Edgar Filing: HELIX ENERGY SOLUTIONS GROUP INC

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Non-accelerated filer ¨

Smaller reporting company ¨

Emerging growth company ¨

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Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q



þ		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2018



¨		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 20, 2018, 148,113,398 shares of common stock were outstanding.

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION	PAGE

Item 1.	Financial Statements:

	Condensed Consolidated Balance Sheets – June 30, 2018 (Unaudited) and December 31, 2017	3

	Condensed Consolidated Statements of Operations (Unaudited) – Three months ended June 30, 2018 and 2017	4

	Condensed Consolidated Statements of Operations (Unaudited) – Six months ended June 30, 2018 and 2017	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) – Three and six months ended June 30, 2018 and 2017	6

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Six months ended June 30, 2018 and 2017	7

	Notes to Condensed Consolidated Financial Statements (Unaudited)	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	46

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 6.	Exhibits	47

	Signatures	48

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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, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	288,490		$	266,592
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $2,752	79,791			113,336
Unbilled and other	76,914			29,947
Other current assets	51,519			41,768
Total current assets	496,714			451,643
Property and equipment	2,722,845			2,695,772
Less accumulated depreciation	(938,538		)	(889,783		)
Property and equipment, net	1,784,307			1,805,989
Other assets, net	85,823			105,205
Total assets	$	2,366,844		$	2,362,837

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	69,624		$	81,299
Accrued liabilities	81,087			71,680
Income tax payable	1,477			2,799
Current maturities of long-term debt	46,151			109,861
Total current liabilities	198,339			265,639
Long-term debt	412,852			385,766
Deferred tax liabilities	106,560			103,349
Other non-current liabilities	46,699			40,690
Total liabilities	764,450			795,444

Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 148,107 and 147,740 shares issued, respectively	1,303,984			1,284,274
Retained earnings	369,659			352,906
Accumulated other comprehensive loss	(71,249		)	(69,787		)
Total shareholders’ equity	1,602,394			1,567,393
Total liabilities and shareholders’ equity	$	2,366,844		$	2,362,837

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,
	2018			2017

Net revenues	$	204,625		$	150,329
Cost of sales	161,728			131,962
Gross profit	42,897			18,367
Selling, general and administrative expenses	(18,125		)	(13,317		)
Income from operations	24,772			5,050
Equity in losses of investment	(135		)	(152		)
Net interest expense	(3,599		)	(6,639		)
Loss on extinguishment of long-term debt	(76		)	(397		)
Other income (expense), net	(3,441		)	467
Other income – oil and gas	561			291
Income (loss) before income taxes	18,082			(1,380		)
Income tax provision	298			5,023
Net income (loss)	$	17,784		$	(6,403	)

Earnings (loss) per share of common stock:
Basic	$	0.12		$	(0.04	)
Diluted	$	0.12		$	(0.04	)

Weighted average common shares outstanding:
Basic	146,683			145,940
Diluted	146,724			145,940

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,
	2018			2017

Net revenues	$	368,887		$	254,857
Cost of sales	313,007			237,315
Gross profit	55,880			17,542
Loss on disposition of assets, net	—			(39		)
Selling, general and administrative expenses	(32,224		)	(30,158		)
Income (loss) from operations	23,656			(12,655		)
Equity in losses of investment	(271		)	(304		)
Net interest expense	(7,495		)	(11,865		)
Loss on extinguishment of long-term debt	(1,181		)	(397		)
Other expense, net	(2,516		)	(68		)
Other income – oil and gas	3,416			2,893
Income (loss) before income taxes	15,609			(22,396		)
Income tax provision	385			422
Net income (loss)	$	15,224		$	(22,818	)

Earnings (loss) per share of common stock:
Basic	$	0.10		$	(0.16	)
Diluted	$	0.10		$	(0.16	)

Weighted average common shares outstanding:
Basic	146,668			144,599
Diluted	146,668			144,599

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,
	2018			2017

Net income (loss)	$	17,784		$	(6,403	)
Other comprehensive income (loss), net of tax:
Net unrealized gain (loss) on hedges arising during the period	(1,226		)	935
Reclassifications to net income (loss)	1,807			3,949
Income taxes on hedges	(126		)	(1,708		)
Net change in hedges, net of tax	455			3,176
Foreign currency translation gain (loss)	(7,547		)	6,284
Other comprehensive income (loss), net of tax	(7,092		)	9,460
Comprehensive income	$	10,692		$	3,057



	Six Months Ended June 30,
	2018			2017

Net income (loss)	$	15,224		$	(22,818	)
Other comprehensive income, net of tax:
Net unrealized gain on hedges arising during the period	927			1,844
Reclassifications to net income (loss)	3,434			7,439
Income taxes on hedges	(941		)	(3,264		)
Net change in hedges, net of tax	3,420			6,019
Unrealized loss on note receivable arising during the period	(629		)	—
Income taxes on note receivable	132			—
Unrealized loss on note receivable, net of tax	(497		)	—
Foreign currency translation gain (loss)	(2,856		)	9,392
Other comprehensive income, net of tax	67			15,411
Comprehensive income (loss)	$	15,291		$	(7,407	)

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,
	2018			2017
Cash flows from operating activities:
Net income (loss)	$	15,224		$	(22,818	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	55,659			56,377
Amortization of debt discount	2,659			2,303
Amortization of debt issuance costs	1,799			4,326
Share-based compensation	5,022			5,181
Deferred income taxes	(1,622		)	(80		)
Equity in losses of investment	271			304
Loss on disposition of assets, net	—			39
Loss on extinguishment of long-term debt	1,181			397
Unrealized gain on derivative contracts, net	(1,554		)	(2,482		)
Changes in operating assets and liabilities:
Accounts receivable, net	(14,319		)	(10,122		)
Other current assets	(9,662		)	(10,957		)
Income tax payable / receivable	(1,445		)	(1,729		)
Accounts payable and accrued liabilities	9,202			27,372
Other non-current, net	25,251			(32,510		)
Net cash provided by operating activities	87,666			15,601

Cash flows from investing activities:
Capital expenditures	(41,969		)	(94,396		)
Proceeds from sale of assets	—			10,000
Net cash used in investing activities	(41,969		)	(84,396		)

Cash flows from financing activities:
Issuance of Convertible Senior Notes due 2023	125,000			—
Repurchase of Convertible Senior Notes due 2032	(60,362		)	—
Proceeds from term loan	—			100,000
Repayment of term loan	(61,936		)	(192,258		)
Repayment of Nordea Q5000 Loan	(17,857		)	(17,858		)
Repayment of MARAD Debt	(3,226		)	(3,073		)
Debt issuance costs	(3,856		)	(3,665		)
Net proceeds from issuance of common stock	—			219,504
Payments related to tax withholding for share-based compensation	(1,058		)	(1,306		)
Proceeds from issuance of ESPP shares	332			279
Net cash provided by (used in) financing activities	(22,963		)	101,623

Effect of exchange rate changes on cash and cash equivalents	(836		)	960
Net increase in cash and cash equivalents	21,898			33,788
Cash and cash equivalents:
Balance, beginning of year	266,592			356,647
Balance, end of period	$	288,490		$	390,435

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 (“GAAP”).

The accompanying condensed consolidated financial statements have been prepared in conformity with GAAP in U.S. dollars and are consistent in all material respects with those applied in our 2017 Annual Report on Form 10-K (“2017 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, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. Our balance sheet as of December 31, 2017 included herein has been derived from the audited balance sheet as of December 31, 2017 included in our 2017 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 2017 Form 10-K.

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

New accounting standards adopted

In May 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASC Topic 606”). The FASB also issued several subsequent updates to promote more consistent interpretation and application of the principles outlined in the standard. ASC Topic 606 provides a five-step approach to account for revenue arising from contracts with customers in order for 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.

We adopted ASC Topic 606 effective January 1, 2018 using the modified retrospective method by applying the five-step model to all contracts that were not completed as of the date of adoption. For contracts that were modified before the date of adoption, we have considered the modification guidance within the new standard and determined that the revenues recognized prior to adoption for such modified contracts were not impacted. We did not record any cumulative effect adjustment to the opening balance of our retained earnings as of January 1, 2018 as the adoption of ASC 606 had an insignificant impact on our prior year earnings. On our consolidated balance sheet, contract assets that were previously presented as “Other accounts receivable” are now a component of “Other current assets.” The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. ASC Topic 606 requires additional disclosures with regard to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We do not expect the adoption of this guidance to have a material impact on the measurement or recognition of our revenues on an ongoing basis. The impact of ASC Topic 606 for the three- and six-month periods ended June 30, 2018 was as follows (in thousands):

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	June 30, 2018
	As Reported		Pro Forma Without Adoption of ASC 606		Effect of Change
Balance Sheet
Assets
Unbilled and other	$	76,914	$	76,814	$	100
Other current assets	51,519		50,792		727
Liabilities
Accrued liabilities	81,087		81,618		(531		)
Deferred tax liabilities	106,560		106,275		285
Equity
Retained earnings	369,659		368,586		1,073



	Three Months Ended June 30, 2018						Six Months Ended June 30, 2018
	As Reported		Pro Forma Without Adoption of ASC 606		Effect of Change		As Reported		Pro Forma Without Adoption of ASC 606		Effect of Change
Statement of Operations
Net revenues	$	204,625	$	203,267	$	1,358	$	368,887	$	367,529	$	1,358
Income from operations	24,772		23,414		1,358		23,656		22,298		1,358
Income before income taxes	18,082		16,724		1,358		15,609		14,251		1,358
Income tax provision	298		13		285		385		100		285
Net income	17,784		16,711		1,073		15,224		14,151		1,073

In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU allows a reclassification from accumulated other comprehensive income (loss) (“OCI”) to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”) that was enacted on December 22, 2017. We adopted this guidance as of January 1, 2018 by making the election to reclassify $1.5 million of net stranded tax benefits from accumulated OCI to retained earnings (Note 8). On an ongoing basis, we release the income tax effects of individual items in accumulated OCI as those items are sold or settled at the applicable statutory rate.

New accounting standards issued but not yet effective

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU amends the existing accounting standards for leases to increase transparency and comparability among organizations. The new guidance requires a lessee to recognize a lease right-of-use asset and related lease liability for most leases, including those classified as operating leases under current GAAP. The ASU also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We have planned and commenced our implementation of the new guidance. We have accumulated our lease contracts and are aggregating them into a lease software platform. We are also assessing non-lease contracts for inclusion of embedded leases as well as updating our policies and controls and establishing appropriate presentation and disclosure changes resulting from the new guidance. While our implementation plan is still ongoing, management’s assessment based on our current portfolio of leases, including vessel charters, is that our assets and liabilities will increase by a significant amount as we recognize right-of-use assets and lease liabilities on our balance sheet upon our adoption of this ASU. We do not expect the new guidance to have any significant impact on our earnings or cash flows. We will adopt the ASU on its effective date in the first quarter of 2019.

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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 August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU improves the financial reporting of hedging relationships to better align risk management activities in financial statements and makes certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

We do not expect any other recent accounting standards to have a material impact on our financial position, results of operations or cash flows.

Note 2 — Company Overview

We are an international offshore energy services company that provides specialty services to the offshore energy industry with a focus on well intervention and robotics operations. We seek to provide services and methodologies that we believe are critical to maximizing production economics. We provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our “life of field” services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities (Note 12).

Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services in the U.S. Gulf of Mexico, Brazil, North Sea and West Africa. Our Well Intervention segment also includes intervention riser systems (“IRSs”), some of which we provide 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 two chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. We also have a semi-submersible well intervention vessel under construction, the Q7000.

Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills, which are designed to complement offshore construction and well intervention services, and three ROV support vessels under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III. We also utilize spot vessels as needed.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamically positioned floating production vessel, 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 the Phoenix field operator since February 2013, currently under a fixed fee agreement through at least June 1, 2023. We are also party to an agreement providing various operators through March 31, 2019 with access to the HFRS for well control purposes. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”) (Note 5).

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Note 3 — Details of Certain Accounts

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



	June 30, 2018		December 31, 2017

Contract assets (Note 9)	$	727	$	—
Note receivable ⁽¹⁾	2,000		—
Prepaids	15,426		10,102
Deferred costs (Note 9)	27,275		27,204
Other	6,091		4,462
Total other current assets	$	51,519	$	41,768

(1)

The note receivable in the form of convertible bonds was issued to us by a customer as part of a payment forgiveness arrangement and was acquired from us by a third party on July 6, 2018. The fair value of the bonds at June 30, 2018 reflects the amount that we received from the sale. The bonds were previously scheduled to mature on December 14, 2019. The fair value of the bonds at December 31, 2017 is reflected in “Other assets, net” (see below). During the six-month period ended June 30, 2018, we reversed a $0.6 million unrealized gain previously recorded in Accumulated OCI and recorded a $1.1 million other than temporary loss to account for the reduction in the fair value of these bonds.

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



	June 30, 2018		December 31, 2017

Note receivable	$	—	$	3,758
Prepaids	6,788		7,666
Deferred dry dock costs, net	10,732		12,368
Deferred costs (Note 9)	51,089		63,767
Charter fee deposit ⁽¹⁾	12,544		12,544
Other	4,670		5,102
Total other assets, net	$	85,823	$	105,205


(1)	This amount deposited with the vessel owner is to be used to reduce our final charter payments for the Siem Helix 2.

Accrued liabilities consist of the following (in thousands):



	June 30, 2018		December 31, 2017

Accrued payroll and related benefits	$	35,245	$	30,685
Deferred revenue (Note 9)	14,438		12,609
Derivative liability (Note 15)	10,157		10,625
Other	21,247		17,761
Total accrued liabilities	$	81,087	$	71,680

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



	June 30, 2018		December 31, 2017

Investee losses in excess of investment (Note 5)	$	6,518	$	7,567
Deferred gain on sale of property ⁽¹⁾	5,466		5,838
Deferred revenue (Note 9)	20,169		8,744
Derivative liability (Note 15)	3,353		8,150
Other	11,193		10,391
Total other non-current liabilities	$	46,699	$	40,690


(1)	Relates to the sale and lease-back in January 2016 of our office and warehouse property located in Aberdeen, Scotland. 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,
	2018		2017

Interest paid, net of interest capitalized	$	3,783	$	6,663
Income taxes paid	$	3,651	$	2,424

Our non-cash investing activities include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions totaled $7.9 million as of June 30, 2018 and $16.9 million as of December 31, 2017.

Note 5 — Equity Investments

We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in the U.S. Gulf of Mexico in a water depth of 8,000 feet. Since we are committed to providing our pro-rata portion of the necessary level of financial support for Independence Hub to pay its obligations as they become due, we recorded liabilities of $8.8 million at June 30, 2018 and $9.8 million at December 31, 2017 for our share of the estimated obligations, net of remaining working capital. These liabilities are reflected in “Accrued liabilities” and “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

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Note 6 — Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of June 30, 2018 are as follows (in thousands):



	Term Loan ⁽¹⁾			2022 Notes			2023 Notes			MARAD Debt			Nordea Q5000 Loan			Total

Less than one year	$	3,744		$	—		$	—		$	6,693		$	35,714		$	46,151
One to two years	31,820			—			—			7,027			107,143			145,990
Two to three years	—			—			—			7,378			—			7,378
Three to four years	—			125,000			—			7,746			—			132,746
Four to five years	—			—			—			8,133			—			8,133
Over five years	—			—			125,000			36,797			—			161,797
Total debt	35,564			125,000			125,000			73,774			142,857			502,195
Current maturities	(3,744		)	—			—			(6,693		)	(35,714		)	(46,151		)
Long-term debt, less current maturities	31,820			125,000			125,000			67,081			107,143			456,044
Unamortized debt discount ⁽²⁾	—			(12,484		)	(19,394		)	—			—			(31,878		)
Unamortized debt issuance costs ⁽³⁾	(496		)	(2,030		)	(3,117		)	(4,269		)	(1,402		)	(11,314		)
Long-term debt	$	31,324		$	110,486		$	102,489		$	62,812		$	105,741		$	412,852


(1)	Term Loan borrowing pursuant to the Credit Agreement (amended and restated in June 2017) matures in June 2020. Scheduled maturities of the Term Loan have been adjusted to reflect prepayments made in March 2018.


(2)	Our Convertible Senior Notes due 2022 (the “2022 Notes”) will increase to their face amount through accretion of the debt discount through May 2022. Our Convertible Senior Notes due 2023 (the “2023 Notes”) will increase to their face amount through accretion of the debt discount through September 2023.


(3)	Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.

Below is a summary of certain components of our indebtedness:

Credit Agreement

On June 30, 2017, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”). The amended and restated credit facility is comprised of a $100 million term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) of up to $150 million (the “Revolving Loans”). The Revolving Credit Facility permits us to obtain letters of credit up to a sublimit of $25 million. Pursuant to the Credit Agreement, subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may request aggregate commitments up to $100 million with respect to an increase in the Revolving Credit Facility, additional term loans, or a combination thereof. As of June 30, 2018, we had no borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the applicable leverage ratio covenant, totaled $146.6 million, net of $3.4 million of letters of credit issued under that facility.

The Term Loan and the Revolving Loans (together, the “Loans”), at our election, bear interest in relation to Bank of America’s base rate, to a LIBOR rate or a combination thereof. The Term Loan bearing interest at the base rate will bear interest at a per annum rate equal to the base rate plus 3.25%. The Term Loan bearing interest at a LIBOR rate will bear interest per annum at the LIBOR rate selected by us plus a margin of 4.25%. The interest rate on the Term Loan was 6.34% as of June 30, 2018. The Revolving Loans 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 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 (as defined below) as provided for in the Credit Agreement. We also pay a fixed commitment fee of 0.50% per annum on the unused portion of our Revolving Credit Facility.

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The Term Loan principal is required to be repaid in quarterly installments totaling 5% in the first loan year, 10% in the second loan year and 15% in the third loan year, with a balloon payment at maturity. Installment amounts are subject to adjustment for any prepayments on the Term Loan. We may 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 Credit Facility without premium or penalty and may reborrow any amounts prepaid up to the amount of the Revolving Credit Facility. The Loans mature on June 30, 2020.

The Credit Agreement and the other documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, which we consider customary for this type of facility. The covenants include certain restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and make capital expenditures. In addition, the Credit Agreement obligates us to meet minimum ratios of EBITDA to interest charges (“Consolidated Interest Coverage Ratio”) and funded debt to EBITDA (“Consolidated Total Leverage Ratio”), and provided 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”). After the initial Term Loan is repaid in full, if there are any Loans outstanding including unreimbursed draws under letters of credit issued under the Revolving Credit Facility, we also are required to ensure that the ratio of our total secured indebtedness to EBITDA (“Consolidated Secured Leverage Ratio”) does not exceed the maximum permitted 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

June 30, 2018 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

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


(c)	The maximum permitted Consolidated Secured Leverage Ratio:



Four Fiscal Quarters Ending	Maximum Consolidated Secured Leverage Ratio

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

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(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
Greater than or equal to 3.50 to 1.00 but less than 4.00 to 1.00	$50,000,000
Less than 3.50 to 1.00	$0

(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 on our balance sheet as cash and cash equivalents. As of June 30, 2018, we were required to, and did, maintain an aggregate cash balance of at least $50 million in compliance with this covenant.

We may from time to time designate one or more of our foreign subsidiaries as subsidiaries not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”). The debt and EBITDA of Unrestricted Subsidiaries are not included in the calculations of our financial covenants, except for the debt and EBITDA of Helix Q5000 Holdings, S.a.r.l., a wholly owned subsidiary incorporated in Luxembourg (“Q5000 Holdings”). Our obligations under the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I - Title XI, Inc.) and by Canyon Offshore Limited, a wholly owned Scottish subsidiary. Our obligations under the Credit Agreement, and of such guarantors under their guarantee, are secured by (i) most of the assets of the parent, (ii) the shares of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and Canyon Offshore Limited, and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and Canyon Offshore Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries.

In March 2018, we prepaid $61 million of the Term Loan with a portion of the net proceeds from the 2023 Notes. We recognized a $0.9 million loss to write off the related unamortized debt issuance costs, which loss is presented as “Loss on extinguishment of long-term debt” in the accompanying consolidated statement of operations.

Convertible Senior Notes Due 2022

On November 1, 2016, we completed a public offering and sale of our 2022 Notes in the aggregate principal amount of $125 million. The 2022 Notes bear interest at a rate of 4.25% per annum, and are payable semi-annually in arrears on November 1 and May 1 of each year, beginning on May 1, 2017. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions (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 our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.

Prior to November 1, 2019, the 2022 Notes are not redeemable. On or after November 1, 2019, if certain conditions are met, we may redeem all or any portion of the 2022 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium.” Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change,” as defined in the indenture governing the 2022 Notes.

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

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The 2022 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million ($11.0 million net of tax) as a result of separating the equity component. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2022 Notes at their inception. The remaining unamortized amount of the debt discount of the 2022 Notes was $12.5 million at June 30, 2018 and $13.9 million at December 31, 2017.

Convertible Senior Notes Due 2023

On March 20, 2018, we completed a public offering and sale of our 2023 Notes in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2023 Notes were approximately $121 million, after deducting the underwriters’ discounts and commissions and estimated offering expenses. We used the net proceeds from the issuance of the 2023 Notes to fund the required repurchase of $59.3 million in principal of the 2032 Notes and to prepay $61 million of our Term Loan.

The 2023 Notes bear interest at a rate of 4.125% per annum, and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2018. The 2023 Notes mature on September 15, 2023 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions (as described in the indenture governing the 2023 Notes), the 2023 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 105.6133 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $9.47 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.

Prior to March 15, 2021, the 2023 Notes are not redeemable. On or after March 15, 2021, if certain conditions are met, we may redeem all or any portion of the 2023 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium.” Holders of the 2023 Notes may require us to repurchase the notes following a “fundamental change,” as defined in the indenture governing the 2023 Notes.

The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2023 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2023 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.

The 2023 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2023 Notes, we recorded a debt discount of $20.1 million ($15.9 million net of tax) as a result of separating the equity component. The effective interest rate for the 2023 Notes is 7.8% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2023 Notes at their inception. The remaining unamortized amount of the debt discount of the 2023 Notes was $19.4 million at June 30, 2018.

MARAD Debt

This U.S. government guaranteed financing (the “MARAD Debt”), pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. The MARAD Debt is payable in equal semi-annual installments, matures in February 2027 and bears interest at a rate of 4.93%.

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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. Quarterly principal installments 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 15). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.

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

Convertible Senior Notes Due 2032

In March 2012, we issued $200 million of 3.25% Convertible Senior Notes which were originally scheduled to mature on March 15, 2032. In March 2018, we made a tender offer for the repurchase of the 2032 Notes outstanding on the first repurchase date as required by the indenture governing the 2032 Notes, and as a result we repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018. The total repurchase price was $59.5 million, including $0.2 million in fees. We recognized a $0.2 million loss in connection with the repurchase of the notes. The loss is presented as “Loss on extinguishment of long-term debt” in the accompanying consolidated statement of operations. On May 4, 2018, we redeemed the remaining $0.8 million in aggregate principal amount of the 2032 Notes.

Other

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017

Interest expense	$	8,041		$	11,607		$	16,340		$	21,847
Interest income	(679		)	(918		)	(1,269		)	(1,264		)
Capitalized interest	(3,763		)	(4,050		)	(7,576		)	(8,718		)
Net interest expense	$	3,599		$	6,639		$	7,495		$	11,865

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Note 7 — Income Taxes

On December 22, 2017, the 2017 Tax Act was enacted. The 2017 Tax Act is comprehensive tax reform legislation that contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate from 35% to 21%, a mandatory one-time tax on un-repatriated accumulated earnings of foreign subsidiaries, a partial limitation on the deductibility of business interest expense, and a shift of the U.S. taxation of multinational corporations from a tax on worldwide income to a partial territorial system (along with rules that create a new U.S. minimum tax on earnings of foreign subsidiaries).

We recognized the income tax effects of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”), which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes, to the 2017 Tax Act. SAB 118 allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. We believe the provisional amounts recorded during the fourth quarter of 2017 continue to represent a reasonable estimate of the accounting implications of the 2017 Tax Act. We did not identify any items for which the income tax effects of the 2017 Tax Act could not be reasonably estimated through June 30, 2018.

We believe that our recorded deferred tax assets and liabilities are reasonable. However, tax laws and regulations are subject to interpretation, and the outcomes of tax disputes are inherently uncertain; therefore, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

Our estimated annual effective tax rate, adjusted for discrete tax items, is applied to our pretax loss for the current interim period in 2018 as we have determined that a return to the annualized effective tax rate method is appropriate for 2018. A year-to-date effective tax rate method was used for recording income taxes for the comparative interim period in 2017 based on expectations that a small change in our estimated ordinary income could result in a large change in the estimated annual effective tax rate.

The effective tax rates for the three- and six-month periods ended June 30, 2018 were 1.6% and 2.5%, respectively. The effective tax rates for the three- and six-month periods ended June 30, 2017 were (364.0)% and (1.9)%, respectively. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, the reduction of the U.S. corporate income tax rate from 35% to 21% as a result of the 2017 Tax Act, and a tax charge in 2017 attributable to a change in tax position related to our foreign taxes.

Income taxes are provided based on the U.S. statutory rate 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,
	2018		2017		2018		2017

U.S. statutory rate	21.0	%	35.0	%	21.0	%	35.0	%
Foreign provision	(19.6	)	79.7		(20.2	)	(5.5	)
Change in tax position ⁽¹⁾	—		(459.7	)	—		(28.3	)
Other	0.2		(19.0	)	1.7		(3.1	)
Effective rate	1.6	%	(364.0	)%	2.5	%	(1.9	)%


(1)	As a result of a change in tax position related to our foreign taxes, we recorded a tax charge of $6.3 million in June 2017.

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Note 8 — Shareholders’ Equity

The components of Accumulated OCI are as follows (in thousands):



	June 30, 2018			December 31, 2017

Cumulative foreign currency translation adjustment	$	(65,545	)	$	(62,689	)
Net unrealized loss on hedges, net of tax ⁽¹⁾	(5,704		)	(7,507		)
Unrealized gain on note receivable, net of tax ⁽²⁾	—			409
Accumulated other comprehensive loss	$	(71,249	)	$	(69,787	)

(1)

Relates to foreign currency hedges for the Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan (Note 15). Balance at June 30, 2018 was net of deferred income taxes totaling $1.4 million. Balance at December 31, 2017 was net of deferred income taxes of $4.0 million, $1.6 million of which was reclassified to retained earnings on January 1, 2018 pursuant to the adoption of ASU No. 2018-02 (Note 1).


(2)	Balance at December 31, 2017 was net of deferred income taxes of $0.2 million, $0.1 million of which was reclassified to retained earnings on January 1, 2018 pursuant to the adoption of ASU No. 2018-02 (Note 1).

Note 9 — Revenue from Contracts with Customers

We generate revenue in our Well Intervention segment by supplying the vessels, personnel, and equipment to provide well intervention services, which involve providing marine access, serving as a deployment mechanism to the subsea well, connecting to and maintaining a secure connection to the subsea well and maintaining well control through the duration of the intervention services. We also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs, trenchers and ROVDrills to provide subsea construction, inspection, repair and maintenance services to oil and gas companies as well as subsea trenching and burial of pipelines and cables for the oil and gas and the renewable energy industries. We also provide integrated robotic services by supplying vessels that deploy the ROVs and trenchers. Our Production Facilities segment generates revenue by providing the personnel, vessel and equipment for oil and natural gas processing as well as well control response services.

Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities.

We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration for these activities as well as contract fulfillment activities is allocated to the single performance obligation on a systematic basis that depicts the pattern of the provision of our services to the customer.

The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We do not generally provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. The estimated amount of variable consideration is constrained and is only included in the transaction price to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.

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Dayrate Contracts. Revenues generated from dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g. operating rate, standby rate, repair rate). The invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month.

Dayrate contracts also may contain fees charged to the customer for mobilizing and demobilizing equipment and personnel. Mobilization and demobilization fees are associated with contract fulfillment activities, and related revenue (subject to any constraint on estimates of variable consideration) is allocated to the single performance obligation and recognized ratably over the initial term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer. See further discussion on contract liabilities under “Contract balances” below.

We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.

A dayrate contract modification involving an extension of the contract by adding additional days of services is generally accounted prospectively for as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.

Lump Sum Contracts. Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.

We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue (either as an increase in or a reduction of revenue) on a cumulative catch-up basis.

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Disaggregation of revenue

The following table provides information about disaggregated revenue by contract duration for the three- and six-month periods ended June 30, 2018 (in thousands):



	Well Intervention		Robotics		Production Facilities		Intercompany Elimination ⁽¹⁾			Total Revenue
Three months ended June 30, 2018
Short-term	$	61,935	$	30,738	$	—	$	—		$	92,673
Long-term ⁽²⁾	99,824		8,322		16,343		(12,537		)	111,952
Total	$	161,759	$	39,060	$	16,343	$	(12,537	)	$	204,625

Six months ended June 30, 2018
Short-term	$	103,962	$	51,062	$	—	$	—		$	155,024
Long-term ⁽²⁾	187,366		15,167		32,664		(21,334		)	213,863
Total	$	291,328	$	66,229	$	32,664	$	(21,334	)	$	368,887


(1)	Intercompany revenues between Robotics and Well Intervention are under agreements that are considered long-term.


(2)	Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.

Contract balances

Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable that have been billed to customers are recorded as trade accounts receivable while accounts receivable that have not been billed to customers are recorded as unbilled accounts receivable.

Contract assets are rights to consideration in exchange for services that we have transferred to a customer when that right is conditional on our future performance. Contract assets may consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” on the accompanying condensed consolidated balance sheet. Contract assets as of January 1, 2018 were immaterial while contract assets as of June 30, 2018 were $0.7 million. Impairment losses recognized on our accounts receivable and contract assets were immaterial for the three- and six-month periods ended June 30, 2018.

Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to the single performance obligation and recognized ratably over the contract term and (ii) the amount billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” on the accompanying condensed consolidated balance sheet. Contract liabilities as of January 1, 2018 and June 30, 2018 totaled $21.4 million and $34.6 million, respectively. Revenue recognized for the three- and six-month periods ended June 30, 2018 included $8.7 million and $10.0 million, respectively, that were included in the contract liability balance at the beginning of each period.

We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.

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Performance obligations

As of June 30, 2018, $1.4 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $268.6 million in 2018, $439.6 million in 2019 and $663.4 million in 2020 and thereafter. These amounts included fixed consideration and estimated variable consideration for both wholly and partially unsatisfied performance obligations, including mobilization and demobilization fees. These amounts are derived from the specific terms within our contracts, and the expected timing for revenue recognition is based on the estimated start date and duration of each contract according to the information known at June 30, 2018.

For the three- and six-month periods ended June 30, 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

Contract costs

Contract costs consist of costs incurred in fulfilling a contract with a customer. Our contract costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which these contact costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” on the accompanying condensed consolidated balance sheet. Our deferred contract costs totaled $78.4 million as of June 30, 2018. For the three- and six-month periods ended June 30, 2018, we recorded $8.2 million and $17.1 million, respectively, related to amortization of deferred contract costs and there were no associated impairment losses.

Note 10 — Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. 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. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations for the three- and six-month periods ended June 30, 2018 are as follows (in thousands):

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	Three Months Ended June 30, 2018				Six Months Ended June 30, 2018
	Income			Shares	Income			Shares
Basic:
Net income	$	17,784			$	15,224
Less: Undistributed earnings allocated to participating securities	(171		)		(147		)
Undistributed earnings allocated to common shares	$	17,613		146,683	$	15,077		146,668

Diluted:
Undistributed earnings allocated to common shares	$	17,613		146,683	$	15,077		146,668
Effect of dilutive securities:
Share-based awards other than participating securities	—			41	—			—
Undistributed earnings reallocated to participating securities	—			—	—			—
Net income	$	17,613		146,724	$	15,077		146,668

We had net losses for the three- and six-month periods ended June 30, 2017. 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	Six Months Ended
	June 30, 2017	June 30, 2017

Diluted shares (as reported)	145,940	144,599
Share-based awards	228	244
Total	146,168	144,843

In addition, the following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 2032 Notes were excluded from the diluted EPS calculation 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,
	2018	2017	2018	2017

2022 Notes	8,997	8,997	8,997	8,997
2023 Notes	13,202	—	7,440	—
2032 Notes ⁽¹⁾	12	2,403	1,057	2,403


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

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Note 11 — Employee Benefit Plans

Long-Term Incentive Plan

As of June 30, 2018, there were 1.8 million shares of our common stock available for issuance under our long-term incentive plan, the 2005 Long-Term Incentive Plan, as amended and restated January 1, 2017 (the “2005 Incentive Plan”). During the six-month period ended June 30, 2018, the following grants of share-based awards were made under the 2005 Incentive Plan:



Date of Grant	Shares / Units	Grant Date Fair Value Per Share		Vesting Period

January 2, 2018 ⁽¹⁾	449,271	$	7.54	33% per year over three years
January 2, 2018 ⁽²⁾	449,271	$	10.44	100% on January 2, 2021
January 2, 2018 ⁽³⁾	8,247	$	7.54	100% on January 1, 2020
April 2, 2018 ⁽³⁾	11,064	$	5.79	100% on January 1, 2020


(1)	Reflects grants of restricted stock to our executive officers.


(2)	Reflects grants of performance share units (“PSUs”) to our executive officers. 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. These awards when vested can only be settled in shares of our common stock.


(3)	Reflects grants 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. Forfeitures are recognized as they occur. For the three- and six-month periods ended June 30, 2018, $1.5 million and $3.0 million, respectively, were recognized as share-based compensation related to restricted stock. 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.

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 that occurs upon vesting. The PSUs granted in 2017 and 2018 are accounted for as equity awards whereas awards granted prior to 2017 are accounted for as liability awards. For the three- and six-month periods ended June 30, 2018, $4.2 million and $5.2 million, respectively, were recognized as share-based compensation related to PSUs. 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. The liability balance for unvested PSUs was $13.4 million at June 30, 2018 and $11.1 million at December 31, 2017. We paid $0.9 million in cash to settle the 2015 PSU awards when they vested in January 2018.

Additionally in January 2018, we granted $5.0 million of fixed value cash awards to select management employees under the 2005 Incentive Plan. The value of these cash awards is recognized on a straight-line basis over a vesting period of three years. For the three- and six-month periods ended June 30, 2018, $0.4 million and $0.8 million, respectively, was recognized as compensation cost.

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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 0.6 million shares were available for issuance as of June 30, 2018. The ESPP currently has a purchase limit of 130 shares per employee per purchase period.

For more information regarding our employee benefit plans, including our long-term incentive stock-based and cash plans and our employee stock purchase plan, see Note 11 to our 2017 Form 10-K.

Note 12 — Business Segment Information

We have three reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention business segment for financial reporting purposes. Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services in the U.S. Gulf of Mexico, Brazil, North Sea and West Africa. Our Well Intervention segment also includes IRSs, some of which we provide 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. Our Robotics segment includes ROVs, trenchers and ROVDrills, which are designed to complement offshore construction and well intervention services, and three ROV support vessels under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III. Our Production Facilities segment includes the HP I, the HFRS and our investment in Independence Hub that is accounted for under the equity method. 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,
	2018			2017			2018			2017
Net revenues —
Well Intervention	$	161,759		$	113,076		$	291,328		$	187,697
Robotics	39,060			33,061			66,229			55,029
Production Facilities	16,343			15,210			32,664			31,585
Intercompany elimination	(12,537		)	(11,018		)	(21,334		)	(19,454		)
Total	$	204,625		$	150,329		$	368,887		$	254,857

Income (loss) from operations —
Well Intervention	$	34,470		$	19,032		$	48,347		$	20,450
Robotics	(4,102		)	(11,642		)	(18,419		)	(27,948		)
Production Facilities	6,866			6,140			14,225			13,064
Corporate and other	(12,684		)	(8,701		)	(20,940		)	(18,663		)
Intercompany elimination	222			221			443			442
Total	$	24,772		$	5,050		$	23,656		$	(12,655	)

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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,
	2018		2017		2018		2017

Well Intervention	$	4,215	$	2,895	$	6,167	$	4,268
Robotics	8,322		8,123		15,167		15,186
Total	$	12,537	$	11,018	$	21,334	$	19,454

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, 2018		December 31, 2017

Well Intervention	$	1,885,738	$	1,830,733
Robotics	152,876		179,853
Production Facilities	127,099		138,292
Corporate and other	201,131		213,959
Total	$	2,366,844	$	2,362,837

Note 13 — Commitments and Contingencies and Other Matters

Commitments

We have charter agreements with Siem Offshore AS for the Siem Helix 1 and Siem Helix 2 vessels used in connection with our contracts with Petrobras to perform well intervention work offshore Brazil. We have charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The charter agreements expire in October 2019 for the Grand Canyon, in April 2021 for the Grand Canyon II and in May 2023 for the Grand Canyon III.

In September 2013, we executed a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% was paid in December 2017, 20% is to be paid on December 31, 2018, and 20% is to be paid upon the delivery of the vessel, which at our option can be deferred until December 31, 2019. We are also contractually committed to reimburse the shipyard for its costs in connection with the deferment of the Q7000’s delivery beyond 2017. At June 30, 2018, our total investment in the Q7000 was $314.9 million, including $207.6 million of installment payments to the shipyard. Currently, equipment is being manufactured and installed for the completion of the vessel.

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.

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Note 14 — 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).

Our financial instruments include cash and cash equivalents, receivables, accounts payable, long-term debt and derivative instruments. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments. The fair value of our derivative instruments (Note 15) and of our note receivable in the form of convertible bonds that are accounted for as investments in available-for-sale debt securities (Note 3) reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. The following tables provide additional information relating to those financial instruments measured at fair value on a recurring basis (in thousands):



	Fair Value Measurements at June 30, 2018 Using
	Level 1		Level 2		Level 3		Total		Valuation Approach
Assets:
Note receivable	$	—	$	2,000	$	—	$	2,000
Interest rate swaps	—		1,617		—		1,617		(c)

Liabilities:
Foreign exchange contracts	—		13,511		—		13,511		(c)
Total net liability	$	—	$	9,894	$	—	$	9,894

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	Fair Value Measurements at December 31, 2017 Using
	Level 1		Level 2		Level 3		Total		Valuation Approach
Assets:
Note receivable	$	—	$	3,758	$	—	$	3,758
Interest rate swaps	—		966		—		$	966	(c)

Liabilities:
Foreign exchange contracts	—		12,467		—		12,467		(c)
Total net liability	$	—	$	7,743	$	—	$	7,743

The principal amount and estimated fair value of our long-term debt are as follows (in thousands):



	June 30, 2018				December 31, 2017
	Principal Amount ⁽¹⁾		Fair Value ^{(2) (3)}		Principal Amount ⁽¹⁾		Fair Value ^{(2) (3)}

Term Loan (matures June 2020)	$	35,564	$	35,631	$	97,500	$	98,231
Nordea Q5000 Loan (matures April 2020)	142,857		142,054		160,714		160,111
MARAD Debt (matures February 2027)	73,774		77,140		77,000		82,058
2022 Notes (mature May 2022)	125,000		129,219		125,000		124,219
2023 Notes (mature September 2023)	125,000		147,812		—		—
2032 Notes (redeemed May 2018)	—		—		60,115		60,040
Total debt	$	502,195	$	531,856	$	520,329	$	524,659


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

(2)

The estimated fair value of the 2022 Notes and the 2023 Notes was determined using Level 1 inputs under the market approach. The fair value of the Term Loan, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.


(3)	The principal amount and fair value of the convertible notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.

Note 15 — 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 reported in Accumulated OCI to the extent that the hedges are effective. These changes are subsequently reclassified into earnings when the hedged transactions settle. 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.

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For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 17 to our 2017 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 reported in Accumulated OCI to the extent the swaps are effective. These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense. The ineffective portion of the interest rate swaps, if any, is recognized immediately in earnings within the line titled “Net interest expense.” The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.

Foreign Currency Exchange Rate Risk

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

In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure associated with the Grand Canyon II and Grand Canyon III charter payments denominated in Norwegian kroner through July 2019 and February 2020, respectively. Unrealized losses associated with 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 not 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, 2018 and 2017.

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, 2018			December 31, 2017
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivative Instruments:
Interest rate swaps	Other current assets	$	875	Other current assets	$	311
Interest rate swaps	Other assets, net	742		Other assets, net	655
		$	1,617		$	966

Liability Derivative Instruments:
Foreign exchange contracts	Accrued liabilities	$	7,170	Accrued liabilities	$	7,492
Foreign exchange contracts	Other non-current liabilities	1,587		Other non-current liabilities	4,975
		$	8,757		$	12,467

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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, 2018			December 31, 2017
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivative Instruments:
Foreign exchange contracts	Accrued liabilities	$	2,988	Accrued liabilities	$	3,133
Foreign exchange contracts	Other non-current liabilities	1,766		Other non-current liabilities	3,175
		$	4,754		$	6,308

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, 2018, $5.0 million of losses in Accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.



	Unrealized Gain (Loss) Recognized in OCI (Effective Portion)
	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018		2017

Foreign exchange contracts	$	(1,459	)	$	1,138		$	129	$	1,809
Interest rate swaps	233			(203		)	798		35
	$	(1,226	)	$	935		$	927	$	1,844



	Location of Gain (Loss) Reclassified from Accumulated OCI into Earnings	Gain (Loss) Reclassified from Accumulated OCI into Earnings (Effective Portion)
		Three Months Ended June 30,						Six Months Ended June 30,
		2018			2017			2018			2017

Foreign exchange contracts	Cost of sales	$	(1,925	)	$	(3,771	)	$	(3,581	)	$	(6,992	)
Interest rate swaps	Net interest expense	118			(178		)	147			(447		)
		$	(1,807	)	$	(3,949	)	$	(3,434	)	$	(7,439	)

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



	Location of Gain (Loss) Recognized in Earnings	Gain (Loss) Recognized in Earnings
		Three Months Ended June 30,					Six Months Ended June 30,
		2018			2017		2018		2017

Foreign exchange contracts	Other income (expense), net	$	(787	)	$	429	$	57	$	481
		$	(787	)	$	429	$	57	$	481

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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,” “budget,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements. Included in forward-looking statements are, among other things:


•	statements regarding our business strategy or any other business plans, forecasts or objectives, any or all of which are subject to change;


•	statements regarding projections of revenues, gross margins, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;


•	statements regarding our backlog and long-term contracts and rates thereunder;


•	statements regarding our ability to enter into and/or perform commercial contracts, including the scope, timing and outcome of those contracts;


•	statements regarding the acquisition, construction, upgrades or maintenance of vessels or equipment and any anticipated costs or downtime related thereto, including the construction of our Q7000 vessel;


•	statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;


•	statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;


•	statements regarding our trade receivables and their collectability;


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


•	statements regarding general economic or political conditions, whether international, national or in the regional and local markets in which we do business;


•	statements regarding our ability to retain our senior management and other key employees;


•	statements regarding the underlying assumptions related to any projection or forward-looking statement; and


•	any other statements that relate to non-historical or future information.

Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include:


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


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


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


•	the ability to effectively bid and perform our contracts;


•	the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets;


•	unexpected future capital expenditures, including the amount and nature thereof;


•	the effectiveness and timing of completion of our vessel upgrades and major maintenance items;


•	unexpected delays in the delivery or chartering or customer acceptance, and terms of acceptance, of new assets for our well intervention and robotics fleet;


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


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


•	the success of our risk management activities;


•	the effects of competition;


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


•	the impact of current and future laws and governmental regulations, including tax and accounting developments, such as the 2017 Tax Act;

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•	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 impact of foreign currency fluctuations;


•	the effectiveness of our current and future hedging activities;


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


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

Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 1A. “Risk Factors” in our 2017 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. Following the delivery of the two newbuild Siem Helix chartered vessels, we expect our well intervention fleet to further expand with the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018 or 2019. Chartering newer vessels with additional capabilities, such as the three Grand Canyon vessels, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also expect to benefit from our fixed fee agreement for the HP I, a dynamically positioned floating production vessel that processes production from the Phoenix field for the field operator until at least June 1, 2023.

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 clients, 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. intervention riser system (“15K IRS”) for a total cost of approximately $28 million (approximately $14 million for our 50% interest), which was completed and placed into service in January 2018. 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). At June 30, 2018, our total investment in the ROAM was $4.5 million. The ROAM is expected to be available to customers late in the third quarter or early in the fourth quarter of 2018.

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.

Oil prices have recently risen above $70 per barrel. An increase in oil and gas exploration and production activities (shale oil production in particular) is expected as major oil producing countries including the U.S. increase output as a result of rising oil prices. Increased supply without adequate levels of increase in demand, however, may constrain oil prices and weaken industry prospects. The resulting weak industry environment may continue to curtail investments in offshore exploration and production as well as other offshore operational activities. Increased competition for limited offshore oil and gas projects has driven down rates that drilling rig contractors are charging for their services, which affects us, as drilling rigs historically have been the asset class used for intervention work. This rig overhang combined with lower volumes of work may affect the utilization and/or rates we can achieve for our assets. The current volatile and uncertain macroeconomic conditions in some countries around the world, such as Brazil and the U.K. following Brexit, may have a direct and/or indirect impact on our existing contracts and contracting opportunities and may introduce further currency volatility into our operations and/or financial results. In addition, the longer term effects of the 2017 Tax Act on capital spending by oil and gas companies are still uncertain.

Many oil and gas companies are increasingly focusing on optimizing production of their existing subsea wells. We believe that we have a competitive advantage in terms of performing well intervention services efficiently. Furthermore, we believe that when oil and gas companies begin to increase overall spending levels, it will likely be for production enhancement activities rather than for exploration projects. Our well intervention and robotics operations are intended to service the life span of an oil and gas field as well as to provide abandonment services at the end of the life of a field as required by governmental regulations. Thus, we believe that fundamentals for our business remain favorable over the longer term as the need for prolongation of well life in oil and gas production is the primary driver of demand for our services.

Our current strategy is to be positioned for future recovery while 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. Pursuant to an agreement with certain industry participants, in exchange for a retainer fee, the HFRS provides these participants with a response resource that can be named in permit applications to federal and state agencies. The HFRS agreements with individual participants also specify the day rates to be charged should the HFRS be deployed in connection with a well control incident. The term of these agreements is currently through 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, Brazil, North Sea, Asia Pacific and West Africa regions. 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, 2018, our consolidated backlog that is supported by written agreements or contracts totaled $1.4 billion, of which $268.6 million is expected to be performed over the remainder of 2018. The substantial majority of our backlog is associated with our Well Intervention business segment. As of June 30, 2018, our well intervention backlog was $1.0 billion, including $197.5 million expected to be performed over the remainder of 2018. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with Petróleo Brasileiro S.A. (“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 87% of our total backlog as of June 30, 2018. Our contracts are in certain cases cancelable 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 GAAP. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.

We measure our operating performance based on EBITDA and free cash flow. EBITDA and free cash flow are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA and free cash flow to monitor and facilitate the internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA and free cash flow provide useful information to the public regarding our ability to service debt and fund capital expenditures and may help our investors understand our operating performance and compare our results to other companies that have different financing, capital and tax structures.

We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. To arrive at our measure of Adjusted EBITDA, we exclude gain or loss on disposition of assets. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments and other than temporary loss on note receivable, which are excluded from EBITDA as a component of net other income or expense. We define free cash flow as cash flow from operating activities less capital expenditures, net of proceeds from sale of assets. In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted.

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Other companies may calculate their measures of EBITDA, Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA and free cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income or other income data prepared in accordance with 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,
	2018			2017			2018			2017

Net income (loss)	$	17,784		$	(6,403	)	$	15,224		$	(22,818	)
Adjustments:
Income tax provision	298			5,023			385			422
Net interest expense	3,599			6,639			7,495			11,865
Loss on extinguishment of long-term debt	76			397			1,181			397
Other (income) expense, net	3,441			(467		)	2,516			68
Depreciation and amortization	27,877			25,519			55,659			56,377
EBITDA	53,075			30,708			82,460			46,311
Adjustments:
Loss on disposition of assets, net	—			—			—			39
Realized losses from foreign exchange contracts not designated as hedging instruments	(806		)	(981		)	(1,496		)	(2,001		)
Other than temporary loss on note receivable	—			—			(1,129		)	—
Adjusted EBITDA	$	52,269		$	29,727		$	79,835		$	44,349

The reconciliation of our cash flow from operating activities to free cash flow is as follows (in thousands):



	Six Months Ended June 30,
	2018			2017

Cash flows from operating activities	$	87,666		$	15,601
Less: Capital expenditures, net of proceeds from sale of assets	(41,969		)	(84,396		)
Free cash flow	$	45,697		$	(68,795	)

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Comparison of Three Months Ended June 30, 2018 and 2017

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



	Three Months Ended June 30,						Increase/ (Decrease)
	2018			2017			Increase/ (Decrease)
Net revenues —
Well Intervention	$	161,759		$	113,076		$	48,683
Robotics	39,060			33,061			5,999
Production Facilities	16,343			15,210			1,133
Intercompany elimination	(12,537		)	(11,018		)	(1,519		)
	$	204,625		$	150,329		$	54,296

Gross profit (loss) —
Well Intervention	$	38,033		$	22,004		$	16,029
Robotics	(1,485		)	(9,634		)	8,149
Production Facilities	6,994			6,206			788
Corporate and other	(867		)	(430		)	(437		)
Intercompany elimination	222			221			1
	$	42,897		$	18,367		$	24,530

Gross margin —
Well Intervention	24%			19%
Robotics	(4)%			(29)%
Production Facilities	43%			41%
Total company	21%			12%

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	6/88%			5/90%
Robotics assets	55/38%			60/42%
Chartered robotics vessels	5/70%			4/57%


(1)	Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters and 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 the 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. The average utilization rates of chartered robotics vessels during the three-month periods ended June 30, 2018 and 2017 include 54 and 17 spot vessel days, respectively, at 100% utilization.

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	Three Months Ended June 30,				Increase/ (Decrease)
	2018		2017		Increase/ (Decrease)

Well Intervention	$	4,215	$	2,895	$	1,320
Robotics	8,322		8,123		199
	$	12,537	$	11,018	$	1,519

Net Revenues. Our total net revenues increased by 36% for the three-month period ended June 30, 2018 as compared to the same period in 2017 as a result of higher revenues in all of our business segments.

Our Well Intervention revenues increased by 43% for the three-month period ended June 30, 2018 as compared to the same period in 2017 reflecting higher revenues generated from our well intervention operations in all regions. In Brazil, the Siem Helix 1 and Siem Helix 2 vessels commenced operations for Petrobras in mid-April 2017 and mid-December 2017, respectively. Both vessels were under contract during the second quarter of 2018 with the Siem Helix 1 achieving 92% utilization and the Siem Helix 2 achieving 99% utilization. During the second quarter of 2017, the Siem Helix 1 was 95% utilized after it commenced operations in mid-April. In the Gulf of Mexico, the Q4000 was 76% utilized during the second quarter of 2018 as compared to being 63% utilized during the same period in 2017. The addition of 15K IRS as well as utilization of other IRS rentals also contributed to the increased revenues in the second quarter of 2018. These increases were partially offset by reduced utilization of the Q5000 from 91% during the second quarter of 2017 to 71% during the same period in 2018. Revenue increases in the North Sea reflects slight rate improvements as well as more diving and high margin coil tubing work despite the Well Enhancer and the Seawell being 94% and 97% utilized, respectively, during the second quarter of 2018 as compared to being fully utilized during the same period in 2017.

Robotics revenues increased by 18% for the three-month period ended June 30, 2018 as compared to the same period in 2017. The increase primarily reflects higher trenching revenues and increased utilization of ROV support vessels from 57% during the second quarter of 2017 to 70% during the same period in 2018.

Our Production Facilities revenues increased by 7% for the three-month period ended June 30, 2018 as compared to the same period in 2017, primarily reflecting lower revenues from the HFRS retainer fees as a result of the Q4000 undergoing regulatory dry dock during the second quarter of 2017.

Gross Profit (Loss). Our total gross profit increased by 134% for the three-month period ended June 30, 2018 as compared to the same period in 2017 reflecting improvements across all business segments.

The gross profit related to our Well Intervention segment increased by 73% for the three-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting positive operating results from our well intervention operations in the Gulf of Mexico, North Sea and Brazil during the second quarter of 2018.

The gross loss associated with our Robotics segment decreased by 85% for the three-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting higher trenching revenues, increased utilization for our ROV support vessels and cost reductions.

The gross profit related to our Production Facilities segment increased by 13% for the three-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting lower revenues from the HFRS retainer fees in the second quarter of 2017.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses increased by $4.8 million for the three-month period ended June 30, 2018 primarily attributable to increased costs associated with our employee share-based compensation awards linked to our stock price (Note 11).

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Net Interest Expense. Our net interest expense decreased by $3.0 million for the three-month period ended June 30, 2018 as compared to the same period in 2017. The decrease in net interest expense was largely attributable to a reduction in our overall debt levels.

Other Income (Expense), Net. We reported other expense, net, of $3.4 million for the three-month period ended June 30, 2018 as compared to other income, net, of $0.5 million for the same period in 2017. Net other expense for the three-month period ended June 30, 2018 included foreign currency transaction losses totaling $2.7 million. Also included in the comparable quarter-over-quarter periods were net gains (losses) of $(0.8) million and $0.4 million, respectively, associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 15).

Income Tax Provision. Income tax provision was $0.3 million for the three-month period ended June 30, 2018 as compared to $5.0 million for the same period in 2017. The variance primarily reflects a tax charge in 2017 attributable to a change in tax position related to our foreign taxes. The effective tax rate was 1.6% for the three-month period ended June 30, 2018 as compared to (364.0)% for the same period in 2017. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, the reduction of the U.S. corporate tax rate from 35% to 21% as a result of the 2017 Tax Act, and the tax charge in 2017 (Note 7).

Comparison of Six Months Ended June 30, 2018 and 2017

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



	Six Months Ended June 30,						Increase/ (Decrease)
	2018			2017			Increase/ (Decrease)
Net revenues —
Well Intervention	$	291,328		$	187,697		$	103,631
Robotics	66,229			55,029			11,200
Production Facilities	32,664			31,585			1,079
Intercompany elimination	(21,334		)	(19,454		)	(1,880		)
	$	368,887		$	254,857		$	114,030

Gross profit (loss) —
Well Intervention	$	55,721		$	27,115		$	28,606
Robotics	(13,383		)	(22,385		)	9,002
Production Facilities	14,451			13,251			1,200
Corporate and other	(1,352		)	(881		)	(471		)
Intercompany elimination	443			442			1
	$	55,880		$	17,542		$	38,338

Gross margin —
Well Intervention	19%			14%
Robotics	(20)%			(41)%
Production Facilities	44%			42%
Total company	15%			7%

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	6/80%			5/74%
Robotics assets	55/34%			60/39%
Chartered robotics vessels	5/63%			4/49%

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(1)	Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters and 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 the 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. The average utilization rates of chartered robotics vessels during the six-month periods ended June 30, 2018 and 2017 include 96 and 17 spot vessel days, respectively, at 100% utilization.



	Six Months Ended June 30,				Increase/ (Decrease)
	2018		2017		Increase/ (Decrease)

Well Intervention	$	6,167	$	4,268	$	1,899
Robotics	15,167		15,186		(19		)
	$	21,334	$	19,454	$	1,880

Net Revenues. Our total net revenues increased by 45% for the six-month period ended June 30, 2018 as compared to the same period in 2017 as a result of higher revenues in all of our business segments.

Our Well Intervention revenues increased by 55% for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting higher revenues in Brazil and the Gulf of Mexico, offset in part by lower revenues in the North Sea. In Brazil, the Siem Helix 1 and Siem Helix 2 vessels commenced operations for Petrobras in mid-April 2017 and mid-December 2017, respectively. The Siem Helix 1 and the Siem Helix 2 achieved 95% and 94% utilization, respectively, during the first half of 2018. In the first half of 2017, the Siem Helix 1 was 95% utilized after it commenced operations in mid-April. In the Gulf of Mexico, the Q4000 was 88% utilized during the first half of 2018 as compared to being 73% utilized during the same period in 2017. The addition of the 15K IRS as well as higher utilization of other IRS rentals also contributed to the increased revenues in the first half of 2018. These increases were partially offset by reduced utilization of the Q5000 from 94% during the first half of 2017 to 79% during the same period in 2018. In the North Sea, the Well Enhancer was 64% utilized during the first half of 2018 while the vessel was 80% utilized during the same period in 2017. The Seawell was 62% utilized during the first half of 2018 whereas it was 77% utilized during the same period in 2017.

Robotics revenues increased by 20% for the six-month period ended June 30, 2018 as compared to the same period in 2017. The increase primarily reflects higher trenching revenues and increased utilization of ROV support vessels from 49% during the first half of 2017 to 63% during the same period in 2018.

Our Production Facilities revenues increased by 3% for the six-month period ended June 30, 2018 as compared to the same period in 2017, primarily reflecting lower revenues from the HFRS retainer fees as a result of the Q4000 undergoing regulatory dry dock during the first half of 2017.

Gross Profit (Loss). Our total gross profit increased by 219% for the six-month period ended June 30, 2018 as compared to the same period in 2017 reflecting improvements across all business segments.

The gross profit related to our Well Intervention segment increased by 105% for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting positive operating results from our well intervention operations in the Gulf of Mexico and Brazil, offset in part by lower gross profit in the North Sea.

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The gross loss associated with our Robotics segment decreased by 40% for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting higher trenching revenues, increased utilization for our ROV support vessels and cost reductions.

The gross profit related to our Production Facilities segment increased by 9% for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting revenue increases for the HFRS and a reduction in operating costs.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses increased by $2.1 million for the six-month period ended June 30, 2018 as compared to the same period in 2017. The increase was primarily attributable to increased costs associated with our employee share-based compensation awards linked to our stock price (Note 11), partially offset by a $1.2 million charge during the first quarter of 2017 associated with the provision for uncertain collection of a portion of our receivables related to our Robotics segment.

Net Interest Expense. Our net interest expense decreased by $4.4 million for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting a decrease in interest expense due to a reduction in our overall debt levels, offset in party by a decrease in capitalized interest. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $7.6 million for the six-month period ended June 30, 2018 as compared to $8.7 million for the same period in 2017 as a result of the completion of the Siem Helix 1 and Siem Helix 2 vessels during 2017.

Loss on Extinguishment of Long-Term Debt. The $1.2 million loss for the six-month period ended June 30, 2018 was attributable to the write-off of the unamortized debt issuance costs related to the prepayment of $61 million of the Term Loan in March 2018 and costs associated with our repurchase of $59.3 million in aggregate principal amount of the 2032 Notes (Note 6). 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 certain lenders exiting from our then outstanding term loan prior to its June 2017 amendment and restatement.

Other Expense, Net. Other expense, net increased by $2.4 million for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting a $1.1 million other than temporary loss on a note receivable (Note 3) and a $0.9 million increase in foreign currency transaction losses. Net other expense for the six-month periods ended June 30, 2018 and 2017 also included net gains of $0.1 million and $0.5 million, respectively, associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 15).

Income Tax Provision. Income tax provision was $0.4 million for the six-month period ended June 30, 2018. Excluding a $6.3 million tax charge in 2017 attributable to a change in tax position related to our foreign taxes, we had an income tax benefit of $5.9 million for the six-month period ended June 30, 2017. The variance in our income taxes (excluding the 2017 tax charge) primarily reflects increased profitability in the current year period. The effective tax rate was 2.5% for the six-month period ended June 30, 2018 as compared to (1.9)% for the same period in 2017. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, the reduction of the U.S. corporate tax rate from 35% to 21% as a result of the 2017 Tax Act, and the tax charge in 2017 (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, 2018		December 31, 2017

Net working capital	$	298,375	$	186,004
Long-term debt ⁽¹⁾	412,852		385,766
Liquidity ⁽²⁾	435,109		348,207


(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. Long-term debt 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 that facility. Our liquidity at June 30, 2018 included cash and cash equivalents of $288.5 million (including a minimum cash balance of $50 million as required by our Credit Agreement) and $146.6 million of available borrowing capacity under our Revolving Credit Facility (Note 6). Our liquidity at December 31, 2017 included cash and cash equivalents of $266.6 million and $81.6 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, 2018		December 31, 2017

Term Loan (matures June 2020)	$	35,068	$	95,842
Nordea Q5000 Loan (matures April 2020)	141,455		158,930
MARAD Debt (matures February 2027)	69,505		72,487
2022 Notes (mature May 2022) ⁽¹⁾	110,486		108,829
2023 Notes (mature September 2023) ⁽²⁾	102,489		—
2032 Notes (redeemed May 2018)	—		59,539
Total debt	$	459,003	$	495,627


(1)	The 2022 Notes will increase to their face amount through accretion of the debt discount through May 1, 2022.


(2)	The 2023 Notes will increase to their face amount through accretion of the debt discount through September 15, 2023.

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



	Six Months Ended June 30,
	2018			2017
Cash provided by (used in):
Operating activities	$	87,666		$	15,601
Investing activities	(41,969		)	(84,396		)
Financing activities	(22,963		)	101,623

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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 continue to remain 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, internally generated cash flows and available borrowing capacity under our Revolving Credit Facility will be sufficient to fund our operations over at least the next 12 months.

In accordance with our Credit Agreement, the 2022 Notes, the 2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of a 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, 2018 and December 31, 2017, 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 fully access our Revolving Credit Facility may be impacted. At June 30, 2018, our available borrowing capacity under our Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $146.6 million, net of $3.4 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrow under our Revolving Credit Facility other than for the issuance of letters of credit. Our ability to comply with loan agreement 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 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 2023 Notes can be converted into our common stock by the holders or redeemed by us prior to their stated maturity under certain circumstances specified in the applicable indenture governing the notes. We can settle any conversion in cash, shares of our common stock or a combination thereof.

We repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018 and redeemed the remaining $0.8 million on May 4, 2018.

Operating Cash Flows

Total cash flows from operating activities increased by $72.1 million for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting improvements in our operations and collection of accounts receivable as well as reductions in interest payments.

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Investing Activities

Capital expenditures represent cash paid principally for the acquisition, construction, upgrade, modification and refurbishment of long-lived property and equipment such as dynamically positioned vessels, topside equipment and subsea systems. Capital expenditures also include interest on those property and equipment under development. Significant sources (uses) of cash associated with investing activities are as follows (in thousands):



	Six Months Ended June 30,
	2018			2017
Capital expenditures:
Well Intervention	$	(41,756	)	$	(94,048	)
Robotics	(64		)	(262		)
Production Facilities	(104		)	—
Other	(45		)	(86		)
Proceeds from sale of assets ⁽¹⁾	—			10,000
Net cash used in investing activities	$	(41,969	)	$	(84,396	)


(1)	Reflects cash received from the sale of our former spoolbase facility located in Ingleside, Texas.

Our capital expenditures have primarily 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 that we charter to perform our agreements with Petrobras (see below).

In September 2013, we executed a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, including the third amendment that was entered into in November 2017, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% was paid in December 2017, 20% is to be paid on December 31, 2018, and 20% is to be paid upon the delivery of the vessel, which at our option can be deferred until December 31, 2019. We are also contractually committed to reimburse the shipyard for its costs in connection with the deferment of the Q7000’s delivery beyond 2017. At June 30, 2018, our total investment in the Q7000 was $314.9 million, including $207.6 million of installment payments to the shipyard. Currently equipment is being manufactured and installed for the completion of the vessel. We plan to incur approximately $86 million related to the Q7000 over the remainder of 2018, including a scheduled shipyard payment of $69.2 million in December 2018.

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 options to extend by agreement of the parties. In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two monohull vessels, the Siem Helix 1, which commenced operations for Petrobras in mid-April 2017, and the Siem Helix 2, which commenced operations for Petrobras in mid-December 2017.

Financing Activities

Cash flows from financing activities consist primarily of proceeds from debt and equity transactions and repayments of our long-term debt. Total cash flows from financing activities decreased by $124.6 million for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily reflecting net proceeds of approximately $220 million we received from our underwritten public equity offering in January 2017, offset in part by a decrease in debt repayments during the first half of 2018 as compared to the same period in 2017.

Free Cash Flow

Free cash flow increased by $114.5 million for the six-month period ended June 30, 2018 as compared to the same period in 2017 primarily attributable to higher operating cash flows in the first half of 2018 as well as reduced capital expenditures as a result of the completion of the Siem Helix 1 and Siem Helix 2 vessels during 2017.

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Outlook

We anticipate that our capital expenditures and deferred dry dock costs for 2018 will approximate $135 million. We believe that our cash on hand, internally generated cash flows and availability under our Revolving Credit Facility will provide the capital necessary to continue funding our 2018 capital obligations and to meet our debt obligations due in 2018. 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, 2018 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	$	35,564	$	3,744	$	31,820	$	—	$	—
Nordea Q5000 Loan	142,857		35,714		107,143		—		—
MARAD Debt	73,774		6,693		14,405		15,879		36,797
2022 Notes ⁽²⁾	125,000		—		—		125,000		—
2023 Notes ⁽³⁾	125,000		—		—		—		125,000
Interest related to debt ⁽⁴⁾	80,495		23,153		33,781		19,035		4,526
Property and equipment ⁽⁵⁾	157,133		87,344		69,789		—		—
Operating leases ⁽⁶⁾	516,458		122,127		207,893		166,029		20,409
Total cash obligations	$	1,256,281	$	278,775	$	464,831	$	325,943	$	186,732


(1)	Excludes unsecured letters of credit outstanding at June 30, 2018 totaling $3.4 million. These letters of credit may be issued to support various obligations, such as contractual obligations, 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 the conversion price on that 30th trading day (i.e., $18.06 per share). At June 30, 2018, the conversion trigger was not met. See Note 6 for additional information.

(3)

Notes mature September 2023. The 2023 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 the conversion price on that 30th trading day (i.e., $12.31 per share). At June 30, 2018, the conversion trigger was not met. 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, 2018 for variable rate debt.


(5)	Primarily reflects costs associated with our Q7000 semi-submersible well intervention vessel currently under construction (Note 13).


(6)	Operating leases include vessel charters and facility leases. At June 30, 2018, our vessel charter commitments totaled approximately $478.4 million.

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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.

Revenue from Contracts with Customers

Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer.

Revenue for lump sum contracts is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified.

For additional information regarding our critical accounting policies and estimates, please read our “Critical Accounting Policies and Estimates” as disclosed in our 2017 Form 10-K.

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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, 2018, $178.4 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 a portion of our Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. As of June 30, 2018, $107.1 million of our Nordea Q5000 Loan was hedged. Debt subject to variable rates after considering hedging activities was $71.3 million. 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 $0.5 million in interest expense for the six-month period ended June 30, 2018.

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 impacted by 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 may not be 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, 2018, we recognized gains of $1.4 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 February 2013, we entered into foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II and Grand Canyon III charter payments denominated in Norwegian kroner through July 2019 and February 2020, respectively. A portion of these foreign currency exchange contracts currently qualifies for cash flow hedge accounting treatment. There was no foreign currency hedge ineffectiveness for the six-month period ended June 30, 2018.

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, 2018. 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, 2018 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, 2018 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 13 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, 2018	—	$	—	—	3,731,656
May 1 to May 31, 2018	—	—		—	3,758,295
June 1 to June 30, 2018	—	—		—	3,758,295
	—	$	—	—


(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 under our ESPP to participating employees (Note 11), increases the amount of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 9 to our 2017 Form 10-K.

Item 6. Exhibits



Exhibit Number	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 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.	Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (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.	Filed herewith
101.SCH	XBRL Schema Document.	Filed herewith
101.CAL	XBRL Calculation Linkbase Document.	Filed herewith
101.PRE	XBRL Presentation Linkbase Document.	Filed herewith
101.DEF	XBRL Definition Linkbase Document.	Filed herewith
101.LAB	XBRL Label Linkbase Document.	Filed herewith

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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, 2018	By:	/s/ Owen Kratz
			Owen Kratz President and Chief Executive Officer (Principal Executive Officer)

Date:	July 25, 2018	By:	/s/ Erik Staffeldt
			Erik Staffeldt Senior Vice President and Chief Financial Officer (Principal Financial Officer)