620

 
 
 
(1)
Unless otherwise indicated, the fair value of our Level 2 derivative instruments 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 and market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. See Note 14 for further discussion on fair value of our derivative instruments.
 
The fair value of our long-term debt is as follows (in thousands): 
 
September 30, 2015
 
December 31, 2014
 
Carrying
Value
 
Fair
Value (2)
 
Carrying
Value
 
Fair
Value (2)
 
 
 
 
 
 
 
 
Term Loan (matures June 2018)
$
262,500

 
$
259,547

 
$
277,500

 
$
270,563

Nordea Q5000 Loan (matures April 2020)
241,071

 
236,852

 

 

MARAD Debt (matures February 2027)
89,148

 
98,036

 
94,792

 
104,830

2032 Notes (mature March 2032) (1)
200,000

 
166,250

 
200,000

 
222,900

Total debt
$
792,719

 
$
760,685

 
$
572,292

 
$
598,293

 
(1)
Carrying amount excludes the related unamortized debt discount of $16.5 million at September 30, 2015 and $20.9 million at December 31, 2014.
 
(2)
The estimated fair value of the 2032 Notes was determined using Level 1 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. The fair value of the Term Loan, the Nordea Q5000 Loan and the MARAD Debt 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.
Note 14 — Derivative Instruments and Hedging Activities
 
Our operations are exposed to market risk 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. All derivatives are reflected in the accompanying condensed consolidated balance sheets at fair value.
 

24



We engage solely in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the fair value of derivatives that are designated as cash flow hedges are deferred to the extent that the hedges are effective. These fair value changes are recorded as a component of Accumulated OCI (a component of shareholders’ equity) until the hedged transactions occur and are recognized in earnings. The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately in earnings. In addition, any change in the fair value of a derivative 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 derivatives, see Notes 2 and 15 to our 2014 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 September 2013, we entered into various interest rate swap contracts to fix the interest rate on $148.1 million of our Term Loan borrowings (Note 6). These contracts, which are settled monthly, began in October 2013 and extend through October 2016. Additionally, in June 2015 we entered into various interest rate swap contracts to fix the interest rate on $187.5 million of our Nordea Q5000 Loan borrowings (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 hedge accounting treatment. Changes in the fair value of interest rate swaps are deferred to the extent the swaps are effective. These changes are recorded as a component of Accumulated OCI until the anticipated interest is recognized as interest expense. The ineffective portion of the interest rate swaps, if any, is recognized immediately in earnings within the line titled “Net interest expense.” The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.
 
Foreign Currency Exchange Rate Risk
 
Because we operate in various regions in 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 January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 the foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II and Grand Canyon III charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively.
 

25



Quantitative Disclosures Relating to Derivative Instruments 
 
The following table presents the fair value and balance sheet classification of our derivative instruments that were designated as hedging instruments (in thousands): 
 
September 30, 2015
 
December 31, 2014
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Asset Derivatives:
 
 
 
 
 
 
 
Interest rate swaps
Other assets, net
 
$

 
Other assets, net
 
$
369

 
 
 
$

 
 
 
$
369

 
 
 
 
 
 
 
 
Liability Derivatives:
 
 
 
 
 
 
 
Foreign exchange contracts
Accrued liabilities
 
$
20,443

 
Accrued liabilities
 
$
12,661

Interest rate swaps
Accrued liabilities
 
2,347

 
Accrued liabilities
 
561

Foreign exchange contracts
Other non-current liabilities
 
41,936

 
Other non-current liabilities
 
37,767

Interest rate swaps
Other non-current liabilities
 
824

 
Other non-current liabilities
 

 
 
 
$
65,550

 
 
 
$
50,989

 
For the three- and nine-month periods ended September 30, 2015, we recorded losses of $0.4 million and $3.6 million, respectively, in “Other expense, net” in the accompanying condensed consolidated statement of operations related to ineffectiveness associated with our foreign currency hedges with respect to the Grand Canyon III charter payments as a result of the deferral of the vessel’s delivery until February 2016. Ineffectiveness associated with our cash flow hedges was immaterial for the three- and nine-month periods ended September 30, 2014. The following tables present the impact that derivative instruments designated as cash flow hedges had on our Accumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of September 30, 2015, $13.4 million of losses in Accumulated OCI associated with our derivatives is expected to be reclassified into earnings within the next 12 months.
 
 
Gain (Loss) Recognized in OCI
on Derivatives, Net of Tax
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
Foreign exchange contracts
$
(5,777
)
 
$
(5,713
)
 
$
(7,136
)
 
$
(4,823
)
Interest rate swaps
(975
)
 
255

 
(1,848
)
 
141

 
$
(6,752
)
 
$
(5,458
)
 
$
(8,984
)
 
$
(4,682
)
 
 
Location of Loss Reclassified from
Accumulated OCI into Earnings
 
Loss Reclassified from
Accumulated OCI into Earnings
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
Foreign exchange contracts
Cost of sales
 
$
(3,433
)
 
$
(215
)
 
$
(7,828
)
 
$
(646
)
Interest rate swaps
Net interest expense
 
(822
)
 
(597
)
 
(1,358
)
 
(1,434
)
 
 
 
$
(4,255
)
 
$
(812
)
 
$
(9,186
)
 
$
(2,080
)

26



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,” “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 or any other business plans, forecasts or objectives, any or all of which are subject to change;
statements regarding the construction, upgrades or acquisition of vessels or equipment and any anticipated costs related thereto, including the construction of our Q7000 vessel and the construction of two chartered vessels to be used in connection with our contracts to provide well intervention services offshore Brazil (Note 12);
statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;
statements regarding our backlog and long-term contracts;
statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
statements regarding the collectability of our trade receivables;
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 market areas in which we do business;
statements regarding our ability to retain key members of our senior management and 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 these 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, among other things: 
 
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;
impact of potential cancellation, deferral or modification of our work or contracts by our customers;

27



unexpected delays in the delivery or chartering of new vessels for our well intervention and robotics fleet, including the Q7000, the Grand Canyon III and the two newbuild chartered vessels to be used to perform contracted well intervention work offshore Brazil;
unexpected future capital expenditures (including the amount and nature thereof);
the effectiveness and timing of completion of our vessel upgrades and major maintenance items;
the results of our continuing efforts to control costs and improve performance;
the success of our risk management activities;
the effects of competition;
the impact of current and future laws and governmental regulations, including tax and accounting developments;
the effect of adverse weather conditions and/or other risks associated with marine operations;
the effectiveness of our current and future hedging activities;
the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations and our ability to reduce certain capital commitments;
the effects of our indebtedness;
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 2014 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.
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 will deliver favorable long-term financial returns. We are making strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. On our well intervention side, we took delivery of the Q5000 at the end of April 2015. Our well intervention fleet is expected to expand following the completion and delivery of a second newbuild semi-submersible vessel currently under construction, the Q7000, and the expected delivery of two newbuild monohull vessels, which we will charter in connection with the well intervention agreements that we entered into with Petrobras. On our robotics side, we took delivery of the Grand Canyon II in late April 2015. We will upgrade our robotics fleet by chartering the Grand Canyon III newbuild vessel while downsizing the fleet by returning two chartered vessels to their owners in 2016.
 
On January 5, 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 is expected to leverage the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. In furtherance of the strategy of the contractual alliance, we and OneSubsea have jointly ordered a 15,000 working p.s.i. well access package to be delivered by July 2017 for a total cost of approximately $27.5 million, of which we are responsible for 50%.
 

28



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 make capital expenditures for offshore exploration, drilling and production operations. 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 but not limited to: 
 
worldwide economic activity, 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;
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 (“OPEC”);
the availability and discovery rate of new oil and natural gas reserves in offshore areas;
the exploration and production of shale oil and natural gas;
the cost of offshore exploration for and production and transportation of oil and natural gas;
the ability of oil and gas companies to generate funds or otherwise obtain external capital for exploration, development 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;
weather conditions;
environmental and other governmental regulations; and
domestic and international tax laws, regulations and policies.
 
Global prices for crude oil are roughly half of the amounts that were realized around mid-year 2014 while prices for natural gas remain relatively low. The significant decrease in oil prices is attributable to a global oversupply of oil, which reflects increased production in certain countries (primarily the United States). U.S. domestic oil production has nearly doubled over the past few years. Major oil producers, such as Saudi Arabia, which have seen a decline in their oil exports to the U.S. are increasingly competing with other oil exporters such as Canada, Iraq and Russia in other markets (e.g., Asia). The easing of sanctions on Iran is likely to result in additional crude oil supply to the global market. OPEC’s continued unwillingness to reduce its daily production quotas to support higher oil prices reflects a few of its member nations’ fear of losing market share. On the demand side, China’s equity market turmoil and recent currency devaluation suggests the economy of the world’s largest oil importer will be weaker than expected. Europe’s economy continues to suffer from sluggish growth. Greece’s debt crisis is far from over despite a third bailout deal in August 2015. The Federal Reserve’s recent decision not to raise benchmark interest rates may be a reflection of a weaker global economic outlook than previously anticipated. In light of the sharp decline in oil prices, many oil and gas companies have decided to terminate or not renew contracts for more than half of their contracted rigs and drastically cut investments in exploration and production.
 
We expect these challenging industry conditions to continue into 2016 and beyond if oil and gas prices fail to increase. Increased competition for limited offshore oil and gas capital projects has driven down rates that drilling rig contractors are charging for their services, which affects all offshore oil and gas services contractors, including us, and is also expected to affect utilization of our assets, and increasingly for 2016, our robotics assets. In addition, the current dynamic and uncertain macroeconomic conditions in some countries around the world, such as Brazil, may have direct and/or indirect impact on existing contracts and contracting opportunities. On the positive side, 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 when oil and gas companies begin to increase overall spending levels, it

29



will likely be for production 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 over the longer term, we believe that fundamentals for our business remain favorable as the need for prolongation of well life in oil and gas production is the primary driver of demand for our services.
 
In addition, we believe that we are well positioned for future recovery as well as sustaining potential prolongation of market conditions with less than robust demand for deepwater production based on the following factors: (1) the need to extend the life of subsea wells is significant to the commerciality 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; and (3) in past cycles, well intervention and workover have been the first market niches to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells.
 
Helix Fast Response System
 
We developed the HFRS as a culmination of our experience as a responder in the Macondo well control and containment efforts. The HFRS centers on two of our vessels, the HP I and the Q4000, both of which played a key role in the Macondo well control and containment efforts and are currently operating in the Gulf of Mexico. In 2011, we signed an agreement with Clean Gulf Associates (“CGA”), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available to certain CGA participants who executed utilization agreements with us that specified the day rates to be charged should the HFRS be deployed in connection with a well control incident. The original set of agreements expired on March 31, 2013, and we entered into a new set of substantially similar agreements effective April 1, 2013 with the operators who formed HWCG LLC, a Delaware limited liability company comprised of some of the original CGA members as well as other industry participants, to perform the same functions as CGA with respect to the HFRS. In March 2015, HWCG LLC exercised a one-year option to extend the agreement with us through March 31, 2018.
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 developing offshore reservoirs and maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We operate primarily in deepwater in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and intend to increase our operations offshore Brazil. In addition, our Robotics operations are often contracted for the development of renewable energy projects (wind farms). As of September 30, 2015, our consolidated backlog that is supported by written agreements or contracts totaled $1.8 billion, of which $118.4 million is expected to be performed over the remainder of 2015. The substantial majority of our backlog is associated with our Well Intervention business segment. As of September 30, 2015, our well intervention backlog was $1.7 billion, including $70.7 million expected to be performed over the remainder of 2015. Our five-year contract with BP to provide well intervention services with our Q5000 semi-submersible vessel and our four-year agreements with Petrobras to provide well intervention services offshore Brazil with two chartered newbuild monohull vessels, represent approximately 78% of our total backlog. Backlog contracts are cancelable sometimes without penalty. In addition, 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. Accordingly, backlog is not necessarily a reliable indicator of total annual revenues for our services as contracts may be added, renegotiated, deferred, canceled and in many cases modified while in progress.
 

30



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 U.S. GAAP. We measure our operating performance based on EBITDA, a non-GAAP financial measure that is commonly used but is not a recognized accounting term under GAAP. We use EBITDA to monitor and facilitate the 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 our measure of EBITDA provides 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 net income plus income taxes, depreciation and amortization expense, and net interest expense and other. In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted. This means that these amounts are recorded at 100% even if we do not own 100% of all of our subsidiaries. Accordingly, to arrive at our measure of Adjusted EBITDA, when applicable, we deduct the noncontrolling interests related to the adjustment components of EBITDA and the gain or loss on disposition of assets.
 
Other companies may calculate their measures of EBITDA and Adjusted EBITDA differently than we do, which may limit their usefulness as comparative measures. Because EBITDA is not a financial measure calculated in accordance with U.S. GAAP, it should not be considered in isolation or as a substitute for net income attributable to common shareholders or cash flows from operations, but used as a supplement to these GAAP financial measures. The reconciliation of our net income to EBITDA and Adjusted EBITDA is as follows (in thousands): 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
Net income applicable to common shareholders
$
9,880

 
$
75,586

 
$
26,887

 
$
187,087

Adjustments:
 
 
 
 
 
 
 
Net income applicable to noncontrolling interests

 

 

 
503

Income tax provision
94

 
29,832

 
1,115

 
67,778

Net interest expense and other
8,718

 
3,258

 
24,215

 
13,085

Depreciation and amortization
32,805

 
28,421

 
86,333

 
81,274

EBITDA
51,497

 
137,097

 
138,550

 
349,727

Adjustments:
 
 
 
 
 
 
 
Noncontrolling interests

 

 

 
(661
)
Gain on disposition of assets, net

 

 

 
(10,418
)
ADJUSTED EBITDA
$
51,497

 
$
137,097

 
$
138,550

 
$
338,648

 

31



Comparison of Three Months Ended September 30, 2015 and 2014 
 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
 
Three Months Ended
September 30,
 
Increase/
(Decrease)
 
2015
 
2014
 
Net revenues —
 
 
 
 
 
Well Intervention
$
94,895

 
$
205,139

 
$
(110,244
)
Robotics
83,310

 
131,707

 
(48,397
)
Production Facilities
19,133

 
24,184

 
(5,051
)
Intercompany elimination
(14,876
)
 
(20,193
)
 
5,317

 
$
182,462

 
$
340,837

 
$
(158,375
)
 
 
 
 
 
 
Gross profit —
 
 
 
 
 
Well Intervention
$
8,967

 
$
84,166

 
$
(75,199
)
Robotics
17,071

 
31,457

 
(14,386
)
Production Facilities
7,125

 
11,422

 
(4,297
)
Corporate and other
(1,031
)
 
(901
)
 
(130
)
Intercompany elimination
(163
)
 
103

 
(266
)
 
$
31,969

 
$
126,247

 
$
(94,278
)
 
 
 
 
 
 
Gross margin —
 
 
 
 
 
Well Intervention
9%

 
41%

 
 
Robotics
20%

 
24%

 
 
Production Facilities
37%

 
47%

 
 
Total company
18%

 
37%

 
 
 
 
 
 
 
 
Number of vessels or ROV assets (1) / Utilization (2)
 
 
 
 
 
Well Intervention vessels
5/60%

 
5/97%

 
 
ROVs
60/59%

 
61/81%

 
 
Robotics vessels
5/87%

 
6/90%

 
 
 
(1)
Represents number of vessels or ROV assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. The Seawell was excluded for the first two months of the third quarter of 2015 as it was out of service undergoing major capital upgrades.
 
(2)
Average vessel utilization rate is calculated by dividing the total number of days the vessels or other assets generated revenues by the total number of calendar days in the applicable period. 
 

32



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
September 30,
 
Increase/
(Decrease)
 
2015
 
2014
 
 
 
 
 
 
 
Well Intervention
$
7,324

 
$
8,635

 
$
(1,311
)
Robotics
7,552

 
11,558

 
(4,006
)
 
$
14,876

 
$
20,193

 
$
(5,317
)
 
Net Revenues.  Our total net revenues decreased by 46% for the three-month period ended September 30, 2015 as compared to the same period in 2014. The decreased revenues for the three-month period in 2015 reflect the continuing adverse impact of reduced opportunities for near term work and the acceptance of work at lower rates for some of our assets.
 
Our Well Intervention revenues decreased by 54% for the three-month period ended September 30, 2015 as compared to the same period in 2014 primarily reflecting decreased utilization of our in-service well intervention vessels and no utilization of the Seawell and the Helix 534. In the North Sea, the Seawell has been warmed stacked since September 2015 after completion of its life extension capital upgrades. The Well Enhancer worked 84 days during the third quarter of 2015 as compared to 90 days in the same period in 2014. The Skandi Constructor