HELIX ENERGY SOLUTIONS GROUP INC - Quarter Report: 2017 June (Form 10-Q)

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

Emerging growth company ¨

(Do not check if a smaller reporting company)

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 June 30, 2017



¨		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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No

As of July 21, 2017, 147,683,937 shares of common stock were outstanding.

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PART I.	FINANCIAL INFORMATION	PAGE

Item 1.	Financial Statements:

	Condensed Consolidated Balance Sheets – June 30, 2017 (Unaudited) and December 31, 2016	3

	Condensed Consolidated Statements of Operations (Unaudited) – Three months ended June 30, 2017 and 2016	4

	Condensed Consolidated Statements of Operations (Unaudited) – Six months ended June 30, 2017 and 2016	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) – Three and six months ended June 30, 2017 and 2016	6

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Six months ended June 30, 2017 and 2016	7

	Notes to Condensed Consolidated Financial Statements (Unaudited)	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41

Item 4.	Controls and Procedures	42

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 6.	Exhibits	43

	Signatures	44

	Index to Exhibits	45

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)



	June 30, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	390,435		$	356,647
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $2,752 and $1,778, respectively	83,555			101,825
Unbilled revenue and other	40,312			10,328
Current deferred tax assets	—			16,594
Other current assets	40,206			37,388
Total current assets	554,508			522,782
Property and equipment	2,562,835			2,450,890
Less accumulated depreciation	(851,432		)	(799,280		)
Property and equipment, net	1,711,403			1,651,610
Other assets, net	95,651			72,549
Total assets	$	2,361,562		$	2,246,941

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	86,601		$	60,210
Accrued liabilities	60,119			58,614
Current maturities of long-term debt	107,205			67,571
Total current liabilities	253,925			186,395
Long-term debt	408,250			558,396
Deferred tax liabilities	154,826			167,351
Other non-current liabilities	46,926			52,985
Total liabilities	863,927			965,127
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 147,670 and 120,630 shares issued, respectively	1,279,162			1,055,934
Retained earnings	300,036			322,854
Accumulated other comprehensive loss	(81,563		)	(96,974		)
Total shareholders’ equity	1,497,635			1,281,814
Total liabilities and shareholders’ equity	$	2,361,562		$	2,246,941

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)



	Three Months Ended June 30,
	2017			2016

Net revenues	$	150,329		$	107,267
Cost of sales	131,962			101,609
Gross profit	18,367			5,658
Selling, general and administrative expenses	(13,317		)	(14,953		)
Income (loss) from operations	5,050			(9,295		)
Equity in losses of investment	(152		)	(121		)
Net interest expense	(6,639		)	(7,480		)
Gain (loss) on early extinguishment of long-term debt	(397		)	302
Other income, net	467			1,308
Other income – oil and gas	291			396
Loss before income taxes	(1,380		)	(14,890		)
Income tax provision (benefit)	5,023			(4,219		)
Net loss	$	(6,403	)	$	(10,671	)

Loss per share of common stock:
Basic	$	(0.04	)	$	(0.10	)
Diluted	$	(0.04	)	$	(0.10	)

Weighted average common shares outstanding:
Basic	145,940			107,767
Diluted	145,940			107,767

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)



	Six Months Ended June 30,
	2017			2016

Net revenues	$	254,857		$	198,306
Cost of sales	237,315			209,578
Gross profit (loss)	17,542			(11,272		)
Loss on disposition of assets, net	(39		)	—
Selling, general and administrative expenses	(30,158		)	(28,779		)
Loss from operations	(12,655		)	(40,051		)
Equity in losses of investment	(304		)	(244		)
Net interest expense	(11,865		)	(18,164		)
Gain (loss) on early extinguishment of long-term debt	(397		)	302
Other income (expense), net	(68		)	3,188
Other income – oil and gas	2,893			2,968
Loss before income taxes	(22,396		)	(52,001		)
Income tax provision (benefit)	422			(13,507		)
Net loss	$	(22,818	)	$	(38,494	)

Loss per share of common stock:
Basic	$	(0.16	)	$	(0.36	)
Diluted	$	(0.16	)	$	(0.36	)

Weighted average common shares outstanding:
Basic	144,599			106,838
Diluted	144,599			106,838

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)



	Three Months Ended June 30,
	2017			2016

Net loss	$	(6,403	)	$	(10,671	)
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on hedges arising during the period	935			(2,344		)
Reclassification adjustments for loss on hedges included in net loss	3,949			3,054
Income taxes on unrealized (gain) loss on hedges	(1,708		)	(236		)
Unrealized gain on hedges, net of tax	3,176			474
Foreign currency translation gain (loss)	6,284			(14,641		)
Other comprehensive income (loss), net of tax	9,460			(14,167		)
Comprehensive income (loss)	$	3,057		$	(24,838	)



	Six Months Ended June 30,
	2017			2016

Net loss	$	(22,818	)	$	(38,494	)
Other comprehensive income (loss), net of tax:
Unrealized gain on hedges arising during the period	1,844			1,032
Reclassification adjustments for loss on hedges included in net loss	7,439			6,494
Income taxes on unrealized gain on hedges	(3,264		)	(2,553		)
Unrealized gain on hedges, net of tax	6,019			4,973
Foreign currency translation gain (loss) arising during the period	9,392			(21,216		)
Reclassification adjustment for translation loss realized upon liquidation	—			289
Foreign currency translation gain (loss)	9,392			(20,927		)
Other comprehensive income (loss), net of tax	15,411			(15,954		)
Comprehensive loss	$	(7,407	)	$	(54,448	)

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)



	Six Months Ended June 30,
	2017			2016
Cash flows from operating activities:
Net loss	$	(22,818	)	$	(38,494	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	56,377			57,239
Amortization of debt discount	2,303			3,134
Amortization of debt issuance costs	4,326			5,138
Share-based compensation	5,181			2,867
Deferred income taxes	(80		)	(10,047		)
Equity in losses of investment	304			244
Loss on disposition of assets, net	39			—
(Gain) loss on early extinguishment of long-term debt	397			(302		)
Unrealized gain and ineffectiveness on derivative contracts, net	(2,482		)	(6,147		)
Changes in operating assets and liabilities:
Accounts receivable, net	(10,122		)	19,062
Other current assets	(10,957		)	(3,055		)
Income tax receivable	(1,729		)	8,843
Accounts payable and accrued liabilities	27,372			(7,979		)
Other non-current, net	(32,510		)	(5,614		)
Net cash provided by operating activities	15,601			24,889

Cash flows from investing activities:
Capital expenditures	(94,396		)	(57,563		)
Distribution from equity investment	—			1,200
Proceeds from sale of equity investment	—			25,000
Proceeds from sale of assets	10,000			10,887
Net cash used in investing activities	(84,396		)	(20,476		)

Cash flows from financing activities:
Proceeds from term loan	100,000			—
Repayment of term loan	(192,258		)	(15,000		)
Repayment of Nordea Q5000 Loan	(17,858		)	(17,858		)
Repayment of MARAD Debt	(3,073		)	(2,927		)
Repurchase of Convertible Senior Notes due 2032	—			(6,480		)
Debt issuance costs	(3,665		)	(1,230		)
Net proceeds from issuance of common stock	219,504			38,773
Payments related to tax withholding for share-based compensation	(1,306		)	(187		)
Proceeds from issuance of ESPP shares	279			600
Net cash provided by (used in) financing activities	101,623			(4,309		)

Effect of exchange rate changes on cash and cash equivalents	960			(2,106		)
Net increase (decrease) in cash and cash equivalents	33,788			(2,002		)
Cash and cash equivalents:
Balance, beginning of year	356,647			494,192
Balance, end of period	$	390,435		$	492,190

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Basis of Presentation and New Accounting Standards

The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its subsidiaries (collectively, “Helix” or the “Company”). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (the “SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”).

The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. GAAP and are consistent in all material respects with those applied in our 2016 Annual Report on Form 10-K (“2016 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. We have made all adjustments (which were normal recurring adjustments) that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive income (loss), and statements of cash flows, as applicable. The operating results for the three- and six-month periods ended June 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. Our balance sheet as of December 31, 2016 included herein has been derived from the audited balance sheet as of December 31, 2016 included in our 2016 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 2016 Form 10-K.

Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format.

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 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, and was subsequently deferred by one year to annual reporting periods beginning after December 15, 2017. The FASB also issued several subsequent updates containing implementation guidance on principal versus agent considerations (gross versus net revenue presentation), identifying performance obligations and accounting for licenses of intellectual property. Additionally, these updates provide narrow-scope improvements and practical expedients as well as technical corrections and improvements to the guidance. The new revenue standard 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 continue reviewing our contracts with customers for gap analysis. We are also working on expanded disclosure requirements and documentation of new policies, procedures and controls. We expect to make a determination on our adoption method (full retrospective or modified retrospective method) in the third quarter of 2017.

In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes.” This ASU requires companies to classify all deferred tax assets and liabilities as non-current on the balance sheet instead of separating deferred taxes into current and non-current amounts. The requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount was not affected by this guidance. We adopted this guidance prospectively in the first quarter of 2017. Prior periods were not retrospectively adjusted.

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU amends the existing accounting standards for leases. The amendments are intended to increase transparency and comparability among organizations by requiring recognition of lease assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. The guidance is

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required to be adopted at the earliest period presented using a modified retrospective approach. We expect to adopt this guidance in the first quarter of 2019. We are currently evaluating the impact these amendments will have on our consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Our restricted stock typically vests in the beginning of each year. The adoption of this guidance had no material impact on our consolidated financial statements for the three- and six-month periods ended June 30, 2017.

In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU replaces the current incurred loss model for measurement of credit losses on financial assets including trade receivables with a forward-looking expected loss model based on historical experience, current conditions and reasonable and supportable forecasts. The guidance is effective for annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

In October 2016, the FASB issued ASU No. 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” This ASU eliminates the exception in current guidance that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. Under the new ASU, an entity should recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on 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 maximizing production economics. We provide services primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and have recently expanded our operations into Brazil with the commencement of operations of the Siem Helix 1. 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 U.S. Gulf of Mexico, North Sea and Brazil. Our Well Intervention segment also includes intervention riser systems (“IRSs”), some of which we rent out on a stand-alone basis, and subsea intervention lubricators (“SILs”). Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer and the two chartered vessels, the Siem Helix 1 which is used and the Siem Helix 2 which is to be used, in connection with our contracts to provide well intervention services offshore Brazil. We also have a semi-submersible well intervention vessel under construction, the Q7000.

Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates four chartered ROV support vessels, including the Grand Canyon III that went into service for us in May 2017.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamic positioning floating production vessel, and the Helix Fast Response System (the “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. The HP I has been under contract to process production from the Phoenix field for the field operator since February 2013. We currently operate under a fixed fee agreement for the HP I for service to the Phoenix field until at least June 1, 2023. We are party to an agreement providing various operators with access to the HFRS for well control purposes, which was amended effective February 1, 2017 to reduce the retainer fee and to extend the term of the agreement by one year to March 31, 2019. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”) and previously included our former ownership interest in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) that we sold in February 2016 (Note 5).

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Note 3 — Details of Certain Accounts

Other current assets consist of the following (in thousands):



	June 30, 2017		December 31, 2016

Note receivable ⁽¹⁾	$	—	$	10,000
Prepaid insurance	3,603		4,426
Other prepaids	9,934		9,547
Deferred costs ⁽²⁾	17,992		7,971
Spare parts inventory	2,539		2,548
Income tax receivable	2,559		880
Value added tax receivable	2,741		1,345
Other	838		671
Total other current assets	$	40,206	$	37,388


(1)	Relates to the balance of the promissory note we received in connection with the sale of our former Ingleside spoolbase in January 2014. Interest on the note was payable quarterly at a rate of 6% per annum. In June 2017, we collected the $10 million principal balance of this note receivable as well as accrued interest.


(2)	Primarily reflects deferred mobilization costs associated with certain long-term contracts, which are to be amortized within 12 months from the balance sheet date.

Other assets, net consist of the following (in thousands):



	June 30, 2017		December 31, 2016

Note receivable, net ⁽¹⁾	$	3,129	$	2,827
Prepaids	8,559		6,418
Deferred dry dock costs, net	16,100		14,766
Deferred costs ⁽²⁾	50,146		30,738
Deferred financing costs, net ⁽³⁾	3,052		3,745
Charter fee deposit ⁽⁴⁾	12,544		12,544
Other	2,121		1,511
Total other assets, net	$	95,651	$	72,549

(1)

In 2016, we entered into an agreement with one of our customers to defer their payment obligations until June 30, 2018. On March 30, 2017, we entered into a new agreement with this customer in which we agreed to forgive all but $4.3 million of our outstanding receivables due from the customer in exchange for redeemable convertible bonds that approximated that amount. The bonds are redeemable by the customer at any time and the maturity date of the bonds is December 14, 2019. Interest at a rate of 5% per annum is payable on the bonds annually. Amounts presented were net of allowance of $1.2 million at June 30, 2017 and $4.2 million at December 31, 2016.


(2)	Primarily reflects deferred mobilization costs to be amortized after 12 months from the balance sheet date through the end of the applicable term of certain long-term contracts.


(3)	Represents unamortized debt issuance costs related to our revolving credit facility (Note 6).


(4)	Deposit amount will be used to reduce our final charter payments for the Siem Helix 2.

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Accrued liabilities consist of the following (in thousands):



	June 30, 2017		December 31, 2016

Accrued payroll and related benefits	$	27,224	$	20,705
Deferred revenue	7,547		8,911
Accrued interest	3,139		3,758
Derivative liability (Note 14)	13,259		18,730
Taxes payable excluding income tax payable	919		1,214
Other	8,031		5,296
Total accrued liabilities	$	60,119	$	58,614

Other non-current liabilities consist of the following (in thousands):



	June 30, 2017		December 31, 2016

Investee losses in excess of investment (Note 5)	$	9,817	$	10,238
Deferred gain on sale of property ⁽¹⁾	5,862		5,761
Deferred revenue	8,910		8,598
Derivative liability (Note 14)	13,809		20,191
Other	8,528		8,197
Total other non-current liabilities	$	46,926	$	52,985


(1)	Relates to the sale and lease-back of our office and warehouse property located in Aberdeen, Scotland in January 2016. The deferred gain is amortized over a 15-year minimum lease term.

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):



	Six Months Ended June 30,
	2017		2016

Interest paid, net of interest capitalized	$	6,663	$	10,321
Income taxes paid	$	2,424	$	3,845

Our non-cash investing activities include property and equipment capital expenditures that are incurred but not yet paid. These non-cash capital expenditures totaled $16.1 million as of June 30, 2017 and $10.1 million as of December 31, 2016.

Note 5 — Equity Investments

We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. We previously had a 50% ownership interest in Deepwater Gateway, which we sold in February 2016 to a subsidiary of Genesis Energy, L.P., the other 50% owner, for $25 million with no resulting gain or loss. We also received a cash distribution of $1.2 million from Deepwater Gateway in February 2016. These equity investments are included in our Production Facilities segment.

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Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. Our share of the losses reported by Independence Hub exceeded the carrying amount of our investment by $9.8 million as of June 30, 2017 and $10.2 million at December 31, 2016 reflecting our share of Independence Hub’s obligations (primarily its estimated asset retirement obligations to decommission the platform), net of remaining working capital. This liability is reflected in “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

Note 6 — Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of June 30, 2017 are as follows (in thousands):



	Term Loan ⁽¹⁾			2022 Notes			2032 Notes ⁽²⁾			MARAD Debt			Nordea Q5000 Loan			Total

Less than one year	$	5,000		$	—		$	60,115		$	6,375		$	35,715		$	107,205
One to two years	10,000			—			—			6,693			35,714			52,407
Two to three years	85,000			—			—			7,027			107,142			199,169
Three to four years	—			—			—			7,378			—			7,378
Four to five years	—			—			—			7,746			—			7,746
Over five years	—			125,000			—			44,930			—			169,930
Total debt	100,000			125,000			60,115			80,149			178,571			543,835
Current maturities	(5,000		)	—			(60,115		)	(6,375		)	(35,715		)	(107,205		)
Long-term debt, less current maturities	95,000			125,000			—			73,774			142,856			436,630
Unamortized debt discount ⁽³⁾	—			(15,218		)	(1,573		)	—			—			(16,791		)
Unamortized debt issuance costs ⁽⁴⁾	(1,967		)	(2,560		)	(138		)	(4,757		)	(2,167		)	(11,589		)
Long-term debt	$	93,033		$	107,222		$	(1,711	)	$	69,017		$	140,689		$	408,250


(1)	Term Loan borrowing pursuant to the Credit Agreement (amended and restated in June 2017) matures in June 2020.


(2)	The holders of our remaining Convertible Senior Notes due 2032 may require us to repurchase the notes in March 2018. Accordingly, these notes are classified as current liabilities.


(3)	Our Convertible Senior Notes due 2022 will increase to their face amount through accretion of non-cash interest charges through May 2022. Our Convertible Senior Notes due 2032 will increase to their face amount through accretion of non-cash interest charges through March 2018.


(4)	Debt issuance costs are amortized over the term of the applicable debt agreement.

Below is a summary of certain components of our indebtedness:

Credit Agreement

On June 30, 2017, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”), which agreement is comprised of a $100 million term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) of up to $150 million (the “Revolving Loans”). The Revolving Credit Facility also permits the Company to obtain letters of credit up to a sublimit of $25 million. Subject to customary conditions, we may request aggregate commitments up to $100 million with respect to an increase in the Revolving Credit Facility, additional term loans, or a combination thereof. The $100 million proceeds from the Term Loan as well as cash on hand were used to repay the approximately $180 million term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement. At June 30, 2017, we had no borrowings under the Revolving Credit Facility, and we had $3.0 million of letters of credit issued under that facility.

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The Term Loan and the Revolving Loans (together, the “Loans”), at our election, bear interest either in relation to Bank of America’s base rate or to a LIBOR rate. The Term Loan or portions thereof bearing interest at the base rate will bear interest at a per annum rate equal to the base rate plus 3.25%. The Term Loan or portions thereof bearing interest at a LIBOR rate will bear interest per annum at the LIBOR rate selected by us plus a margin of 4.25%. The Revolving Loans or portions thereof bearing interest at the base rate will bear interest at a per annum rate equal to the base rate plus a margin ranging from 1.75% to 3.25%. The Revolving Loans or portions thereof bearing interest at a LIBOR rate will bear interest per annum at the LIBOR rate selected by us plus a margin ranging from 2.75% to 4.25%. A letter of credit fee is payable by us equal to its applicable margin for LIBOR rate Loans times the daily amount available to be drawn under the applicable letter of credit. Margins on the Revolving Loans will vary in relation to the consolidated total leverage ratio provided for in the Credit Agreement. We also pay a fixed commitment fee of 0.50% per annum on the unused portion of our Revolving Credit Facility.

The Term Loan is subject to scheduled installments of principal reduction of 5% in the first loan year, 10% in the second loan year and 15% in the third loan year, payable quarterly, with a balloon payment at maturity, which 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 prepaid up to the amount of the Revolving Credit Facility. The Loans mature on June 30, 2020.

The Credit Agreement and the other documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, which we consider customary for this type of transaction. The covenants include certain restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and make capital expenditures. In addition, the Credit Agreement obligates us to meet minimum financial ratio requirements of EBITDA to interest charges (“Consolidated Interest Coverage Ratio”) and funded debt to EBITDA (“Consolidated Total Leverage Ratio”), provided that if there are no Loans outstanding, the funded debt ratio requirement permits us to offset a certain amount of cash against the funded debt used in the calculation (“Consolidated Net Leverage Ratio”). For any period where there are amounts outstanding under any Loans or unreimbursed draws under letters of credit issued under the Revolving Credit Facility, we are also required to meet a minimum ratio requirement of total secured indebtedness to EBITDA (“Consolidated Secured Leverage Ratio”). The Credit Agreement also obligates us to maintain certain cash levels depending on the type of indebtedness outstanding. These financial covenant requirements are detailed as follows:


(a)	The minimum required Consolidated Interest Coverage Ratio:



Four Fiscal Quarters Ending	Minimum Consolidated Interest Coverage Ratio

September 30, 2017 and each fiscal quarter thereafter	2.50	to 1.00


(b)	The maximum permitted Consolidated Total Leverage Ratio or Consolidated Net Leverage Ratio:



Four Fiscal Quarters Ending	Maximum Consolidated Total or Net Leverage Ratio

September 30, 2017	6.00	to 1.00
December 31, 2017	5.75	to 1.00
March 31, 2018	5.50	to 1.00
June 30, 2018	5.25	to 1.00
September 30, 2018	5.00	to 1.00
December 31, 2018 through and including March 31, 2019	4.50	to 1.00
June 30, 2019 through and including September 30, 2019	4.25	to 1.00
December 31, 2019	4.00	to 1.00
March 31, 2020 and each fiscal quarter thereafter	3.50	to 1.00

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(c)	The maximum permitted Consolidated Secured Leverage Ratio:



Four Fiscal Quarters Ending	Maximum Consolidated Secured Leverage Ratio

September 30, 2017 through and including June 30, 2018	3.00	to 1.00
September 30, 2018 and each fiscal quarter thereafter	2.50	to 1.00


(d)	The minimum required Unrestricted Cash and Cash Equivalents:



Consolidated Total Leverage Ratio	Minimum Cash ⁽¹⁾

Greater than or equal to 4.00 to 1.00	$100,000,000.00
Greater than or equal to 3.50 to 1.00 but less than 4.00 to 1.00	$50,000,000.00
Less than 3.50 to 1.00	$0.00

(1)

This minimum cash balance is not required to be maintained in any particular bank account or to be segregated from other cash balances in bank accounts that we use in our ordinary course of business. Because the use of this cash is not legally restricted notwithstanding this maintenance covenant, we present it as cash and cash equivalents on our balance sheet. As of June 30, 2017, we were required to, and did, maintain an aggregate cash balance of at least $100 million in order to comply with this covenant.

We may from time to time designate one or more of our foreign subsidiaries as subsidiaries which are not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”), provided that we meet certain liquidity requirements. The debt and EBITDA of Unrestricted Subsidiaries are not included in the calculations of our financial covenants, except for the debt and EBITDA of Helix Q5000 Holdings, S.a.r.l., a wholly owned subsidiary incorporated in Luxembourg (“Q5000 Holdings”). Our obligations under the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, a wholly owned Scottish subsidiary, and our obligations under the Credit Agreement and of such guarantors under their guarantee are secured by most of our assets of the parent, our 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.

In June 2017, we recognized a $0.4 million loss to write off the unamortized debt issuance costs related to the lenders exiting from the term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement, which loss is presented as “Loss on early extinguishment of long-term debt” in the accompanying consolidated statements of operations. In connection with decreases in lenders’ commitments under our revolving credit facility, in June 2017 and February 2016 we recorded interest charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments were reduced.

Convertible Senior Notes Due 2022

On November 1, 2016, we completed a public offering and sale of our Convertible Senior Notes due 2022 (the “2022 Notes”) in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2022 Notes were $121.7 million, after deducting the underwriter’s discounts and commissions and offering expenses. We used net proceeds from the issuance of the 2022 Notes, as well as cash on hand, to repurchase and retire $125 million of aggregate principal amount of the 2032 Notes (see “Convertible Senior Notes Due 2032” below) in separate, privately negotiated transactions.

The 2022 Notes bear interest at a rate of 4.25% per annum, and are payable semi-annually in arrears on November 1 and May 1 of each year, beginning on May 1, 2017. The 2022 Notes mature on May 1, 2022, unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions (as described in the Indenture governing the 2022 Notes) the 2022 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 71.9748 shares of common stock per $1,000 principal amount (which represents an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2022 Notes. We have the right and the intention to settle any such future conversions in cash.

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Prior to November 1, 2019, the 2022 Notes are not redeemable. On or after November 1, 2019, we may redeem all or any portion of the 2022 Notes, at our option, subject to certain conditions, at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium” with a value equal to the present value of the remaining scheduled interest payments of the 2022 Notes to be redeemed through May 1, 2022. Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change,” as defined in the 2022 Notes documentation.

The Indenture governing the 2022 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the Indenture or the holders of not less than 25% in aggregate principal amount of the 2022 Notes then outstanding may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a principal subsidiary, the principal amount of the 2022 Notes together with any accrued and unpaid interest thereon will automatically be and become immediately due and payable.

In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million as required under existing accounting rules. To arrive at this discount amount, we estimated the fair value of the liability component of the 2022 Notes as of October 26, 2016 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 pricing and an expected life of 5.5 years. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2022 Notes at their inception. We recorded $11.0 million, net of tax, related to the carrying amount of the equity component of the 2022 Notes. The remaining unamortized amount of the debt discount of the 2022 Notes was $15.2 million at June 30, 2017 and $16.5 million at December 31, 2016.

Convertible Senior Notes Due 2032

In March 2012, we completed a public offering and sale of our Convertible Senior Notes due 2032 (the “2032 Notes”) in the aggregate principal amount of $200 million, $60 million of which are currently outstanding. 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 (either a Change of Control or a Termination of Trading, as those terms are defined in the Indenture governing the 2032 Notes). We elected to repurchase $7.3 million, $7.6 million and $125 million, respectively, in aggregate principal amount of the 2032 Notes in June, July and November of 2016, respectively. In June 2016, we recognized a total gain of $0.3 million which is presented as “Gain on early extinguishment of long-term debt” in the accompanying consolidated statements of operations.

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In connection with the issuance of the 2032 Notes, we recorded a debt 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 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 pricing 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, net of tax, related to the carrying amount of the equity component of the 2032 Notes. The remaining unamortized amount of the debt discount of the 2032 Notes was $1.6 million at June 30, 2017 and $2.6 million at December 31, 2016.

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.

Nordea Credit Agreement

In September 2014, Q5000 Holdings entered into a credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) in an amount of up to $250 million. The Nordea Q5000 Loan was funded in the amount of $250 million in April 2015 at the time the Q5000 vessel was delivered to us. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., also a wholly owned Luxembourg subsidiary, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.

The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. Q5000 Holdings may elect to prepay 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 June 2015, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 14). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.

The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants and prepayment requirements, that we consider customary for this type of transaction. The covenants include restrictions on Q5000 Holdings’s ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, and pay dividends. In addition, the Nordea Credit Agreement obligates Q5000 Holdings to meet certain minimum financial requirements, including liquidity, consolidated debt service coverage and collateral maintenance.

Other

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The following table details the components of our net interest expense (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016

Interest expense	$	11,607		$	10,435		$	21,847		$	23,479
Interest income	(918		)	(436		)	(1,264		)	(880		)
Capitalized interest	(4,050		)	(2,519		)	(8,718		)	(4,435		)
Net interest expense	$	6,639		$	7,480		$	11,865		$	18,164

Note 7 — Income Taxes

We believe that our recorded deferred tax assets and liabilities are reasonable. However, tax laws and regulations are subject to interpretation and tax disputes are 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 six-month periods ended June 30, 2017 were (364.0)% and (1.9)%, respectively. The effective tax rates for the three- and six-month periods ended June 30, 2016 were 28.3% and 26.0%, respectively. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and a change in tax position related to our foreign taxes.

We continued recording income taxes using a year-to-date effective tax rate method for the three- and six-month periods ended June 30, 2017. The use of this method was based on our expectations at June 30, 2017 that a small change in our estimated ordinary income could result in a large change in the estimated annual effective tax rate. We will re-evaluate our use of this method each quarter until such time as a return to the annualized effective tax rate method is deemed appropriate.

Income taxes are provided based on the U.S. statutory rate of 35% and at the local statutory rate for each foreign jurisdiction adjusted for items that are allowed as deductions for federal and foreign income tax reporting purposes, but not for book purposes. The primary differences between the U.S. statutory rate and our effective rate are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016

U.S. statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Foreign provision	79.7		(8.3	)	(5.5	)	(9.3	)
Change in tax position ⁽¹⁾	(459.7	)	—		(28.3	)	—
Other	(19.0	)	1.6		(3.1	)	0.3
Effective rate	(364.0	)%	28.3	%	(1.9	)%	26.0	%

(1)

We consider all available evidence, both positive and negative, when determining whether a valuation allowance is required against deferred tax assets. Due to weaker near term outlook and financial results primarily associated with our Robotics segment, we currently do not anticipate generating sufficient foreign source income to fully utilize our foreign tax credits prior to their expiration. We have concluded that it is more likely than not that previously benefited deferred tax assets on foreign tax credits will not be realized. As a result of this change in tax position, we recorded a tax charge of $6.3 million in June 2017, which is comprised of a $2.8 million valuation allowance attributable to a foreign tax credit carryforward from 2015 and a $3.5 million charge attributable to the decision to deduct foreign taxes related to 2016 and 2017.

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Note 8 — Shareholders’ Equity

On January 10, 2017, we completed an underwritten public offering (the “Offering”) of 26,450,000 shares of our common stock at a public offering price of $8.65 per share. The net proceeds from the Offering approximated $220 million, after deducting underwriting discounts and commissions and estimated offering expenses. We intend to use the net proceeds from the Offering for general corporate purposes, which may include debt repayment, capital expenditures, working capital, acquisitions or investments in our subsidiaries.

The components of Accumulated Other Comprehensive Income (Loss) (“OCI”) are as follows (in thousands):



	June 30, 2017			December 31, 2016

Cumulative foreign currency translation adjustment	$	(69,561	)	$	(78,953	)
Unrealized loss on hedges, net ⁽¹⁾	(12,002		)	(18,021		)
Accumulated other comprehensive loss	$	(81,563	)	$	(96,974	)


(1)	Relates to foreign currency hedges for the Grand Canyon, Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan, and are net of deferred income taxes totaling $6.5 million at June 30, 2017 and $9.7 million at December 31, 2016 (Note 14).

Note 9 — Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. Holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common stock and the shares of restricted stock 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. For periods in which we have a net loss we do not use the two class method as holders of our restricted shares are not obligated to share in such losses.

The presentation of basic EPS amounts on the face of the accompanying condensed consolidated statements of operations is computed by dividing net income or loss by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to 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.

We had net losses for the three- and six-month periods ended June 30, 2017 and 2016. Accordingly, our diluted EPS calculation for these periods was equivalent to our basic EPS calculation since diluted EPS excluded any assumed exercise or conversion of common stock equivalents. These common stock equivalents were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2017	2016	2017	2016

Diluted shares (as reported)	145,940	107,767	144,599	106,838
Share-based awards	228	377	244	187
Total	146,168	108,144	144,843	107,025

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In addition, the following potentially dilutive shares related to the 2022 Notes and the 2032 Notes were excluded from the diluted EPS calculation because we have the right and the intention to settle any such future conversions in cash (Note 6) (in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2017	2016	2017	2016

2022 Notes	8,997	—	8,997	—
2032 Notes	2,403	7,959	2,403	7,977

Note 10 — Employee Benefit Plans

Long-Term Incentive Stock-Based Plan

As of June 30, 2017, there were 2.5 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 January 1, 2017 (the “2005 Incentive Plan”). During the six-month period ended June 30, 2017, 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 3, 2017 ⁽¹⁾	671,771	$	8.82	33% per year over three years
January 3, 2017 ⁽²⁾	671,771	$	12.64	100% on January 1, 2020
January 3, 2017 ⁽³⁾	9,956	$	8.82	100% on January 1, 2019
April 3, 2017 ⁽³⁾	8,004	$	7.77	100% on January 1, 2019


(1)	Reflects the grant of restricted stock to our executive officers and select management employees.

(2)

Reflects the grant of performance share units (“PSUs”) to our executive officers and select management employees. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum amount of the award being 200% of the original awarded PSUs and the minimum amount being zero. For the 2017 awards, vested PSUs can only be settled in shares of our common stock.


(3)	Reflects the grant of restricted stock to certain independent members of our Board of Directors (the “Board”) who have made an election to take their quarterly fees in stock in lieu of cash.

Compensation cost for restricted stock is the product of grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting periods on a straight-line basis. We elected to account for forfeitures when they occur upon the adoption of the new guidance for employee share-based payment accounting (Note 1). For the three- and six-month periods ended June 30, 2017, $1.7 million and $3.7 million, respectively, were recognized as share-based compensation related to restricted stock. For the three- and six-month periods ended June 30, 2016, $1.4 million and $2.9 million, respectively, were recognized as share-based compensation related to restricted stock.

The estimated fair value of PSUs is determined using a Monte Carlo simulation model. Compensation cost for PSUs that are accounted for as equity awards is measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line basis. PSUs that are accounted for as liability awards are measured based on the estimated fair value at the balance sheet date and changes in fair value of the awards are recognized in earnings. Cumulative compensation cost for vested liability PSU awards equals the actual cash payout amount upon vesting. The 2017 awards are accounted for as equity awards whereas awards made prior to 2017 are accounted for as liability awards. For the three-month period ended June 30, 2017, we recorded a net reduction of $0.5 million of previously recognized compensation cost related to unvested PSUs. For the six-month period ended June 30, 2017, $1.7 million was recognized as share-based compensation related to PSUs. For the three- and six-month periods ended June 30, 2016, $1.7 million and $2.8 million, respectively, were recognized as share-based compensation related to PSUs. The liability balance for unvested PSUs was $6.8 million at June 30, 2017 and $7.1 million at December 31, 2016. We paid $0.6 million in cash to settle the 2014 grant of PSUs when they vested in January 2017.

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Employee Stock Purchase Plan

We have an employee stock purchase plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance, of which 0.7 million shares were available for issuance as of June 30, 2017. In February 2016, we suspended ESPP purchases for the January through April 2016 purchase period and indefinitely imposed a purchase limit of 130 shares per employee for subsequent purchase periods.

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 12 to our 2016 Form 10-K.

Note 11 — Business Segment Information

We have three reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention business segment for financial reporting purposes. Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, North Sea and Brazil. Our Well Intervention segment also includes IRSs, some of which we rent out on a stand-alone basis, and SILs. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer and the chartered Siem Helix 1 and Siem Helix 2 vessels. The Siem Helix 1 commenced its operations for Petrobras in mid-April 2017. Our Robotics segment includes ROVs, trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates four chartered ROV support vessels, including the Grand Canyon III that went into service for us in May 2017. Our Production Facilities segment includes the HP I, the HFRS and our investment in Independence Hub that is accounted for under the equity method, and previously included our former ownership interest in Deepwater Gateway that we sold in February 2016 (Note 5). All material intercompany transactions between the segments have been eliminated.

We evaluate our performance primarily based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net revenues —
Well Intervention	$	113,076		$	59,919		$	187,697		$	105,975
Robotics	33,061			38,914			55,029			70,908
Production Facilities	15,210			18,957			31,585			37,439
Intercompany elimination	(11,018		)	(10,523		)	(19,454		)	(16,016		)
Total	$	150,329		$	107,267		$	254,857		$	198,306

Income (loss) from operations —
Well Intervention	$	19,032		$	(538	)	$	20,450		$	(17,226	)
Robotics	(11,642		)	(8,823		)	(27,948		)	(21,573		)
Production Facilities	6,140			9,730			13,064			16,913
Corporate and other	(8,701		)	(9,827		)	(18,663		)	(18,496		)
Intercompany elimination	221			163			442			331
Total	$	5,050		$	(9,295	)	$	(12,655	)	$	(40,051	)

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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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016

Well Intervention	$	2,895	$	2,201	$	4,268	$	2,842
Robotics	8,123		8,322		15,186		13,174
Total	$	11,018	$	10,523	$	19,454	$	16,016

Segment assets are comprised of all assets attributable to each reportable segment. Corporate and other includes all assets not directly identifiable with our business segments, most notably the majority of our cash and cash equivalents. The following table reflects total assets by reportable segment (in thousands):



	June 30, 2017		December 31, 2016

Well Intervention	$	1,719,971	$	1,596,517
Robotics	168,734		186,901
Production Facilities	151,298		158,192
Corporate and other	321,559		305,331
Total	$	2,361,562	$	2,246,941

Note 12 — Commitments and Contingencies and Other Matters

Commitments

We have charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. In February 2016, we amended the charter agreements to reduce the charter rates and, in connection with those reductions, to extend the terms to October 2019 for the Grand Canyon, to April 2021 for the Grand Canyon II and to May 2023 for the Grand Canyon III. We also have a charter agreement for the Deep Cygnus that expires in March 2018.

In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000 for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being 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 contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% is to be paid upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% is to be paid upon the delivery of the vessel, which at our option can be deferred until December 30, 2018. We agreed to pay the shipyard its incremental costs in connection with the contract amendments to extend the scheduled delivery of the Q7000 and to defer certain payment obligations. Incremental costs are capitalized as they are incurred during the construction of the vessel. At June 30, 2017, our total investment in the Q7000 was $207.1 million, including $138.4 million of installment payments to the shipyard.

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In February 2014, we entered into agreements with Petróleo Brasileiro S.A. (“Petrobras”) to provide well intervention services offshore Brazil, and in connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS (“Siem”) for two newbuild monohull vessels, the Siem Helix 1 and the Siem Helix 2. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates with options to extend. The initial term of the agreements with Petrobras is for four years with Petrobras’s options to extend. As part of Petrobras’s efforts to reduce its costs structure with many of its suppliers, we and Petrobras began discussions in mid-2015 with respect to potentially amending our contracts in a manner that would address Petrobras’s objectives and was acceptable to us as well. Those negotiations were finalized in early June 2016 such that the contracts for the Siem Helix 1, originally scheduled to begin no later than July 22, 2016, were amended to commence between July 22, 2016 and October 21, 2016, with the day rate reduced to a mutually acceptable level, and the contracts for the Siem Helix 2, originally scheduled to begin no later than January 21, 2017, were amended to commence between October 1, 2017 and December 31, 2017, with no change in the day rate.

The Siem Helix 1 vessel was delivered to us and the charter term began on June 14, 2016 and, after integration of our topside equipment onboard, transited to Brazil. After a prolonged inspection and acceptance process, the vessel was accepted by Petrobras and commenced operations on April 14, 2017. We have agreed with Petrobras to commence operations at reduced day rates as we work through certain items identified in the vessel acceptance process. The Siem Helix 2 was delivered to us and the charter term began on February 10, 2017. We are currently integrating and commissioning our topside equipment onboard the vessel, and we anticipate that the vessel will commence operations for Petrobras late in the fourth quarter of 2017. At June 30, 2017, our total investment in the topside equipment for the two vessels was $275.0 million.

Contingencies and Claims

We believe that there are currently no contingencies that would have a material adverse effect on our financial position, results of operations or cash flows.

Litigation

We are involved in various other 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 and employment-related 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 approaches as follows:


(a)	Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.


(b)	Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).


(c)	Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

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Our financial instruments include cash and cash equivalents, receivables, accounts payable, long-term debt and various derivative instruments. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments. The net carrying amount of our long-term note receivable also approximates its fair value. 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 June 30, 2017 Using
	Level 1		Level 2 ⁽¹⁾		Level 3		Total		Valuation Approach
Assets:
Interest rate swaps	$	—	$	363	$	—	$	363	(c)

Liabilities:
Foreign exchange contracts	—		26,887		—		26,887		(c)
Interest rate swaps	—		181		—		181		(c)
Total liability	$	—	$	26,705	$	—	$	26,705



	Fair Value Measurements at December 31, 2016 Using
	Level 1		Level 2 ⁽¹⁾		Level 3		Total		Valuation Approach
Assets:
Interest rate swaps	$	—	$	451	$	—	$	451	(c)

Liabilities:
Foreign exchange contracts	—		38,170		—		38,170		(c)
Interest rate swaps	—		751		—		751		(c)
Total net liability	$	—	$	38,470	$	—	$	38,470

(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.

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The carrying values and estimated fair values of our long-term debt are as follows (in thousands):



	June 30, 2017				December 31, 2016
	Carrying Value ⁽¹⁾		Fair Value ⁽²⁾		Carrying Value ⁽¹⁾		Fair Value ⁽²⁾

Term Loan (previously scheduled to mature June 2018)	$	—	$	—	$	192,258	$	192,258
Nordea Q5000 Loan (matures April 2020)	178,571		176,228		196,429		192,746
Term Loan (matures June 2020)	100,000		100,000		—		—
MARAD Debt (matures February 2027)	80,149		90,419		83,222		92,049
2022 Notes (mature May 2022)	125,000		116,719		125,000		130,156
2032 Notes (mature March 2032)	60,115		59,814		60,115		59,965
Total debt	$	543,835	$	543,180	$	657,024	$	667,174


(1)	Carrying value includes current maturities and excludes the related unamortized debt discount and debt issuance costs. See Note 6 for additional disclosures on our long-term debt.

(2)

The estimated fair value of the 2022 Notes and the 2032 Notes was determined using Level 1 inputs under the market approach. The fair value of the prior term loan previously scheduled to mature June 2018, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.

Note 14 — Derivative Instruments and Hedging Activities

Our business is exposed to market risks associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we enter into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative instruments are reflected in the accompanying condensed consolidated balance sheets at fair value.

We engage solely in cash flow hedges. 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 derivative instruments that are designated as cash flow hedges are deferred to the extent the hedges are effective. These 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 instrument that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.

For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 18 to our 2016 Form 10-K.

Interest Rate Risk

From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. In June 2015 we entered into 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 cash flow 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.

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Foreign Currency Exchange Rate Risk

Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. We enter into foreign currency exchange contracts from time to time to stabilize expected cash outflows related to our vessel charters that are denominated in foreign currencies.

In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 our 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 associated with 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. In December 2015, we de-designated the foreign currency exchange contracts associated with the charter payment obligations for the Grand Canyon II and Grand Canyon III vessels that no longer qualified for cash flow hedge accounting treatment and we re-designated the hedging relationship between a portion of these contracts and our forecasted Grand Canyon II and Grand Canyon III charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring. Unrealized losses associated with the effective portion of our foreign currency exchange contracts that qualify for hedge accounting treatment are included in our Accumulated OCI (net of tax). Reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations are changes in unrealized losses associated with the foreign currency exchange contracts that are no longer designated as cash flow hedges. Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations. There were no gains or losses associated with hedge ineffectiveness for the three- and six-month periods ended June 30, 2017. For the three- and six-month periods ended June 30, 2016, we recorded unrealized gains of $0.5 million and $0.1 million, respectively, related to the Grand Canyon and Grand Canyon III hedge ineffectiveness.

Quantitative Disclosures Relating to Derivative Instruments

The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments (in thousands):



	June 30, 2017			December 31, 2016
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivative Instruments:
Interest rate swaps	Other assets, net	$	363	Other assets, net	$	451
		$	363		$	451

Liability Derivative Instruments:
Foreign exchange contracts	Accrued liabilities	$	9,710	Accrued liabilities	$	14,056
Interest rate swaps	Accrued liabilities	181		Accrued liabilities	751
Foreign exchange contracts	Other non-current liabilities	8,928		Other non-current liabilities	13,383
		$	18,819		$	28,190

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The following table presents the balance sheet location and fair value of our derivative instruments that were not designated as hedging instruments (in thousands):



	June 30, 2017			December 31, 2016
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivative Instruments:
Foreign exchange contracts	Accrued liabilities	$	3,368	Accrued liabilities	$	3,923
Foreign exchange contracts	Other non-current liabilities	4,881		Other non-current liabilities	6,808
		$	8,249		$	10,731

The following tables present the impact that derivative instruments designated as hedging instruments had on our Accumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of June 30, 2017, $6.4 million of losses in Accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.



	Gain (Loss) Recognized in OCI on Derivative Instruments, Net of Tax (Effective Portion)
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017		2016

Foreign exchange contracts	$	3,191		$	674		$	5,721	$	6,496
Interest rate swaps	(15		)	(200		)	298		(1,523		)
	$	3,176		$	474		$	6,019	$	4,973



	Location of Loss Reclassified from Accumulated OCI into Earnings	Loss Reclassified from Accumulated OCI into Earnings (Effective Portion)
		Three Months Ended June 30,						Six Months Ended June 30,
		2017			2016			2017			2016

Foreign exchange contracts	Cost of sales	$	(3,771	)	$	(2,507	)	$	(6,992	)	$	(5,370	)
Interest rate swaps	Net interest expense	(178		)	(547		)	(447		)	(1,124		)
		$	(3,949	)	$	(3,054	)	$	(7,439	)	$	(6,494	)

The following table presents the impact that derivative instruments not designated as hedging instruments had on our condensed consolidated statements of operations (in thousands):



	Location of Gain Recognized in Earnings on Derivative Instruments	Gain Recognized in Earnings on Derivative Instruments
		Three Months Ended June 30,					Six Months Ended June 30,
		2017		2016			2017		2016

Foreign exchange contracts	Other income (expense), net	$	429	$	(465	)	$	481	$	2,066
		$	429	$	(465	)	$	481	$	2,066

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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 and equipment integration of the Siem Helix 2 chartered vessel 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 our trade receivables and their collectability;


•	statements regarding anticipated developments, industry trends, performance or industry ranking;


•	statements regarding general economic or political conditions, whether international, national or in the regional and local 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 our forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include:


•	the impact of domestic and global economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;


•	the impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;


•	the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;


•	unexpected delays in the delivery or chartering or customer acceptance, and terms of acceptance, of new vessels for our well intervention and robotics fleet, including the Q7000 and the Siem Helix 2, which is to be used to perform contracted well intervention work offshore Brazil;


•	the ability to continue to work through the items identified in the Siem Helix 1 acceptance process and the timing thereof;


•	the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets, including the Q4000, the Q5000 and the Siem Helix 1;


•	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 effects of our indebtedness and our ability to reduce capital commitments;


•	the results of our continuing efforts to control costs and improve performance;


•	the success of our risk management activities;


•	the effects of competition;


•	the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations;

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•	the impact of current and future laws and governmental regulations, including tax and accounting developments;


•	the impact of the vote in the U.K. to exit the European Union (the “EU”), known as Brexit, on our business, operations and financial condition, which is unknown at this time;


•	the effect of adverse weather conditions and/or other risks associated with marine operations;


•	the effectiveness of our current and future hedging activities;


•	the potential impact of a loss of one or more key employees; and


•	the impact of general, market, industry or business conditions.

Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 1A. “Risk Factors” in our 2016 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. From time to time, we make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. Our well intervention fleet expanded following the delivery of the Siem Helix 2 chartered vessel in February 2017 and is expected to further expand following the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018. Chartering newer vessels with additional capabilities, including the Grand Canyon III chartered vessel that went into service for us in May 2017, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also benefit by our fixed fee agreement for the HP I servicing the Phoenix field for the field operator until at least June 1, 2023.

In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreement and related agreements for the parties’ strategic alliance to design, develop, manufacture, promote, market and sell on a global basis integrated equipment and services for subsea well intervention. The alliance is expected to leverage the parties’ capabilities to provide a unique, fully integrated offering to customers, combining marine support with well access and control technologies. In April 2015, we and OneSubsea agreed to jointly develop and ordered a 15,000 working p.s.i. IRS, which is expected to be completed in the second half of 2017 for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At June 30, 2017, our total investment in the IRS was $11.0 million. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $12 million (approximately $6 million for our 50% interest). The ROAM is expected to be available to customers in the fourth quarter of 2017.

Economic Outlook and Industry Influences

Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to spend on operational activities as well as capital projects. The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including:


•	worldwide economic activity, 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;


•	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 level of excess production capacity;

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•	the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;


•	the sale and expiration dates of offshore leases in the United States and overseas;


•	technological advances affecting energy exploration, production, transportation and consumption;


•	potential acceleration of the development of alternative fuels;


•	shifts in end-customer preferences toward fuel efficiency and the use of natural gas;


•	weather conditions and natural disasters;


•	environmental and other governmental regulations; and


•	domestic and international tax laws, regulations and policies.

The significant decline in oil prices since mid-year 2014 and the resulting difficult industry environment has had a significant adverse impact on investments in oil and gas exploration and production. Many oil and gas companies have terminated or not renewed contracts for many of their contracted rigs and have drastically cut investments in exploration and production as well as other operational activities. We expect these challenging industry conditions to continue through 2017 and beyond if oil and gas prices fail to increase to a level conducive to increased activity levels. Increased competition for limited offshore oil and gas 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. Increased competition is also expected to affect utilization of our assets. In addition, the current volatile and uncertain macroeconomic conditions in some countries around the world, such as Brazil and the U.K. following Brexit, may have a direct and/or indirect impact on our existing contracts and contracting opportunities and may introduce further currency volatility into our operations and/or financial results. The U.K. started Brexit negotiations with the EU in June 2017. The U.K. will cease to be a member of the EU on March 29, 2019, unless otherwise extended. We continue to monitor the impact of Brexit and any exit agreements as they are negotiated, but the impact from Brexit on our business and operations will depend on the outcome of tariff, tax treaties, trade, regulatory and other negotiations, as well as the impact of Brexit on macroeconomic growth and currency volatility, which are uncertain at this time.

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 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.

Our current strategy is to be positioned for future recovery while coping with a sustained period of weak activity. This strategy is based on the following factors: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as plug and abandonment costs are considered; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling as well as extending and enhancing the commercial life of subsea wells; and (3) in past cycles, well intervention and workover have been some of the first activities to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells.

Helix Fast Response System

We developed the HFRS in 2011 as a culmination of our experience as a responder in the 2010 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. The HFRS provides industry participants with a response resource to be named in permit applications to federal and state agencies in exchange for a retainer fee. The HFRS agreements specify the day rates to be charged should the HFRS be deployed in connection with a well control incident. The agreement providing access to the HFRS was amended effective February 1, 2017 to reduce the retainer fee and to extend the term of the agreement by one year to March 31, 2019.

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RESULTS OF OPERATIONS

We have three reportable business segments: Well Intervention, Robotics and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our consolidated results of operations.

We seek to provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We operate primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and have recently expanded our operations into Brazil with the commencement of operations of the Siem Helix 1. In addition to servicing the oil and gas market, our Robotics operations are contracted for the development of renewable energy projects (wind farms). As of June 30, 2017, our consolidated backlog that is supported by written agreements or contracts totaled $1.8 billion, of which $260.5 million is expected to be performed over the remainder of 2017. The substantial majority of our backlog is associated with our Well Intervention business segment. As of June 30, 2017, our well intervention backlog was $1.4 billion, including $190.9 million expected to be performed over the remainder of 2017. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 1 and Siem Helix 2 chartered vessels, and our fixed fee agreement for the HP I represent approximately 84% of our total backlog as of June 30, 2017. 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, and reduced rates, fines and penalties may be imposed by our customers.

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. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with U.S. GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these non-GAAP measures.

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 U.S. GAAP. We use EBITDA to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our 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 earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense. To arrive at our measure of Adjusted EBITDA, we exclude gain or loss on disposition of assets. In addition, we include realized losses from the cash settlements of our ineffective foreign currency exchange contracts, which are excluded from EBITDA as a component of net other income or expense. In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016

Net loss	$	(6,403	)	$	(10,671	)	$	(22,818	)	$	(38,494	)
Adjustments:
Income tax provision (benefit)	5,023			(4,219		)	422			(13,507		)
Net interest expense	6,639			7,480			11,865			18,164
(Gain) loss on early extinguishment of long-term debt	397			(302		)	397			(302		)
Other (income) expense, net	(467		)	(1,308		)	68			(3,188		)
Depreciation and amortization	25,519			25,674			56,377			57,239
EBITDA	30,708			16,654			46,311			19,912
Adjustments:
Loss on disposition of assets, net	—			—			39			—
Realized losses from cash settlements of ineffective foreign currency exchange contracts	(981		)	(1,722		)	(2,001		)	(3,958		)
Adjusted EBITDA	$	29,727		$	14,932		$	44,349		$	15,954

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Comparison of Three Months Ended June 30, 2017 and 2016

The following table details various financial and operational highlights for the periods presented (dollars in thousands):



	Three Months Ended June 30,						Increase/ (Decrease)
	2017			2016			Increase/ (Decrease)
Net revenues —
Well Intervention	$	113,076		$	59,919		$	53,157
Robotics	33,061			38,914			(5,853		)
Production Facilities	15,210			18,957			(3,747		)
Intercompany elimination	(11,018		)	(10,523		)	(495		)
	$	150,329		$	107,267		$	43,062

Gross profit (loss) —
Well Intervention	$	22,004		$	2,702		$	19,302
Robotics	(9,634		)	(6,613		)	(3,021		)
Production Facilities	6,206			9,823			(3,617		)
Corporate and other	(430		)	(417		)	(13		)
Intercompany elimination	221			163			58
	$	18,367		$	5,658		$	12,709

Gross margin —
Well Intervention	19%			5%
Robotics	(29)%			(17)%
Production Facilities	41%			52%
Total company	12%			5%

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	5/90%			5/54%
Robotics assets	60/42%			60/48%
Chartered robotics vessels	4/57%			4/61%


(1)	Represents number of vessels or robotics 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.


(2)	Represents average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period.



	Three Months Ended June 30,				Increase/ (Decrease)
	2017		2016		Increase/ (Decrease)

Well Intervention	$	2,895	$	2,201	$	694
Robotics	8,123		8,322		(199		)
	$	11,018	$	10,523	$	495

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Net Revenues. Our total net revenues increased by 40% for the three-month period ended June 30, 2017 as compared to the same period in 2016. Increased revenues for the three-month period in 2017 reflected higher revenues in our Well Intervention segment, offset in part by revenue decreases in our Robotics and Production Facilities segments.

Our Well Intervention revenues increased by 89% for the three-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting higher revenues generated from all of the well intervention vessels except for the Q4000. In the North Sea, the Well Enhancer was fully utilized during the second quarter of 2017 while the vessel was 75% utilized during the same period in 2016. The Seawell was fully utilized during the second quarter of 2017 whereas it was utilized for 21 days after undergoing major life extension capital updates during the same period in 2016. In the Gulf of Mexico, the Q5000 was 91% utilized during the second quarter of 2017 as compared to being fully utilized during the 42 days after it went on contracted rates for BP in May 2016. The Q4000 was 63% utilized during the second quarter of 2017 as compared to being fully utilized during the same period in 2016 as the vessel was out of service for 34 days undergoing its scheduled regulatory dry dock. The Siem Helix 1 was 95% utilized after it commenced services for Petrobras in mid-April 2017. We commenced work at reduced day rates as we work through certain items identified in the vessel acceptance process. We continue to work through those items and currently expect to complete the work by the end of the third quarter.

Robotics revenues decreased by 15% for the three-month period ended June 30, 2017 as compared to the same period in 2016. The decrease primarily reflected the reduction and lower utilization of our Robotics assets, including our chartered vessels, and accepting work at reduced rates. Some of our ROV units have been affected by other industry participants laying up vessels or canceling work as a result of the oil and gas industry downturn. Utilization of our chartered ROV support vessels decreased primarily reflecting reduction in work opportunities as a result of continuous weak market demand for our services.

Our Production Facilities revenues decreased by 20% for the three-month period ended June 30, 2017 as compared to the same period in 2016, which reflected reduced retainer fees from the amended HFRS agreement that became effective February 1, 2017 and lower revenues from the fixed fee agreement with the Phoenix field operator for the HP I that commenced June 1, 2016.

Gross Profit (Loss). Our total gross profit increased by 225% for the three-month period ended June 30, 2017 as compared to the same period in 2016. The gross profit related to our Well Intervention segment increased by 714% for the three-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting higher revenues in our North Sea and U.S. Gulf of Mexico regions.

The gross profit associated with our Robotics segment decreased by 46% for the three-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting decreased utilization for our robotics assets, including our chartered vessels, and accepting work with lower profit margins.

The gross profit related to our Production Facilities segment decreased by 37% for the three-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting revenue decreases for the HFRS and the HP I.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by $1.6 million for the three-month period ended June 30, 2017 as compared to the same period in 2016. The decrease was primarily attributable to payroll related costs associated with our variable performance-based incentive compensation programs (Note 10).

Net Interest Expense. Our net interest expense decreased by $0.8 million for the three-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting increases in interest income and capitalized interest, offset in part by an increase in interest expense. Interest income totaled $0.9 million for the three-month period ended June 30, 2017 as compared to $0.4 million for the same period in 2016. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $4.1 million for the three-month period ended June 30, 2017 as compared to $2.5 million for the same period in 2016. Interest expense for the three-month period ended June 30, 2017 included a $1.6 million charge to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments in our revolving credit facility were reduced (Note 6).

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Gain (Loss) on Early Extinguishment of Long-Term Debt. The $0.4 million loss for the three-month period ended June 30, 2017 was associated with the write-off of the unamortized debt issuance costs related to the lenders exiting from the term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement (Note 6). The $0.3 million gain for the three-month period ended June 30, 2016 was associated with the repurchase in June 2016 of $7.3 million in aggregate principal amount of our 2032 Notes.

Other Income, Net. Other income, net decreased by $0.8 million for the three-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting foreign currency transaction gains totaling $1.2 million for the three-month period ended June 30, 2016, offset in part by net gains for the three-month period ended June 30, 2017 of $0.4 million associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 14).

Income Tax Provision (Benefit). Income tax provision was $5.0 million for the three-month period ended June 30, 2017 as compared to income tax benefit of $4.2 million for the same period in 2016. The variance primarily reflected a decrease in pretax loss in the current year period as well as a tax charge attributable to a change in tax position related to our foreign taxes. The effective tax rate was (364.0)% for the three-month period ended June 30, 2017 as compared to 28.3% for the same period in 2016. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and the change in tax position related to our foreign taxes (Note 7).

Comparison of Six Months Ended June 30, 2017 and 2016

The following table details various financial and operational highlights for the periods presented (dollars in thousands):



	Six Months Ended June 30,						Increase/ (Decrease)
	2017			2016			Increase/ (Decrease)
Net revenues —
Well Intervention	$	187,697		$	105,975		$	81,722
Robotics	55,029			70,908			(15,879		)
Production Facilities	31,585			37,439			(5,854		)
Intercompany elimination	(19,454		)	(16,016		)	(3,438		)
	$	254,857		$	198,306		$	56,551

Gross profit (loss) —
Well Intervention	$	27,115		$	(10,979	)	$	38,094
Robotics	(22,385		)	(16,961		)	(5,424		)
Production Facilities	13,251			17,221			(3,970		)
Corporate and other	(881		)	(884		)	3
Intercompany elimination	442			331			111
	$	17,542		$	(11,272	)	$	28,814

Gross margin —
Well Intervention	14%			(10)%
Robotics	(41)%			(24)%
Production Facilities	42%			46%
Total company	7%			(6)%

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	5/74%			5/38%
Robotics assets	60/39%			60/44%
Chartered robotics vessels	4/49%			4/57%

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(1)	Represents number of vessels or robotics 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.


(2)	Represents average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period.



	Six Months Ended June 30,				Increase/ (Decrease)
	2017		2016		Increase/ (Decrease)

Well Intervention	$	4,268	$	2,842	$	1,426
Robotics	15,186		13,174		2,012
	$	19,454	$	16,016	$	3,438

Net Revenues. Our total net revenues increased by 29% for the six-month period ended June 30, 2017 as compared to the same period in 2016. Increased revenues for the six-month period in 2017 reflected higher revenues in our Well Intervention segment, offset in part by revenue decreases in our Robotics and Production Facilities segments.

Our Well Intervention revenues increased by 77% for the six-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting higher revenues generated from all of the well intervention vessels except for the Q4000. In the North Sea, the Well Enhancer was 80% utilized during the first half of 2017 while the vessel was 44% utilized during the same period in 2016. The Seawell was 77% utilized during the first half of 2017 whereas it was utilized for 21 days during the same period in 2016. In the Gulf of Mexico, the Q5000 was 94% utilized during the first half of 2017 as compared to being fully utilized during the 42 days after it went on contracted rates for BP in May 2016. The Q4000 was 73% utilized during the first half of 2017 as compared to being fully utilized during the same period in 2016 as the vessel was out of service for 49 days undergoing its scheduled regulatory dry dock. The Siem Helix 1 was 95% utilized after it commenced services for Petrobras in mid-April 2017. We commenced work at reduced day rates as we work through certain items identified in the vessel acceptance process. We continue to work through those items and currently expect to complete the work by the end of the third quarter.

Robotics revenues decreased by 22% for the six-month period ended June 30, 2017 as compared to the same period in 2016. The decrease primarily reflected the reduction and lower utilization of our Robotics assets, including our chartered vessels, and accepting work at reduced rates. Some of our ROV units have been affected by other industry participants laying up vessels or canceling work as a result of the oil and gas industry downturn. Utilization of our chartered ROV support vessels decreased primarily reflecting reduction in work opportunities as a result of continuous weak market demand for our services.

Our Production Facilities revenues decreased by 16% for the six-month period ended June 30, 2017 as compared to the same period in 2016, which reflected reduced retainer fees from the amended HFRS agreement that became effective February 1, 2017 and lower revenues from the fixed fee agreement with the Phoenix field operator for the HP I that commenced June 1, 2016.

Gross Profit (Loss). Our total gross profit increased by 256% for the six-month period ended June 30, 2017 as compared to the same period in 2016. The gross profit related to our Well Intervention segment increased by 347% for the six-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting higher revenues in our North Sea and U.S. Gulf of Mexico regions.

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The gross profit associated with our Robotics segment decreased by 32% for the six-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting decreased utilization for our robotics assets, including our chartered vessels, and accepting work with lower profit margins.

The gross profit related to our Production Facilities segment decreased by 23% for the six-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting revenue decreases for the HFRS and the HP I.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses increased by $1.4 million for the six-month period ended June 30, 2017 as compared to the same period in 2016. The increase was primarily attributable to a $1.2 million charge during the first quarter of 2017 associated with the provision for uncertain collection of a portion of our existing trade receivables related to our Robotics segment.

Net Interest Expense. Our net interest expense decreased by $6.3 million for the six-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting increases in interest income and capitalized interest and a decrease in interest expense. Interest income totaled $1.3 million for the six-month period ended June 30, 2017 as compared to $0.9 million for the same period in 2016. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $8.7 million for the six-month period ended June 30, 2017 as compared to $4.4 million for the same period in 2016. Interest expense for the six-month periods ended June 30, 2017 and 2016 included charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments in our revolving credit facility were reduced (Note 6).

Gain (Loss) on Early Extinguishment of Long-Term Debt. The $0.4 million loss for the six-month period ended June 30, 2017 was associated with the write-off of the unamortized debt issuance costs related to the lenders exiting from the term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement (Note 6). The $0.3 million gain for the six-month period ended June 30, 2016 was associated with the repurchase in June 2016 of $7.3 million in aggregate principal amount of our 2032 Notes.

Other Income (Expense), Net. We reported other expense, net, of $0.1 million for the six-month period ended June 30, 2017 as compared to other income, net, of $3.2 million for the same period in 2016. Net other income (expense) for the six-month periods ended June 30, 2017 and 2016 included foreign currency transaction gains (losses) of $(0.6) million and $1.0 million, respectively. Also included in the comparable year-over-year periods were net gains of $0.5 million and $2.2 million, respectively, associated with our foreign currency exchange contracts primarily reflecting gains related to the contracts that were not designated as cash flow hedges (Note 14).

Income Tax Provision (Benefit). Income tax provision was $0.4 million for the six-month period ended June 30, 2017 as compared to income tax benefit of $13.5 million for the same period in 2016. The variance primarily reflected a decrease in pretax loss in the current year period as well as a tax charge attributable to a change in tax position related to our foreign taxes. The effective tax rate was (1.9)% for the six-month period ended June 30, 2017 as compared to 26.0% for the same period in 2016. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and the change in tax position related to our foreign taxes (Note 7).

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LIQUIDITY AND CAPITAL RESOURCES

Overview

The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands):



	June 30, 2017		December 31, 2016

Net working capital	$	300,583	$	336,387
Long-term debt ⁽¹⁾	$	408,250	$	558,396
Liquidity ⁽²⁾	$	390,435	$	375,504


(1)	Long-term debt does not include the current maturities portion of our long-term debt as that amount is included in net working capital. It is also net of unamortized debt discount and debt issuance costs. See Note 6 for information relating to our existing debt.

(2)

Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under our Revolving Credit Facility, which capacity is reduced by letters of credit drawn against the facility. Our liquidity at June 30, 2017 consisted of cash and cash equivalents of $390.4 million (including $100 million of minimum cash balance required by our Credit Agreement). Our liquidity at December 31, 2016 included cash and cash equivalents of $356.6 million and $18.9 million of available borrowing capacity under our Revolving Credit Facility.

The carrying amount of our long-term debt, including current maturities, net of unamortized debt discount and debt issuance costs, is as follows (in thousands):



	June 30, 2017		December 31, 2016

Term Loan (previously scheduled to mature June 2018)	$	—	$	190,867
Nordea Q5000 Loan (matures April 2020)	176,404		193,879
Term Loan (matures June 2020)	98,033		—
MARAD Debt (matures February 2027)	75,392		78,221
2022 Notes (mature May 2022) ⁽¹⁾	107,222		105,697
2032 Notes (mature March 2032) ⁽²⁾	58,404		57,303
Total debt	$	515,455	$	625,967


(1)	The 2022 Notes will increase to their face amount through accretion of non-cash interest charges through May 1, 2022.


(2)	The 2032 Notes will increase to their face amount through accretion of non-cash interest charges through March 15, 2018, which is the first date on which the holders of the notes may require us to repurchase the notes.

The following table provides summary data from our condensed consolidated statements of cash flows (in thousands):



	Six Months Ended June 30,
	2017			2016
Cash provided by (used in):
Operating activities	$	15,601		$	24,889
Investing activities	$	(84,396	)	$	(20,476	)
Financing activities	$	101,623		$	(4,309	)

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Our current requirements for cash primarily reflect the need to fund capital spending for our current lines of business and to service our debt. Historically, we have funded our capital program with cash flows from operations, borrowings under credit facilities, and project financing, along with other debt and equity alternatives.

As a further response to the industry-wide spending reductions, we remain even more focused on maintaining a strong balance sheet and adequate liquidity. Over the near term, we may seek to reduce, defer or cancel certain planned capital expenditures. We believe that our cash on hand and internally generated cash flows will be sufficient to fund our operations over at least the next 12 months.

In accordance with our Credit Agreement, the 2022 Notes, 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 various leverage ratios, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. Our Credit Agreement also contains provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by us. The Credit Agreement does permit us to incur certain unsecured indebtedness, and also provides for our subsidiaries to incur project financing indebtedness (such as our MARAD Debt and our Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. Our Credit Agreement also permits our Unrestricted Subsidiaries to incur indebtedness provided that it is not guaranteed by us or any of our Restricted Subsidiaries (as defined in our Credit Agreement). As of June 30, 2017 and December 31, 2016, we were in compliance with all of the covenants in our long-term debt agreements.

A prolonged period of weak industry activity may make it difficult to comply with our covenants and other restrictions in agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to access the full available commitment under our Revolving Credit Facility may be impacted. We currently have no plans or forecasted requirements to borrow under our Revolving Credit Facility other than for issuances of letters of credit. Our ability to comply with these covenants and other restrictions is affected by economic conditions and other events beyond our control. If we fail to comply with these covenants and other restrictions, that failure could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral.

Subject to the terms and restrictions of the Credit Agreement, we may borrow and/or obtain letters of credit up to $25 million under our Revolving Credit Facility. See Note 6 for additional information relating to our long-term debt, including more information regarding our Credit Agreement, including covenants and collateral.

The 2022 Notes and the 2032 Notes can be converted into our common stock prior to their stated maturity upon certain triggering events specified in the applicable Indenture governing the notes. The holders of the remaining 2032 Notes may require us to repurchase these notes in March 2018. Accordingly, the 2032 Notes are classified as current liabilities on our consolidated balance sheet at June 30, 2017. No conversion triggers were met during the six-month periods ended June 30, 2017 and 2016.

Operating Cash Flows

Total cash flows from operating activities decreased by $9.3 million for the six-month period ended June 30, 2017 as compared to the same period in 2016. This decrease was primarily attributable to changes in our working capital due to increased activity levels. In particular, our accounts receivable increased significantly as a result of revenue increases in the comparable year-over-year periods.

Investing Activities

Capital expenditures consist principally of the acquisition, construction, upgrade, modification and refurbishment of long-lived property and equipment such as dynamically positioned vessels, topside equipment and subsea systems. Significant sources (uses) of cash associated with investing activities are as follows (in thousands):

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	Six Months Ended June 30,
	2017			2016
Capital expenditures:
Well Intervention	$	(94,048	)	$	(57,281	)
Robotics	(262		)	(413		)
Production Facilities	—			(74		)
Other	(86		)	205
Distribution from equity investment	—			1,200
Proceeds from sale of equity investment ⁽¹⁾	—			25,000
Proceeds from sale of assets ⁽²⁾	10,000			10,887
Net cash used in investing activities	$	(84,396	)	$	(20,476	)


(1)	Amount in 2016 reflected cash received from the sale of our former ownership interest in Deepwater Gateway (Note 5).


(2)	Amount in 2017 reflected cash received from the sale of our Ingleside spoolbase (Note 3). Amount in 2016 reflected cash received from the sale of our office and warehouse property located in Aberdeen, Scotland.

Capital expenditures associated with our business primarily have included payments associated with the construction of our Q7000 vessel (see below) and the investment in the topside well intervention equipment for the Siem Helix 1 and Siem Helix 2 vessels chartered to perform our agreements with Petrobras (see below).

In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000 for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being 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 contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% is to be paid upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% is to be paid upon the delivery of the vessel, which at our option can be deferred until December 30, 2018. We agreed to pay the shipyard its incremental costs in connection with the contract amendments to extend the scheduled delivery of the Q7000 and to defer certain payment obligations. At June 30, 2017, our total investment in the Q7000 was $207.1 million, including $138.4 million of installment payments to the shipyard. We plan to incur approximately $83 million of costs related to the construction of the Q7000 over the remainder of 2017.

In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with Petrobras’s options to extend. In connection with the Petrobras agreements, we entered into charter agreements with Siem for two newbuild monohull vessels, the Siem Helix 1 and the Siem Helix 2. The Siem Helix 1 commenced its operations for Petrobras in mid-April 2017. The Siem Helix 2 is expected to be in service for Petrobras late in the fourth quarter of 2017. We have invested $275.0 million as of June 30, 2017 and plan to invest approximately $31 million in the topside equipment over the remainder of 2017.

Financing Activities

Cash flows from financing activities consist primarily of proceeds from debt and equity financing activities and repayments of our long-term debt. Total cash flows from financing activities increased by $105.9 million for the six-month period ended June 30, 2017 as compared to the same period in 2016 primarily reflecting net proceeds of approximately $220 million we received from our underwritten public equity offering in January 2017 (Note 8) and the $100 million proceeds from our Term Loan borrowings in June 2017, offset in part by early repayment of the approximately $180 million term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement (Note 6).

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Outlook

We anticipate that our capital expenditures and deferred dry dock costs for 2017 will approximate $235 million. We believe that our cash on hand and internally generated cash flows will provide the capital necessary to continue funding our 2017 capital spending. Our estimate of future capital expenditures may change based on various factors. We may seek to reduce the level of our planned capital expenditures given a prolonged industry downturn.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of June 30, 2017 and the scheduled years in which the obligations are contractually due (in thousands):



	Total ⁽¹⁾		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years

Term Loan	$	100,000	$	5,000	$	95,000	$	—	$	—
Nordea Q5000 Loan	178,571		35,715		142,856		—		—
MARAD Debt	80,149		6,375		13,720		15,124		44,930
2022 Notes ⁽²⁾	125,000		—		—		—		125,000
2032 Notes ⁽³⁾	60,115		60,115		—		—		—
Interest related to debt ⁽⁴⁾	83,989		24,435		39,346		14,805		5,403
Property and equipment ⁽⁵⁾	262,539		109,186		153,353		—		—
Operating leases ⁽⁶⁾	734,801		150,164		254,291		209,868		120,478
Total cash obligations	$	1,625,164	$	390,990	$	698,566	$	239,797	$	295,811


(1)	Excludes unsecured letters of credit outstanding at June 30, 2017 totaling $3.0 million. These letters of credit support various obligations, such as contractual obligations, customs duties, contract bidding and insurance activities.

(2)

Notes mature May 2022. The 2022 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 130% of their issuance price on that 30th trading day (i.e., $18.06 per share). At June 30, 2017, the conversion trigger was not met. See Note 6 for additional information.

(3)

Notes mature March 2032. The 2032 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 130% of their issuance price on that 30th trading day (i.e., $32.53 per share). At June 30, 2017, the conversion trigger was not met. The first date that the holders of these notes may require us to repurchase the notes is March 15, 2018. See Note 6 for additional information.


(4)	Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at June 30, 2017 for variable rate debt.


(5)	Primarily reflects costs associated with our Q7000 semi-submersible well intervention vessel currently under construction and the topside equipment for the Siem Helix 2 chartered vessel (Note 12).

(6)

Operating leases include vessel charters and facility leases. At June 30, 2017, our vessel charter commitments totaled approximately $692.3 million, including the Grand Canyon III that went into service for us in May 2017, the Siem Helix 1, which commenced operations for Petrobras in mid-April 2017, and the Siem Helix 2, which is expected to be in service for Petrobras late in the fourth quarter of 2017.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. We prepare these financial statements and related footnotes in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. For additional information regarding our critical accounting policies and estimates, please read our “Critical Accounting Policies and Estimates” as disclosed in our 2016 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk in two areas: interest rates and foreign currency exchange rates.

Interest Rate Risk. As of June 30, 2017, $278.6 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may rise, thereby increasing our interest expense and related cash outlay. 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. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. The impact of interest rate risk is estimated using a hypothetical increase in interest rates by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional $1.2 million in interest expense for the six-month period ended June 30, 2017.

Foreign Currency Exchange Rate Risk. Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the United States, we generally pay a portion of our expenses in local currencies. In addition, a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the six-month period ended June 30, 2017, we recognized losses of $0.6 million related to foreign currency transactions in “Other income (expense), net” in our condensed consolidated statement of operations.

Our cash flows are subject to fluctuations resulting from changes in foreign currency exchange rates. Fluctuations in exchange rates are likely to impact our results of operations and cash flows. As a result, we entered into various foreign currency exchange contracts to stabilize expected cash outflows related to certain vessel charters denominated in Norwegian kroners. 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. In December 2015, we re-designated the hedging relationship between a portion of our foreign currency exchange contracts and our forecasted Grand Canyon II and Grand Canyon III charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring (Note 14). The foreign currency exchange contracts associated with the Grand Canyon charter payments and the re-designated contracts associated with the Grand Canyon II and Grand Canyon III charter payments currently qualify for cash flow hedge accounting treatment. There was no foreign currency hedge ineffectiveness for the six-month period ended June 30, 2017.

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Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of June 30, 2017. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2017 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

(b) Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 12 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities



Period	(a) Total number of shares purchased	(b) Average price paid per share		(c) Total number of shares purchased as part of publicly announced program	(d) Maximum number of shares that may yet be purchased under the program ⁽¹⁾
April 1 to April 30, 2017	—	$	—	—	3,039,891
May 1 to May 31, 2017	—	—		—	3,065,871
June 1 to June 30, 2017	—	—		—	3,065,871
	—	$	—	—


(1)	Under the terms of our stock repurchase program, the issuance of shares to members of our Board and to certain employees, including shares issued to our employees under the ESPP (Note 10), increases the amount of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 10 to our 2016 Form 10-K.

Item 6. Exhibits

The exhibits to this report are listed in the Exhibit Index on Page 45 hereof.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



			HELIX ENERGY SOLUTIONS GROUP, INC. (Registrant)
Date:	July 25, 2017	By:	/s/ Owen Kratz
			Owen Kratz President and Chief Executive Officer (Principal Executive Officer)

Date:	July 25, 2017	By:	/s/ Erik Staffeldt
			Erik Staffeldt Senior Vice President and Chief Financial Officer (Principal Financial Officer)

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INDEX TO EXHIBITS

HELIX ENERGY SOLUTIONS GROUP, INC.



Exhibits	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.1	2005 Amended and Restated Articles of Incorporation, as amended, of Helix.	Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739)
3.2	Second Amended and Restated By-Laws of Helix, as amended.	Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
4.1	Amended and Restated Credit Agreement dated June 30, 2017, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on June 30, 2017 (001-32936)
10.1 *	Employment Agreement by and between Helix Energy Solutions Group, Inc. and Erik Staffeldt dated June 5, 2017.	Exhibit 10.1 to the Current Report on Form 8-K filed on June 5, 2017 (001-32936)
31.1	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer.	Filed herewith
31.2	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Erik Staffeldt, Chief Financial Officer.	Filed herewith
32.1	Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.	Furnished herewith
101.INS	XBRL Instance Document.	Furnished herewith
101.SCH	XBRL Schema Document.	Furnished herewith
101.CAL	XBRL Calculation Linkbase Document.	Furnished herewith
101.PRE	XBRL Presentation Linkbase Document.	Furnished herewith
101.DEF	XBRL Definition Linkbase Document.	Furnished herewith
101.LAB	XBRL Label Linkbase Document.	Furnished herewith


*	Management contract or compensatory plan or arrangement