~~UNITED STATES~~

~~SECURITIES AND EXCHANGE COMMISSION~~

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

~~[X]~~

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

For the quarterly period ended March 31, 2015

			~~For the quarterly period ended September 30, 2014~~
	or
~~[ ]~~¨		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from__________ to__________

Commission File Number 001-32936

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)



Minnesota (State or other jurisdiction of incorporation or organization)		95–3409686 (I.R.S. Employer Identification No.)

3505 West Sam Houston Parkway North Suite 400 Houston, Texas (Address of principal executive offices)		77043 (Zip Code)

(281) 618–0400

(Registrant's telephone number, including area code)

NOT APPLICABLE

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.þYes ¨No

~~Yes~~

~~[ √ ]~~

~~[ ]~~

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).þYes ¨No

~~Yes~~

~~[ √ ]~~

~~[ ]~~

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated ~~filer“~~filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ~~[ √ ]~~þ	Accelerated filer ~~[ ]~~¨	Non-accelerated filer ~~[ ]~~¨	Smaller reporting company ~~[ ]~~¨
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).¨

~~Yes~~

~~[ ]~~

~~[ √ ]~~

Yes þNo

As of ~~October~~April 17, ~~2014, 105,537,973~~2015, 105,913,805 shares of common stock were outstanding.

~~TABLE OF~~ ~~CONTENTS~~

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION		PAGE

Item 1.	Financial Statements:

	Condensed Consolidated Balance Sheets – ~~September 30, 2014~~March 31, 2015 (Unaudited) and December 31, ~~2013~~2014		3

	Condensed Consolidated Statements of Operations (Unaudited) – Three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		4
	~~Condensed Consolidated Statements of Operations (Unaudited) –~~ ~~Nine months ended September 30, 2014 and 2013~~		5
	Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) – Three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		65

	Condensed Consolidated Statements of Cash Flows (Unaudited) – ~~Nine~~Three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		76

	Notes to Condensed Consolidated Financial Statements (Unaudited)	7

Item 2.	8
~~Item 2.~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	26
~~Item 3.~~	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	41
~~Item 4.~~	Controls and Procedures	37
	41
PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 2.	42
~~Item 2.~~	Unregistered Sales of Equity Securities and Use of Proceeds	38
	42
Item 6.	Exhibits		4238
	~~Signatures~~
	43Signatures	39

	Index to Exhibits		4440

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)


	September 30,			December 31,
	2014			2013			March 31, 2015			December 31, 2014
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	546,529		$	478,200		$	415,302		$	476,492
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $5,971 and $2,234, respectively		125,718			156,925
Trade, net of allowance for uncollectible accounts of $5,160 and $4,735, respectively							108,377			104,724
Unbilled revenue		71,366			25,732		39,324			28,542
Costs in excess of billing		11,111			1,508		776			2,034
Current deferred tax assets		26,342			51,573		23,477			31,180
Other current assets		48,006			29,709		33,016			51,301
Total current assets		829,072			743,647		620,272			694,273
Property and equipment		2,129,058			1,963,706		2,287,411			2,241,444
Less accumulated depreciation		(488,871	)		(431,489	)	(527,033		)	(506,060		)
Property and equipment, net		1,640,187			1,532,217		1,760,378			1,735,384
Other assets:
Equity investments		152,588			157,919		148,147			149,623
Goodwill		62,839			63,230		61,336			62,146
Other assets, net		60,270			47,267		58,191			59,272
Total assets	$	2,744,956		$	2,544,280		$	2,648,324		$	2,700,698

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	117,280		$	72,602		$	80,106		$	83,403
Accrued liabilities		85,969			96,482		70,774			104,923
Income tax payable		25,588			760		3,333			9,143
Current maturities of long-term debt		24,394			20,376		32,033			28,144
Total current liabilities		253,231			190,220		186,246			225,613
Long-term debt		529,281			545,776		514,265			523,228
Deferred tax liabilities		267,409			265,879		247,050			260,275
Other non-current liabilities		17,592			18,295		45,753			38,108
Total liabilities		1,067,513			1,020,170		993,314			1,047,224

Commitments and contingencies
Shareholders' equity:
Common stock, no par, 240,000 shares authorized, 105,531 and 105,640 shares issued, respectively		936,922			933,507
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 105,904 and 105,586 shares issued, respectively							936,735			934,447
Retained earnings		773,319			586,232		800,921			781,279
Accumulated other comprehensive loss		(32,798	)		(20,688	)	(82,646		)	(62,252		)
Total controlling interest shareholders' equity		1,677,443			1,499,051
Noncontrolling interests		—			25,059
Total equity		1,677,443			1,524,110
Total liabilities and shareholders' equity	$	2,744,956		$	2,544,280
Total shareholders’ equity							1,655,010			1,653,474
Total liabilities and shareholders’ equity							$	2,648,324		$	2,700,698

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)



	Three Months Ended March 31,
	2015			2014

Net revenues	$	189,641		$	253,572
Cost of sales	154,694			177,726
Gross profit	34,947			75,846
Gain on disposition of assets, net	—			11,496
Selling, general and administrative expenses	(12,619		)	(20,394		)
Income from operations	22,328			66,948
Equity in earnings of investments	21			708
Net interest expense	(4,070		)	(4,483		)
Other expense, net	(1,156		)	(810		)
Other income – oil and gas	2,926			12,276
Income before income taxes	20,049			74,639
Income tax provision	407			20,417
Net income, including noncontrolling interests	19,642			54,222
Less net income applicable to noncontrolling interests	—			(503		)
Net income applicable to common shareholders	$	19,642		$	53,719

Earnings per share of common stock:
Basic	$	0.19		$	0.51
Diluted	$	0.19		$	0.51

Weighted average common shares outstanding:
Basic	105,290			105,126
Diluted	105,290			105,375

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~OPERATIONS~~COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in ~~thousands, except per share amounts)~~thousands)

Three Months Ended
September 30,
2014 2013

Net revenues $ 340,837 $ 220,117
Cost of sales 214,590 150,660

Gross profit 126,247 69,457

Gain on disposition of assets — 15,812
Selling, general and administrative expenses (19,916 ) (22,610 )
Income from operations 106,331 62,659
Equity in earnings of investments 508 857
Net interest expense (3,856 ) (6,585 )
Loss on early extinguishment of long-term debt — (8,572 )
Other income, net 598 2,366
Other income – oil and gas 1,837 1,681
Income before income taxes 105,418 52,406
Income tax provision 29,832 7,058
Net income from continuing operations 75,586 45,348
Income from discontinued operations, net of tax — 44
Net income, including noncontrolling interests 75,586 45,392
Less net income applicable to noncontrolling interests — (799 )
Net income applicable to Helix $ 75,586 $ 44,593

Basic earnings per share of common stock:
Continuing operations $ 0.72 $ 0.42
Discontinued operations — —
Net income per common share $ 0.72 $ 0.42

Diluted earnings per share of common stock:
Continuing operations $ 0.71 $ 0.42
Discontinued operations — —
Net income per common share $ 0.71 $ 0.42

Weighted average common shares outstanding:
Basic 104,997 105,029
Diluted 105,338 105,136



	Three Months Ended March 31,
	2015			2014

Net income, including noncontrolling interests	$	19,642		$	54,222
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on hedges arising during the period	(11,711		)	4,055
Reclassification adjustments for loss included in net income	1,673			658
Income taxes on unrealized (gain) loss on hedges	3,513			(1,650		)
Unrealized gain (loss) on hedges, net of tax	(6,525		)	3,063
Foreign currency translation gain (loss)	(13,869		)	1,347
Other comprehensive income (loss), net of tax	(20,394		)	4,410
Comprehensive income (loss)	(752		)	58,632
Less comprehensive income applicable to noncontrolling interests	—			(503		)
Comprehensive income (loss) applicable to common shareholders	$	(752	)	$	58,129

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~OPERATIONS~~CASH FLOWS

(UNAUDITED)

(in ~~thousands, except per share amounts)~~thousands)

Nine Months Ended
September 30,
2014 2013

Net revenues $ 899,996 $ 649,724
Cost of sales 588,765 460,203

Gross profit 311,231 189,521

Loss on commodity derivative contracts — (14,113 )
Gain on disposition of assets, net 10,418 14,727
Selling, general and administrative expenses (69,614 ) (65,041 )
Income from operations 252,035 125,094
Equity in earnings of investments 709 2,150
Net interest expense (12,856 ) (28,252 )
Loss on early extinguishment of long-term debt — (12,100 )
Other expense, net (229 ) (1,884 )
Other income – oil and gas 15,709 5,781
Income before income taxes 255,368 90,789
Income tax provision 67,778 16,078
Net income from continuing operations 187,590 74,711
Income from discontinued operations, net of tax — 1,073
Net income, including noncontrolling interests 187,590 75,784
Less net income applicable to noncontrolling interests (503 ) (2,365 )
Net income applicable to Helix $ 187,087 $ 73,419

Basic earnings per share of common stock:
Continuing operations $ 1.77 $ 0.68
Discontinued operations — 0.01
Net income per common share $ 1.77 $ 0.69

Diluted earnings per share of common stock:
Continuing operations $ 1.77 $ 0.68
Discontinued operations — 0.01
Net income per common share $ 1.77 $ 0.69

Weighted average common shares outstanding:
Basic 105,038 105,036
Diluted 105,374 105,152



	Three Months Ended March 31,
	2015			2014
Cash flows from operating activities:
Net income, including noncontrolling interests	$	19,642		$	54,222
Adjustments to reconcile net income, including noncontrolling interests, to net cash provided by (used in) operating activities:
Depreciation and amortization	26,089			24,726
Amortization of deferred financing costs	1,218			1,218
Stock-based compensation expense	1,754			1,811
Amortization of debt discount	1,464			1,397
Deferred income taxes	(1,114		)	33,407
Excess tax from stock-based compensation	(260		)	(619		)
Gain on disposition of assets, net	—			(11,496		)
Unrealized loss and ineffectiveness on derivative contracts, net	2,181			68
Changes in operating assets and liabilities:
Accounts receivable, net	(14,917		)	(5,527		)
Other current assets	17,843			(7,122		)
Income tax payable	(5,322		)	(26,106		)
Accounts payable and accrued liabilities	(48,718		)	(14,385		)
Other noncurrent, net	(2,403		)	(2,757		)
Net cash provided by (used in) operating activities	(2,543		)	48,837

Cash flows from investing activities:
Capital expenditures	(52,524		)	(37,991		)
Distributions from equity investments, net	1,379			2,092
Proceeds from sale of assets	—			11,074
Acquisition of noncontrolling interests	—			(20,085		)
Net cash used in investing activities	(51,145		)	(44,910		)

Cash flows from financing activities:
Repayment of term loans	(3,750		)	(3,750		)
Repayment of MARAD borrowings	(2,788		)	(2,655		)
Distributions to noncontrolling interests	—			(1,018		)
Repurchases of common stock	(1,026		)	(5,449		)
Excess tax from stock-based compensation	260			619
Proceeds from issuance of ESPP shares	1,299			942
Net cash used in financing activities	(6,005		)	(11,311		)

Effect of exchange rate changes on cash and cash equivalents	(1,497		)	(737		)
Net decrease in cash and cash equivalents	(61,190		)	(8,121		)
Cash and cash equivalents:
Balance, beginning of year	476,492			478,200
Balance, end of period	$	415,302		$	470,079

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~(UNAUDITED)~~

~~(in thousands)~~

Three Months Ended
September 30,
2014 2013

Net income, including noncontrolling interests $ 75,586 $ 45,392
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on hedges arising during the period (9,209 ) 1,117
Reclassification adjustments for loss included in net income 812 396
Income taxes on unrealized (gain) loss on hedges 2,939 (529 )
Unrealized gain (loss) on hedges, net of tax (5,458 ) 984
Foreign currency translation gain (loss) (15,706 ) 11,311
Other comprehensive income (loss), net of tax (21,164 ) 12,295
Comprehensive income 54,422 57,687
Less comprehensive income applicable to noncontrolling interests — (799 )
Comprehensive income applicable to Helix $ 54,422 $ 56,888

Nine Months Ended
September 30,
2014 2013

Net income, including noncontrolling interests $ 187,590 $ 75,784
Other comprehensive loss, net of tax:
Unrealized loss on hedges arising during the period (9,283 ) (16,050 )
Reclassification adjustments for loss included in net income 2,080 900
Income taxes on unrealized loss on hedges 2,521 5,303
Unrealized loss on hedges, net of tax (4,682 ) (9,847 )
Foreign currency translation gain (loss) (7,428 ) 12
Other comprehensive loss, net of tax (12,110 ) (9,835 )
Comprehensive income 175,480 65,949
Less comprehensive income applicable to noncontrolling interests (503 ) (2,365 )
Comprehensive income applicable to Helix $ 174,977 $ 63,584

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

~~Table of Contents~~

~~HELIX ENERGY~~ ~~SOLUTIONS GROUP, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(UNAUDITED)~~

~~(in thousands)~~

Nine Months Ended
September 30,
2014 2013
Cash flows from operating activities:
Net income, including noncontrolling interests $ 187,590 $ 75,784
Adjustments to reconcile net income, including noncontrolling interests, to net cash provided by (used in) operating activities:
Income from discontinued operations, net of tax — (1,073 )
Depreciation and amortization 81,274 71,542
Amortization of deferred financing costs 3,653 4,091
Stock-based compensation expense 5,711 7,297
Amortization of debt discount 4,149 3,850
Deferred income taxes 24,728 (23,911 )
Excess tax from stock-based compensation (120 ) (168 )
Gain on disposition of assets, net (10,418 ) (14,727 )
Loss on early extinguishment of debt — 12,100
Unrealized loss and ineffectiveness on derivative contracts, net 69 140
Changes in operating assets and liabilities:
Accounts receivable, net (16,496 ) 2,046
Other current assets (19,388 ) 7,904
Income tax payable 25,440 (37,806 )
Accounts payable and accrued liabilities 26,083 (46,313 )
Oil and gas asset retirement costs (956 ) (9,886 )
Other noncurrent, net (9,758 ) (561 )
Net cash provided by operating activities 301,561 50,309
Net cash used in discontinued operations — (30,503 )
Net cash provided by operating activities 301,561 19,806

Cash flows from investing activities:
Capital expenditures (204,528 ) (275,935 )
Distributions from equity investments, net 5,041 6,110
Proceeds from sale of assets 11,074 189,054
Acquisition of noncontrolling interests (20,085 ) —
Net cash used in investing activities (208,498 ) (80,771 )
Net cash provided by discontinued operations — 582,965
Net cash provided by (used in) investing activities (208,498 ) 502,194

Cash flows from financing activities:
Early extinguishment of Senior Unsecured Notes — (281,490 )
Borrowings under revolving credit facility — 47,617
Repayment of revolving credit facility — (147,617 )
Repurchase of Convertible Senior Notes due 2025 — (3,487 )
Proceeds from term loans — 300,000
Repayment of term loans (11,250 ) (370,931 )
Repayment of MARAD borrowings (5,376 ) (5,120 )
Deferred financing costs (3,143 ) (10,948 )
Distributions to noncontrolling interests (1,018 ) (3,059 )
Repurchases of common stock (8,538 ) (5,562 )
Excess tax from stock-based compensation 120 168
Exercise of stock options, net and other — 95
Proceeds from issuance of ESPP shares 3,223 2,711
Net cash used in financing activities (25,982 ) (477,623 )

Effect of exchange rate changes on cash and cash equivalents 1,248 (1,296 )
Net increase in cash and cash equivalents 68,329 43,081
Cash and cash equivalents:
Balance, beginning of year 478,200 437,100
Balance, end of period $ 546,529 $ 480,181

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

~~Table of Contents~~

~~HELIX ENERGY~~ ~~SOLUTIONS GROUP, INC. AND SUBSIDIARIES~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Basis of Presentation and ~~Recent~~New Accounting Standards

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

The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) and are consistent in all material respects with those applied in our ~~2013~~2014 Annual Report on Form 10-K (“~~2013~~2014 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. We have made all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) 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 nine-month periods~~three-month period ended ~~September 30, 2014~~March 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2014.~~2015. Our balance sheet as of December 31, ~~2013~~2014 included herein has been derived from the audited balance sheet as of December 31, ~~2013~~2014 included in our ~~2013~~2014 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our ~~2013~~2014 Form 10-K.

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

In May 2014, the ~~FASB~~Financial Accounting Standards Board (the “FASB”) issued ~~ASU~~Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU provides a single five-step approach to account for revenue arising from contracts with customers. The ASU requires ~~entities~~an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ~~This guidance~~The new revenue standard is currently effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods. Early adoption is not permitted. The guidance permits companies to either apply the requirements retrospectively to all prior periods presented, or apply the requirements in the year of adoption through a cumulative adjustment. We are currently evaluating which transition approach to use and the potential impact the adoption of this new standard may have on our consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This ASU requires that debt issuance costs related to a recognized debt liability be reported on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This guidance is effective retrospectively beginning in the first quarter of fiscal 2017 and early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial statements.

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Note 2 — Company Overview

~~Our Operations~~

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We seek to provide services and methodologies that we believe are critical to developing offshore reservoirs and maximizing production economics. We provide services primarily in deepwater in the Gulf of Mexico, North Sea, Asia Pacific and West Africa ~~regions.~~regions, and intend to increase our operations in offshore Brazil. Our “life of field” services are segregated into ~~four~~three reportable business segments: Well Intervention, Robotics ~~Subsea Construction~~ and Production Facilities (Note 11). Our ~~Subsea Construction~~Well Intervention segment ~~was significantly diminished~~includes our vessels and equipment used to perform well intervention services primarily in the Gulf of Mexico and North Sea regions. Our well intervention vessels include the Q4000, the Helix 534, the Seawell, the Well Enhancer and the Skandi Constructor, which is a chartered vessel. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills designed to complement offshore construction and well intervention services, and will operate five chartered ROV and trencher support vessels following the ~~sale~~delivery of ~~substantially all of our assets related to this reportable segment during 2013 and early 2014 (see Note 2 to our 2013 Form 10-K and Note 2 to our Quarterly Report on Form 10-Q for~~ the ~~three-month period ended March 31, 2014).~~Grand Canyon II in late April 2015. Our Production Facilities segment includes the Helix Producer I (“ vessel (“HP II””) ~~vessel (which we now own 100% after acquiring our minority partner’s noncontrolling interests in the entity that owns the vessel for $20.1 million in February 2014)~~ as well as our equity investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) (Note 5). The Production Facilities segment also includes the Helix Fast Response System (“HFRS”), which provides certain operators access to our Q4000 and HP I vessels in the event of a well control incident in the Gulf of Mexico.

~~Discontinued Operations~~

In February 2013, we sold Energy Resource Technology GOM, Inc. (“ERT”), a former wholly-owned U.S. subsidiary that conducted our oil and gas operations in the Gulf of Mexico, for $624 million plus additional consideration in the form of overriding royalty interests in ERT’s Wang well and certain exploration prospects. As a result, we have presented the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying condensed consolidated financial statements. See Note 3 to our 2013 Form 10-K for additional information regarding our discontinued operations and Note 6 regarding the use of a portion of the sale proceeds to reduce our indebtedness under our former credit agreement.

Note 3 — Details of Certain Accounts

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

September 30, December 31,
2014 2013

Note receivable (1)
$ 10,000 $ —
Other receivables 840 785
Prepaid insurance 9,613 7,038
Other prepaids 15,969 12,999
Spare parts inventory 2,429 1,038
Value added tax receivable 9,120 7,589
Other 35 260
Total other current assets $ 48,006 $ 29,709

September 30, December 31,
2014 2013

Note receivable (1)
$ 20,000 $ —
Deferred dry dock expenses, net 14,249 20,833
Deferred financing costs, net (Note 6) 24,077 24,297
Intangible assets with finite lives, net 654 622
Other 1,290 1,515
Total other assets, net $ 60,270 $ 47,267



	March 31, 2015		December 31, 2014

Note receivable ⁽¹⁾	$	10,000	$	17,500
Other receivables	613		423
Prepaid insurance	3,523		6,582
Other prepaids	8,631		15,541
Spare parts inventory	2,112		1,857
Value added tax receivable	8,046		9,326
Other	91		72
Total other current assets	$	33,016	$	51,301

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	March 31, 2015		December 31, 2014

Note receivable ⁽¹⁾	$	10,000	$	10,000
Deferred dry dock expenses, net	11,972		11,631
Deferred financing costs, net (Note 6)	22,278		23,399
Intangible assets with finite lives, net	710		696
Charter fee deposit (Note 12)	12,544		12,544
Other	687		1,002
Total other assets, net	$	58,191	$	59,272

(1)

Relates to the remaining balance of the promissory note we received in connection with the sale of our Ingleside spoolbase in January 2014. Interest on the note is payable quarterly at a rate of 6% per annum. ~~A $10~~Under the terms of the note, the remaining $20 million principal ~~reduction~~balance is required to be paid with a $10 million payment on ~~each~~ December 31 of ~~2014,~~ 2015 and ~~2016.~~2016, respectively.

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Accrued liabilities consist of the following (in thousands):


	September 30,		December 31,
	2014		2013		March 31, 2015		December 31, 2014

Accrued payroll and related benefits	$	55,613	$	50,527	$	28,561	$	61,246
Current asset retirement obligations		742		2,024	554		575
Unearned revenue		6,490		19,608	7,653		11,461
Billing in excess of cost		—		1,677
Accrued interest		1,362		4,187	1,952		4,221
Derivative liability (Note 15)		5,917		2,651
Derivative liability (Note 14)					17,491		13,222
Taxes payable excluding income tax payable		7,918		4,811	6,263		6,236
Pipelay assets sale deposit		—		5,000
Other		7,927		5,997	8,300		7,962
Total accrued liabilities	$	85,969	$	96,482	$	70,774	$	104,923

Note 4 — Statement of Cash Flow Information

We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less. The following table provides supplemental cash flow information (in thousands):


	Nine Months Ended
	September 30,				Three Months Ended March 31,
	2014		2013		2015		2014

Interest paid, net of interest capitalized	$	11,671	$	39,754	$	4,124	$	4,635
Income taxes paid	$	53,390	$	78,408	$	7,181	$	13,118

Our non-cash investing activities include accruals for property and equipment capital expenditures. These non-cash investing accruals totaled ~~$21.3~~$17.5 million and ~~$9.5~~$14.1 million as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively. Additionally, our investing activities for the three-month period ended March 31, 2014 included a $30 million ~~of our~~ non-cash ~~investing activities relates~~transaction related to the promissory note we received in connection with the sale of our Ingleside spoolbase in January 2014 (Note 3).

Note 5 — Equity Investments

As of ~~September 30, 2014,~~March 31, 2015, we had two investments that we account for using the equity method of accounting: Deepwater Gateway and Independence Hub, both of which are included in our Production Facilities segment.

Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, each with a 50% interest, to design, construct, install, own and operate a tension leg platform production hub primarily for Anadarko Petroleum ~~Corporation's~~Corporation’s Marco Polofield in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled ~~$82.4~~$80.1 million and ~~$85.8~~$80.9 million as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively (including net capitalized interest of $1.2 million ~~and $1.3 million~~ at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively).

Independence Hub, LLC. In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise. Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. Our investment in Independence Hub was ~~$70.2~~$68.0 million and ~~$72.1~~$68.8 million as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively (including capitalized interest of ~~$4.0 million and $4.3~~$3.9 million at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively).

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We received the following distributions from ~~these~~our equity method investments (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,				Three Months Ended March 31,
	2014		2013		2014		2013		2015		2014

Deepwater Gateway	$	500	$	1,600	$	4,250	$	5,100	$	1,000	$	2,000
Independence Hub		200		800		1,500		3,160	400		800
Total	$	700	$	2,400	$	5,750	$	8,260	$	1,400	$	2,800

Note 6 —Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of ~~September 30, 2014~~March 31, 2015 are as follows (in thousands):


	Term Loan			MARAD Debt			2032 Notes (1)			Total			Term Loan			MARAD Debt			2032 Notes ⁽¹⁾			Total

Less than one year	$	18,750		$	5,644		$	—		$	24,394		$	26,250		$	5,783		$	—		$	32,033
One to two years		30,000			5,926			—			35,926		30,000			6,072			—			36,072
Two to three years		30,000			6,222			—			36,222		30,000			6,375			—			36,375
Three to four years		30,000			6,532			—			36,532		187,500			6,693			—			194,193
Four to five years		172,500			6,858			—			179,358		—			7,027			—			7,027
Over five years		—			63,610			200,000			263,610		—			60,054			200,000			260,054
Total debt		281,250			94,792			200,000			576,042		273,750			92,004			200,000			565,754
Current maturities		(18,750	)		(5,644	)		—			(24,394	)	(26,250		)	(5,783		)	—			(32,033		)
Long-term debt, less current maturities		262,500			89,148			200,000			551,648		247,500			86,221			200,000			533,721
Unamortized debt discount (2)		—			—			(22,367	)		(22,367	)	—			—			(19,456		)	(19,456		)
Long-term debt	$	262,500		$	89,148		$	177,633		$	529,281		$	247,500		$	86,221		$	180,544		$	514,265


(1)	Beginning in March 2018, the holders of our Convertible Senior Notes due 2032 may require us to repurchase these notes or we may at our option elect to repurchase these notes. The notes will mature in March 2032.


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

Included below is a summary of certain components of our indebtedness:

Credit Agreement

In June 2013, we entered into a ~~Credit Agreement~~credit agreement (the “Credit Agreement”) with a group of lenders pursuant to which we borrowed $300 million under the Credit Agreement’s term loan (the “Term Loan”) ~~component~~ and, subject to the terms of the Credit Agreement, may borrow ~~revolving loans~~additional amounts (the “Revolving Loans”) and/or obtain letters of credit under a revolving credit facility (the “Revolving Credit Facility”) up to an outstanding amount of $600 ~~million (the “Revolving Credit Facility”).~~million. Subject to ~~customary conditions,~~lender participation, we may request an increase of up to $200 million in aggregate commitments with respect to the Revolving Credit Facility, additional term loans or a combination thereof. ~~The $300 million we borrowed~~At March 31, 2015, our availability under the ~~Term Loan was in connection with our early redemption~~Revolving Credit Facility totaled $583.7 million, net of ~~the remaining $275~~$16.3 million ~~Senior Unsecured Notes outstanding in July 2013 (see “Senior Unsecured Notes” below).~~of letters of credit issued.

The Term Loan and the Revolving Loans (together, the “Loans”) ~~will~~ bear interest, at our election, in relation to either the base rate established by Bank of America N.A. or to a LIBOR rate, provided that all Swing Line Loans (as defined in the Credit Agreement) will be base rate loans. The Term Loan currently bears interest at the one-month LIBOR rate plus 2.25%. In September 2013, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on $148.1 million of the Term Loan. The fixed LIBOR rates were between 74 and 75 basis points.

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The Loans or portions thereof bearing interest at the base rate ~~will~~ bear interest at a per annum rate equal to the base rate plus a margin ranging from 1.00% to 2.00%. The Loans or portions thereof bearing interest at a LIBOR rate ~~will~~ bear interest at the LIBOR rate selected by us plus a margin ranging from 2.00% to 3.00%. A letter of credit fee is payable by us equal to our applicable margin for LIBOR rate Loans multiplied by the daily amount available to be drawn under outstanding letters of credit. Margins on the Loans will vary in relation to the consolidated coverage ratio, as provided by the Credit Agreement. We currently also pay a fixed commitment fee of 0.375% on the unused portion of our Revolving Credit Facility. AtThe Term Loan currently bears interest at the one-month LIBOR rate plus 2.25%. In September ~~30, 2014, our availability under~~2013, we entered into various interest rate swap contracts to fix the ~~Revolving Credit Facility totaled $583.2 million, net of $16.8~~one-month LIBOR rate on $148.1 million of ~~letters of credit issued.~~the Term Loan. The fixed LIBOR rates are between 74 and 75 basis points.

The Term Loan is repayable in scheduled principal installments of 5% in each of the initial two loan years ($15 million per year), and 10% in each of the remaining three loan years ($30 million per year), payable quarterly, with a balloon payment of $180 million at maturity. These installment amounts are subject to adjustment for any prepayments on the Term Loan. We may elect to prepay amounts outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay amounts outstanding under the Revolving Loans without premium or penalty, and may reborrow any ~~available~~ amounts paid up to the amount of the Revolving Credit Facility. The Loans mature on June 19, 2018. In certain circumstances, we will be required to prepay the Loans.

The Credit Agreement and the other documents entered into in connection with the Credit Agreement (together, the “Loan Documents”) include terms and conditions, including covenants, which we consider customary for this type of transaction. The covenants include restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and incur capital expenditures. In addition, the Credit Agreement obligates us to meet certain financial ratios, including the Consolidated Interest Coverage Ratio and the Consolidated Leverage Ratio (as defined in the Credit Agreement). We have designated five of our foreign subsidiaries, and may designate any newly established foreign subsidiaries, as subsidiaries that are not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”), provided we meet certain liquidity requirements, in which case EBITDA of the Unrestricted Subsidiaries is not included in the calculations with respect to our financial covenants. Our obligations under the Credit Agreement are guaranteed by our ~~wholly-owned~~wholly owned domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited. Our obligations under the Credit Agreement, and of the guarantors under their guaranty, are secured by most of our assets and assets of the guarantors and Canyon Offshore Limited, plus pledges of up to two-thirds of the shares of certain foreign subsidiaries.

Convertible Senior Notes Due 2032

In March 2012, we completed a public offering and sale of ~~$200.0~~$200 million in aggregate principal amount of ~~3.25%~~ Convertible Senior Notes due 2032 (the “2032 Notes”). The net proceeds from the issuance of the 2032 Notes were $195.0 million after deducting the underwriter’s discounts and commissions and offering expenses. We used the net proceeds to repurchase and retire $142.2 million of aggregate principal amount of our 3.25% Convertible Senior Notes due 2025 in separate, privately negotiated transactions (see Note 7 to our 2013 Form 10-K for additional information). The remaining net proceeds were used for general corporate purposes, including the repayment of other indebtedness.

The 2032 Notes bear interest at a rate of 3.25% per annum, and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012. The 2032 Notes will mature on March 15, 2032 unless earlier converted, redeemed or repurchased. The 2032 Notes are convertible in certain circumstances and during certain periods at an initial conversion rate of 39.9752 shares of common stock per $1,000 principal amount (which represents an initial conversion price of approximately $25.02 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2032 Notes.

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We have the right and the intention to settle any such future conversions in cash.

Prior to March 20, 2018, the 2032 Notes are not redeemable. On or after March 20, 2018, we, at our option, may redeem some or all of the 2032 Notes in cash, at any time upon at least 30 days’ notice, at a price equal to 100% of the principal amount plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the redemption date. In addition, the holders of the 2032 Notes may

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require us to purchase in cash some or all of their 2032 Notes at a repurchase price equal to 100% of the principal amount of the 2032 Notes, plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022 and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a fundamental change (as defined in the Indenture governing the 2032 Notes).

In connection with the issuance of the 2032 Notes, we recorded a discount of $35.4 million as required under existing accounting rules. To arrive at this discount amount, we estimated the fair value of the liability component of the 2032 Notes as of the date of their issuance (March 12, 2012) using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 6.0 years. In selecting the expected life, we selected the earliest date ~~upon which~~ the holders could require us to repurchase all or a portion of the 2032 Notes (March 15, 2018). The effective interest rate for the 2032 Notes is 6.9% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2032 Notes at their inception. As of March 31, 2015, the carrying amount of the equity component of the 2032 Notes was $22.5 million.

MARAD Debt

This U.S. government guaranteed financing (the “MARAD Debt”) is pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, and was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures in February 2027. The MARAD Debt is collateralized by the Q4000, is guaranteed 50% by us, and initially bore interest at a floating rate that approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date.

Nordea Credit Agreement

In September 2014, ~~our wholly-owned~~a wholly owned subsidiary incorporated in Luxembourg, Helix Q5000 Holdings S.à r.l. (“Q5000 Holdings”), entered into a ~~Credit Agreement~~credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Term Loan”) in an amount of up to $250 million. The Nordea Term Loan will be funded at or near the time of the delivery of the Q5000, which is currently estimated in ~~early~~the second quarter of 2015. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., also a wholly owned Luxembourg subsidiary, has guaranteed the Nordea Term Loan. The loan will be secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is nonrecourse to Helix.

The Nordea Term Loan will bear interest at a LIBOR rate plus a margin of 2.5%, with an undrawn fee of 0.875%. The Nordea Term Loan matures five years after funding and is repayable in scheduled principal installments of $8.9 million, payable quarterly, with a balloon payment of $80.4 million at maturity. Installment amounts are subject to adjustment for any prepayments on this debt. Q5000 Holdings may elect to prepay amounts outstanding under the Nordea Term Loan without premium or penalty, but may not reborrow any amounts prepaid. In certain circumstances, Q5000 Holdings will be required to prepay the loan.

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

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~~Former Credit Facility~~

Similar to our current Credit Agreement, our former credit facility contained both term loan and revolving loan components. This indebtedness was scheduled to mature on July 1, 2015. In February 2013, we repaid $318.4 million of borrowings outstanding under this former credit facility with the proceeds from the sale of ERT. We fully repaid the remaining indebtedness outstanding under this credit facility in June 2013. In connection with the repayments of this debt, we recorded charges totaling $3.5 million to accelerate a pro rata portion of the deferred financing costs associated with our former term loan debt. This charge is reflected as a component of “Loss on early extinguishment of long-term debt” in the accompanying condensed consolidated statement of operations for the nine-month period ended September 30, 2013.

~~Senior Unsecured Notes~~

In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (the “Senior Unsecured Notes”). We had $275 million of the Senior Unsecured Notes outstanding at the beginning of 2013. We fully redeemed these notes in July 2013 (see Note 7 to our 2013 Form 10-K). Our results of operations for the three- and nine-month periods ended September 30, 2013 included a loss on early extinguishment of debt totaling $8.6 million in connection with the redemption of these notes.

Other

Unamortized deferred financing costs are included in “Other assets, net” in the accompanying condensed consolidated balance sheets and are amortized over the life of the respective debt agreements. The following table reflects the components of our deferred financing costs (in thousands):

September 30, 2014 December 31, 2013
Gross Carrying Amount Accumulated Amortization Net Gross Carrying Amount Accumulated Amortization Net

Term Loan (matures June 2018) (1)
$ 3,638 $ (909 ) $ 2,729 $ 3,638 $ (364 ) $ 3,274
Revolving Credit Facility (matures June 2018) (1)
13,275 (3,319 ) 9,956 13,275 (1,327 ) 11,948
2032 Notes (mature March 2032) 3,759 (1,609 ) 2,150 3,759 (1,148 ) 2,611
MARAD Debt (matures February 2027) 12,200 (6,101 ) 6,099 12,200 (5,736 ) 6,464
Nordea Term Loan 3,143 — 3,143 — — —
Total deferred financing costs $ 36,015 $ (11,938 ) $ 24,077 $ 32,872 $ (8,575 ) $ 24,297

~~(1)~~

~~Relates to amounts allocated to the existing Term Loan and Revolving Credit Facility, which became effective in June 2013.~~



	March 31, 2015							December 31, 2014
	Gross Carrying Amount		Accumulated Amortization			Net		Gross Carrying Amount		Accumulated Amortization			Net

Term Loan (matures June 2018)	$	3,638	$	(1,273	)	$	2,365	$	3,638	$	(1,091	)	$	2,547
Revolving Credit Facility (matures June 2018)	13,275		(4,646		)	8,629		13,275		(3,982		)	9,293
2032 Notes (mature March 2032)	3,759		(1,916		)	1,843		3,759		(1,763		)	1,996
MARAD Debt (matures February 2027)	12,200		(6,345		)	5,855		12,200		(6,223		)	5,977
Nordea Term Loan	3,586		—			3,586		3,586		—			3,586
Total deferred financing costs	$	36,458	$	(14,180	)	$	22,278	$	36,458	$	(13,059	)	$	23,399

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

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014
2013 (1)

Interest expense $ 8,952 $ 9,416 $ 24,474 $ 35,971
Interest income (2,741 ) (271 ) (4,113 ) (903 )
Capitalized interest (2,355 ) (2,560 ) (7,505 ) (6,816 )
Net interest expense $ 3,856 $ 6,585 $ 12,856 $ 28,252



	Three Months Ended March 31,
	2015			2014

Interest expense	$	8,409		$	8,362
Interest income	(650		)	(717		)
Capitalized interest	(3,689		)	(3,162		)
Net interest expense	$	4,070		$	4,483

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~~(1)~~

Interest expense amount includes $2.8 million for the three-month period ended March 31, 2013 that was allocated to ERT and is included in discontinued operations. Following the sale of ERT in February 2013, we ceased allocating interest expense to ERT, which then constituted a discontinued operation.

Note 7 — Income Taxes

Our estimated annual effective tax rate, adjusted for discrete tax items, is applied to interim periods’ pretax earnings. We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested, and as such, we have not provided for any U.S. federal income taxes on these permanently reinvested earnings. We believe that our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, and therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

The effective tax rates for the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014 were ~~28.3%~~2.0% and ~~26.5%, respectively. The effective tax rates for the three- and nine-month periods ended September 30, 2013 were 13.5% and 17.7%~~27.4%, respectively. The variance iswas primarily attributable to ~~projected year-over-year increases in profitability in~~ the ~~United States~~earnings mix between our higher and ~~the 2013~~lower tax ~~benefit of a reduction in the U.K. statutory tax rate.~~ rate jurisdictions.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013

Statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
Foreign provision (7.2 ) (12.3 ) (7.8 ) (11.8 )
Tax return to accrual adjustment — (4.0 ) — (2.3 )
Change in U.K. tax rate — (5.6 ) — (3.3 )
Other 0.5 0.4 (0.7 ) 0.1
Effective rate 28.3 % 13.5 % 26.5 % 17.7 %



	Three Months Ended March 31,
	2015		2014

U.S. statutory rate	35.0	%	35.0	%
Foreign provision	(34.1	)	(8.5	)
Other	1.1		0.9
Effective rate	2.0	%	27.4	%

In June 2014, the U.S. Internal Revenue Service (“IRS”) and the Joint Committee on Taxation completed the examination procedures including all appeals and administrative reviews that the taxing authorities are required and expected to perform for the 2006 through 2010 audit period. In September 2014, we received an income tax refund in the amount of $35.2 million that was pending the conclusion of the examination. The refund was primarily attributable to the utilization of a net operating loss carryback from 2010.

Note 8 —Accumulated Other Comprehensive Income (Loss) (“OCI”)

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


	September 30,			December 31,
	2014			2013			March 31, 2015			December 31, 2014

Cumulative foreign currency translation adjustment	$	(18,125	)	$	(10,697	)	$	(44,030	)	$	(30,161	)
Unrealized loss on hedges, net (1)		(14,673	)		(9,991	)	(38,616		)	(32,091		)
Accumulated other comprehensive loss	$	(32,798	)	$	(20,688	)	$	(82,646	)	$	(62,252	)


(1)	Amounts relate to foreign currency hedges for the Grand Canyon, the Grand Canyon II and the Grand Canyon III charters as well as interest rate swap contracts for the Term Loan, and are net of deferred income taxes totaling ~~$7.9~~$20.8 million at March 31, 2015 and ~~$5.4~~$17.3 million ~~as of September 30, 2014 and~~at December 31, ~~2013, respectively~~2014 (Note ~~15)~~14).

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Note 9 — Earnings Per Share

We have shares of restricted stock issued and outstanding, which currently are unvested. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding unrestricted common stock and the shares are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share (“EPS”) amounts under the two class method in periods in which we have earnings from continuing operations. ~~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 contractually 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 the net income applicable to ~~Helix~~our common shareholders by the weighted average shares of our outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations are as follows (in thousands):

Three Months Ended Three Months Ended
September 30, 2014 September 30, 2013
Income Shares Income Shares
Basic:
Continuing operations:
Net income applicable to Helix $ 75,586 $ 44,593
Less: Income from discontinued operations, net of tax — (44 )
Net income from continuing operations 75,586 44,549
Less: Undistributed income allocable to participating securities – continuing operations (392 ) (337 )
Net income applicable to common shareholders – continuing operations $ 75,194 104,997 $ 44,212 105,029

Discontinued operations:
Income from discontinued operations, net of tax $ — 104,997 $ 44 105,029

Diluted:
Continuing operations:
Net income applicable to common shareholders �� continuing operations $ 75,194 104,997 $ 44,212 105,029
Effect of dilutive securities:
Share-based awards other than participating securities — 341 — 107
Undistributed income reallocated to participating securities 1 — — —
Net income applicable to common shareholders – continuing operations $ 75,195 105,338 $ 44,212 105,136

Discontinued operations:
Income from discontinued operations, net of tax $ — 105,338 $ 44 105,136

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	Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
	Income			Shares	Income			Shares
Basic:
Net income applicable to common shareholders	$	19,642			$	53,719
Less undistributed income allocated to participating securities	(114		)		(286		)
Undistributed income allocated to common shares	$	19,528		105,290	$	53,433		105,126

Diluted:
Undistributed income allocated to common shares	$	19,528		105,290	$	53,433		105,126
Effect of dilutive securities:
Share-based awards other than participating securities	—			—	—			249
Undistributed income reallocated to participating securities	—			—	1			—
Net income applicable to common shareholders	$	19,528		105,290	$	53,434		105,375

Nine Months Ended Nine Months Ended
September 30, 2014 September 30, 2013
Income Shares Income Shares
Basic:
Continuing operations:
Net income applicable to Helix $ 187,087 $ 73,419
Less: Income from discontinued operations, net of tax — (1,073 )
Net income from continuing operations 187,087 72,346
Less: Undistributed income allocable to participating securities – continuing operations (980 ) (525 ) ��
Net income applicable to common shareholders – continuing operations $ 186,107 105,038 $ 71,821 105,036

Discontinued operations:
Income from discontinued operations, net of tax $ — $ 1,073
Less: Undistributed income allocable to participating securities – discontinued operations — (8 )
Net income applicable to common shareholders – discontinued operations $ — 105,038 $ 1,065 105,036

Diluted:
Continuing operations:
Net income applicable to common shareholders – continuing operations $ 186,107 105,038 $ 71,821 105,036
Effect of dilutive securities:
Share-based awards other than participating securities — 336 — 116
Undistributed income reallocated to participating securities 3 — — —
Net income applicable to common shareholders – continuing operations $ 186,110 105,374 $ 71,821 105,152

Discontinued operations:
Income from discontinued operations, net of tax $ — 105,374 $ 1,073 105,152

~~No diluted~~Approximately 8.0 million of potentially dilutive shares ~~were included for~~related to the 2032 Notes were excluded from the diluted EPS calculation for the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013 as the conversion trigger of $32.53 per share were not met in either period, and~~ because we have the right, intention and ability to settle any such future conversions in cash ~~at our sole discretion~~ (Note 6).

Note 10 — Employee Benefit Plans

Long-Term Incentive Stock-Based ~~Plans~~Plan

As of ~~September 30, 2014,~~March 31, 2015, there were ~~6.4~~5.6 million shares of our common stock available for issuance under our active long-term incentive stock-based ~~plans~~plan, the 2005 Long-Term Incentive Plan, as amended and restated effective May 9, 2012 (the ~~“LTI Stock Plans”~~“2005 Incentive Plan”). During the ~~nine-month~~three-month period ended ~~September 30, 2014,~~March 31, 2015, the following grants of ~~other~~ share-based awards were made ~~to executive officers and non-employee members of our Board of Directors~~ under ~~our LTI Stock Plans:~~ the 2005 Incentive Plan:



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

January 2, 2015 ⁽¹⁾	289,163	$	21.70	33% per year over three years
January 2, 2015 ⁽²⁾	289,163	$	25.06	100% on January 1, 2018
January 5, 2015 ⁽³⁾	3,946	$	21.66	100% on January 1, 2017
January 12, 2015 ⁽¹⁾	3,866	$	19.40	33% per year over three years
January 12, 2015 ⁽²⁾	3,866	$	25.06	100% on January 11, 2018
February 1, 2015 ⁽¹⁾	2,664	$	18.77	33% per year over three years
February 1, 2015 ⁽²⁾	2,664	$	25.06	100% on January 31, 2018

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

January 2, 2014 (1)
73,609 $ 23.18 33% per year over three years
January 2, 2014 (2)
73,609 $ 26.79 100% on January 1, 2017
January 2, 2014 (3)
2,724 $ 23.18 100% on January 1, 2016
April 1, 2014 (3)
4,051 $ 22.98 100% on January 1, 2016
July 1, 2014 (3)
3,397 $ 26.31 100% on January 1, 2016


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

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(2)

Reflects the grant of performance share units (“PSUs”) to our executive ~~officers. The estimated fair value of the PSUs on grant date was determined using a Monte Carlo simulation model.~~officers and selected management employees. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum amount of the award being 200% of the original awarded PSUs and the minimum amount being zero. The vested PSUs ~~will~~may be settled in ~~an equivalent number of~~either cash or shares of our common stock ~~unless~~at the discretion of the Compensation Committee of our Board of ~~Directors elects to pay in cash.~~Directors.


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

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Compensation cost for restricted stock is recognized over ~~the respective~~its vesting ~~periods~~period on a straight-line basis. For the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014, ~~$1.7~~$1.4 million and ~~$5.2~~$1.2 million, respectively, were recognized as stock-based compensation expense related to ~~share-based~~restricted stock and restricted stock units.

The estimated fair value of the PSUs on grant date was determined using a Monte Carlo simulation model. Until December 2014, the PSUs were being treated as an equity award. Accordingly, compensation expense associated with the PSUs was fixed, as represented by the number of PSUs multiplied by their respective grant date fair value. The fixed amount was being amortized on a straight-line basis over the three-year vesting period. In connection with the vesting of the 2012 PSU awards ~~as compared~~(which occurred in January 2015), the decision was made by the Compensation Committee of our Board of Directors to settle these PSUs with ~~$1.6~~a cash payment of $4.5 million ~~and $6.7 million for~~rather than an equivalent number of shares of our common stock, which was the ~~three- and nine-month periods ended September 30, 2013. A total of $1.3 million~~default provision of the PSU awards. Accordingly, PSUs are now accounted for as a liability plan. For the three-month period ended March 31, 2015, we recorded a $1.0 million reduction of previously recognized compensation cost to reflect the estimated fair value of unvested PSUs as of March 31, 2015. For the three-month period ended March 31, 2014, $0.5 million was recognized as stock-based compensation expense ~~for the nine-month period ended September 30, 2013 was included within our discontinued operations.~~related to PSUs.

Long-Term Incentive Cash Plans

We have certain long-term incentive cash plans (the “LTI Cash Plans”) that provide long-term cash-based compensation to eligible employees. Cash awards historically have been both fixed sum amounts payable (for non-executive management only) as well as cash awards indexed to our common stock with the payment amount at each vesting date fluctuating based on the performance of our common stock (for both executive and non-executive management). ~~These~~Payment amounts under these awards are ~~measured~~calculated based on the ~~performance~~ratio of ~~our~~the average stock price during the applicable measurement period over the ~~applicable award period compared to a~~original base price determined by the Compensation Committee of our Board of Directors at the time of the award. Cash payments under ~~the LTI Cash Plans~~these awards are made each year on the anniversary date of the award. Cash awards granted since 2012 have a vesting period of three years while those granted prior to 2012 have a vesting period of five years. The LTI Cash Plans are considered liability plans and as such are re-measured to fair value each reporting period with corresponding changes in the liability amount being reflected in our results of operations.

The cash awards granted under the LTI Cash Plans to our executive officers and selected management employees totaled $8.9 million in ~~2014 and $8.4~~2014. No long-term incentive cash awards were granted in 2015. For the three-month period ended March 31, 2015, we recorded a $1.9 million ~~in 2013. Total~~reduction of previously recognized compensation expense associated with the cash awards issued pursuant to the LTI Cash Plans, was $5.4 million ($2.4 million related to our executive officers) for the nine-month period ended September 30, 2014. Overall, compensation expense recorded for the three-month period ended September 30, 2014 was immaterial reflecting the effect the decrease in our stock price at the end of ~~September 2014~~March 2015 had on the value of our liability plan. For the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2013,~~March 31, 2014, total compensation expense associated with the cash awards issued pursuant to the LTI Cash Plans was ~~$3.3 million ($2.1 million related to our executive officers) and $7.5 million ($4.4 million related to our executive officers), respectively.~~$1.7 million. The liability balance for the cash awards issued under the LTI Cash Plans was ~~$10.5~~$2.0 million at ~~September 30, 2014~~March 31, 2015 and ~~$14.8~~$12.8 million at December 31, ~~2013, including $6.7 million at September 30, 2014 and $11.1 million at December 31, 2013 associated with the cash awards issued to our executive officers under the LTI Cash Plans.~~2014.

Employee Stock Purchase Plan

We also have an employee stock purchase plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance, of which ~~1.2~~1.1 million shares were available for issuance as of ~~September 30, 2014.~~March 31, 2015. The total value of the ESPP awards is calculated using the component approach where each award is computed as the sum of 15% of a share of non-vested stock, a call option on 85% of a share of non-vested stock, and a put option on 15% of a share of non-vested stock. Share-based compensation expense with respect to the ESPP was $0.3 million and ~~$0.7~~$0.2 million for the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014, respectively. ~~For the three- and nine-month periods ended September 30, 2013, share-based compensation with respect to the ESPP was $0.2 million and $0.6 million, respectively.~~

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For more information regarding our employee benefit plans, including our ~~stock-based compensation plans, our~~ long-term incentive stock-based and cash plans and our employee stock purchase plan, see Note 98 to our ~~2013~~2014 Form 10-K.

Note 11 — Business Segment Information

We have ~~four~~three reportable business segments: Well Intervention, Robotics ~~Subsea Construction~~ and Production Facilities. Our Well Intervention segment includes our vessels and ~~related~~ equipment ~~that are~~ used to perform well intervention services primarily in the Gulf of Mexico and North Sea regions. Our well intervention vessels include the Q4000, the Helix 534, the Seawell, theWell Enhancer and the Skandi Constructor, which is a chartered vessel. We are currently constructing two additional well intervention vessels, the Q5000 and the Q7000. We have also contracted to charter two newbuild vessels, which are expected to be delivered in 2016 and used in connection with our contracts to provide well intervention services offshore Brazil. Our Robotics segment ~~currently operates four chartered vessels, and also~~ includes ~~remotely operated vehicles (“ROVs”),~~ROVs, trenchers and ROVDrills designed to complement offshore construction and well intervention ~~services. We have sold substantially all~~services, and will operate five chartered ROV and trencher support vessels following the delivery of the ~~assets associated with our former Subsea Construction operations, including the sale~~Grand Canyon II in ~~January 2014 of our Ingleside spoolbase.~~late April 2015. The Production Facilities segment includes the HP I as well as our ~~equity~~ investments in Deepwater Gateway and Independence Hub that are accounted for under the equity method. The results of our Subsea Construction segment are immaterial and thus no longer meet the threshold to be separately reported as a business segment. These results are now aggregated within “Other” for all periods presented in this Quarterly Report on Form 10-Q. All material intercompany transactions between the segments have been eliminated. In February 2013, we sold ERT and as a result, the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment are presented as discontinued operations in the accompanying consolidated financial statements. See Note 3 to our 2013 Form 10-K for additional information regarding our discontinued operations.

We evaluate our performance based on operating income and income before income taxes of each segment. Segment assets are comprised of all assets attributable to each reportable segment. Corporate and other includes all assets not directly identifiable with our business ~~segments, most notably the majority of our cash and cash equivalents.~~segments. Certain financial data by reportable segment isare summarized as follows (in thousands):

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013
Net revenues —
Well Intervention $ 205,139 $ 114,238 $ 546,057 $ 319,893
Robotics 131,707 90,370 339,301 242,940
Subsea Construction — 4,120 358 69,305
Production Facilities 24,184 24,366 71,373 68,933
Intercompany elimination (20,193 ) (12,977 ) (57,093 ) (51,347 )
Total $ 340,837 $ 220,117 $ 899,996 $ 649,724

Income (loss) from operations —
Well Intervention $ 80,789 $ 33,544 $ 194,297 $ 93,906
Robotics 28,397 16,392 60,415 28,991
Subsea Construction (1)
41 15,088 10,871 29,031
Production Facilities 11,284 14,136 33,127 39,964
Corporate and other (14,283 ) (16,522 ) (45,625 ) (64,260 )
Intercompany elimination 103 21 (1,050 ) (2,538 )
Total $ 106,331 $ 62,659 $ 252,035 $ 125,094

Equity in earnings of equity investments $ 508 $ 857 $ 709 $ 2,150

~~(1)~~

~~Amount in 2014 includes the $10.5 million gain on the sale of our Ingleside spoolbase in January 2014. Amounts in 2013 include the $1.1 million loss on the sale of the~~ ~~Caesar~~ ~~in June 2013 and the $15.6 million gain on the sale of the~~ ~~Express~~ ~~in July 2013.~~



	Three Months Ended March 31,
	2015			2014
Net revenues —
Well Intervention	$	104,051		$	159,700
Robotics	80,171			87,890
Production Facilities	18,385			23,140
Other	—			358
Intercompany elimination	(12,966		)	(17,516		)
Total	$	189,641		$	253,572

Income (loss) from operations —
Well Intervention	$	14,794		$	48,733
Robotics	9,457			11,219
Production Facilities	4,578			11,384
Corporate and other	(6,607		)	(3,190		)
Intercompany elimination	106			(1,198		)
Total	$	22,328		$	66,948

Equity in earnings of equity investments	$	21		$	708

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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				Nine Months Ended
	September 30,				September 30,				Three Months Ended March 31,
	2014		2013		2014		2013		2015		2014

Well Intervention	$	8,635	$	4,784	$	22,052	$	15,052	$	4,946	$	5,461
Robotics		11,558		8,193		35,041		31,305	8,020		12,055
Subsea Construction		—		—		—		317
Production Facilities		—		—		—		4,673
Total	$	20,193	$	12,977	$	57,093	$	51,347	$	12,966	$	17,516

Intercompany segment profits (losses)~~, which~~ (which losses only relate to intercompany capital ~~projects,~~projects) are as follows (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,						Three Months Ended March 31,
	2014			2013			2014			2013			2015			2014

Well Intervention	$	(87	)	$	(45	)	$	(236	)	$	(91	)	$	(86	)	$	(62	)
Robotics		28			67			1,417			2,602		24			1,304
Subsea Construction		—			—			—			158
Production Facilities		(44	)		(43	)		(131	)		(131	)	(44		)	(44		)
Total	$	(103	)	$	(21	)	$	1,050		$	2,538		$	(106	)	$	1,198

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):


	September 30,		December 31,
	2014		2013		March 31, 2015		December 31, 2014

Well Intervention	$	1,503,592	$	1,245,229	$	1,486,347	$	1,470,349
Robotics		324,101		282,373	296,525		299,701
Subsea Construction		32,959		38,054
Production Facilities		469,374		495,829	452,582		459,427
Corporate and other		414,930		482,795	412,870		471,221
Total	$	2,744,956	$	2,544,280	$	2,648,324	$	2,700,698

Note 12 — Commitments and Contingencies and Other Matters

Commitments

In March 2012, we executed a contract with a shipyard in Singapore for the construction of a newbuild semi-submersible well intervention vessel, theQ5000. This $386.5 million shipyard contract represents the majority of the expected costs associated with the construction of the Q5000. Pursuant to the terms of this contract, payments are made in a fixed percentage of the contract price, together with any variations, on contractually scheduled dates. The vessel is expected to be ~~completed~~delivered in the second quarter of 2015 and ~~placed in service in early 2015.~~will subsequently transit to the Gulf of Mexico. In September 2014, we entered into the Nordea Credit Agreement to partially finance the construction of the Q5000and other future capital projects. The Nordea Term Loan will be funded at or near the time of the delivery of the Q5000 (Note 6). At ~~September 30, 2014,~~March 31, 2015, our total investment in the Q5000 was ~~$282.0~~$359.2 million, including ~~$231.9~~$289.4 million of scheduled payments made to the shipyard.

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In February 2013, we contracted to charter the Grand Canyon II and the Grand Canyon III for use in our robotics operations. The terms of the charters will be five years from the respective delivery ~~dates, both~~dates. We will take delivery of ~~which are expected to be~~the Grand Canyon II in late April 2015.

~~Table~~ The delivery of ~~Contents~~the

Grand Canyon III has been deferred until February 2016.

In September 2013, we executed a second contract with the same shipyard in Singapore that is currently constructing the Q5000. This contract provides for the construction of a newbuild semi-submersible well intervention vessel, theQ7000, which will be built to North Sea standards. This $346.0 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the current terms of this contract, 20% of the contract price was paid upon the signing of the contract and the remaining 80% will be paid upon the delivery of the ~~vessel, which is expected to occur in 2016.~~vessel. At ~~September 30, 2014,~~March 31, 2015, our total investment in the Q7000 was ~~$95.7~~$98.4 million, including the $69.2 million paid to the shipyard upon signing the contract.

In February 2014, we entered into agreements with Petróleo Brasileiro S.A. (“Petrobras”) to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with options to extend. In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two newbuild monohull vessels, both of which are expected to be in service for Petrobras in 2016. At ~~September 30, 2014,~~March 31, 2015, our total investment in the topside equipment for the two vessels was ~~$31.0~~$61.5 million. In November 2014, we paid a charter fee deposit of $12.5 million.

Contingencies and Claims

~~Under the terms~~We believe that there are currently no contingencies which would have a material effect on our financial position, results of the equity purchase agreement for the sale of ERT, we required the buyer to provide bonding in a sufficient amount as determined by the Bureau of Ocean Energy Management (the “BOEM”) to cover the decommissioning costs of ERT’s lease properties and thus to replace and allow for a discharge of our existing guaranty to the BOEM for ERT’s lease obligations. The buyer posted the bonding required by the equity purchase agreement, and we submitted a formal request to the BOEM to terminate and release our guaranty. On July 24, 2014, we received a letter from the BOEM terminating the period of liability under our guaranty effective July 14, 2014.operations or cash flows.

Litigation

On July 8, 2011, a shareholder derivative lawsuit styled City of Sterling Heights Police & Fire Retirement System v. Owen Kratz, et al. was filed in the United States District Court for the Southern District of Texas, Houston Division. In the suit, the plaintiff made claims against our Board of Directors, certain of our former directors, certain of our current and former executive officers, and the independent compensation consultant to the Compensation Committee of our Board of Directors, for breaches of the fiduciary duty of loyalty, unjust enrichment and aiding and abetting the alleged breaches of fiduciary duty relating to the long-term equity awards granted in 2010 to certain of the Company’s then executive officers who are defendants. The defendants filed a motion to dismiss the claim asserting that the plaintiff has not (i) pled specific facts excusing its failure to make pre-suit demand on our Board of Directors as required by Minnesota law, (ii) filed proper verification, or (iii) stated a claim. In August 2014, the judge in this case granted the defendants’ motion to dismiss and dismissed the case with prejudice.

We are involved in various legal proceedings, ~~primarily~~some involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.

Note 13 ~~— Allowance for Uncollectible Accounts~~

~~The following table sets forth the activity in our allowance for uncollectible accounts since December 31, 2013 (in thousands):~~

Balance at December 31, 2013 $ 2,234
Provision (1)
5,196
Write-offs (1,459 )
Balance at September 30, 2014 $ 5,971

~~(1)~~

~~Reflects charges associated with the provision for uncertain collection of a portion of our existing trade receivables related to our Robotics segment.~~

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~~Note 14~~ — Fair Value Measurements

~~Certain of our financial assets and liabilities are measured and reported~~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 ~~on a recurring basis as required under applicable~~ accounting ~~requirements. These requirements~~rules establish a three-tier fair value hierarchy, ~~for~~which prioritizes the inputs used in measuring fair ~~value. The 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 be calculated based on assumptions that market participants would use in pricing assets and liabilities and not on assumptions specific to the entity. The statement requires that each asset and liability carried at fair value be classified into one of the following categories: develop its own assumptions.

	•		~~Level 1. Observable inputs such as quoted prices in active markets;~~
	•		~~Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and~~
	•		~~Level 3. Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.~~

Assets and liabilities measured at fair value are based on one or more of three valuation techniques as follows:


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


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

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

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, long-term debt and various derivative instruments. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the ~~highly liquid~~short-term nature of these instruments. The following ~~table provides~~tables provide additional information ~~related~~relating to other financial instruments measured at fair value on a recurring basis ~~at September 30, 2014~~ (in thousands):


									Valuation	Fair Value Measurements at March 31, 2015 Using
	Level 1		Level 2 (1)		Level 3		Total		Technique	Level 1		Level 2 ⁽¹⁾		Level 3		Total		Valuation Technique
Assets:
Interest rate swaps	$	—	$	578	$	—	$	578	(c)	$	—	$	79	$	—	$	79	(c)

Liabilities:
Fair value of long-term debt (2)		513,278		104,300		—		617,578	(a)	199,750		370,071		—		569,821		(a)
Foreign exchange contracts		—		22,490		—		22,490	(c)	—		62,395		—		62,395		(c)
Interest rate swaps		—		662		—		662	(c)	—		523		—		523		(c)
Total net liability	$	513,278	$	126,874	$	—	$	640,152		$	199,750	$	432,910	$	—	$	632,660



	Fair Value Measurements at December 31, 2014 Using
	Level 1		Level 2 ⁽¹⁾		Level 3		Total		Valuation Technique
Assets:
Interest rate swaps	$	—	$	369	$	—	$	369	(c)

Liabilities:
Fair value of long-term debt ⁽²⁾	222,900		375,393		—		598,293		(a)
Foreign exchange contracts	—		50,428		—		50,428		(c)
Interest rate swaps	—		561		—		561		(c)
Total net liability	$	222,900	$	426,013	$	—	$	648,913

(1)

Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. See Note 1514 for further discussion on fair value of our derivative instruments.

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(2)	See Note 6 for additional information regarding our long-term debt. The value of our long-term debt is as follows (in thousands):



	March 31, 2015				December 31, 2014
	Carrying Value		Fair Value ^(b)		Carrying Value		Fair Value ^(b)

Term Loan (matures June 2018)	$	273,750	$	271,355	$	277,500	$	270,563
2032 Notes (mature March 2032) ^(a)	200,000		199,750		200,000		222,900
MARAD Debt (matures February 2027)	92,004		98,716		94,792		104,830
Total debt	$	565,754	$	569,821	$	572,292	$	598,293

September 30, 2014
Carrying Value
Fair Value (b)

Term Loan (matures June 2018) $ 281,250 $ 278,438
2032 Notes (mature March 2032) (a)
200,000 234,840
MARAD Debt (matures February 2027) 94,792 104,300
Total debt $ 576,042 $ 617,578

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(a)	Carrying ~~value~~amount excludes the related unamortized debt discount of ~~$22.4~~$19.5 million at ~~September 30,~~March 31, 2015 and $20.9 million at December 31, 2014.

(b)

The estimated fair value of ~~all debt, other than~~ the ~~MARAD Debt,~~2032 Notes was determined using Level 1 inputs using the market approach. The fair value of the Term Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach. The fair value of the Term Loan and the MARAD Debt was determined using a third party evaluation of the remaining average life and outstanding principal balance of the ~~MARAD~~ indebtedness as compared to other ~~governmental~~ obligations in the marketplace with similar terms. ~~The fair value of the MARAD Debt was estimated using Level 2 fair value inputs using the market approach.~~

Note 1514 — Derivative Instruments and Hedging Activities

Our operations are exposed to market risk associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. All derivatives are reflected in the accompanying condensed consolidated balance sheets at fair value.

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 ~~derivative~~ fair ~~values~~value of derivatives that are designated as cash flow hedges are deferred to the extent that the hedges are effective. These fair value changes are recorded as a component of Accumulated OCI (a component of shareholders’ equity) until the hedged transactions occur and are recognized in earnings. The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately in earnings. In addition, any change in the fair value of a derivative that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.

For additional information regarding our accounting for derivatives, see Notes 2 and 1615 to our ~~2013~~2014 Form 10-K.

Interest Rate Risk

From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term debt subject to variable interest rates. Changes in the fair value of an interest rate swap are deferred to the extent the swap is effective. These changes are recorded as a component of Accumulated OCI until the anticipated interest payments occur and are recognized in interest expense. The ineffective portion of the interest rate swap, 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. In September 2013, we entered into various interest rate swap contracts to fix the interest rate on $148.1 million of our Term Loan (Note 6). These contracts, which are settled monthly, ~~contracts~~ began in October 2013 and extend through October 2016.

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Our interest rate swap contracts qualify for hedge accounting treatment.

Foreign Currency Exchange Rate Risk

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. We entered into various foreign currency exchange contracts to stabilize expected cash outflows ~~relating~~related to certain vessel charters that are denominated in ~~British pounds and~~ Norwegian kroner.

In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 the foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II~~and~~ and Grand Canyon III charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. ~~These contracts currently qualify for hedge accounting treatment. All~~

Table of our remaining foreign exchange contracts that were not accounted for as hedge contracts have been settled. We had no foreign currency exchange contracts for vessel charters denominated in British pounds as of September 30, 2014.Contents

Quantitative Disclosures ~~Related~~Relating to Derivative Instruments

As a result of the announcement in December 2012 of the sale of ERT, we de-designated all of our then remaining oil and natural gas derivative contracts as hedging instruments. In addition, under the terms of our former credit agreement (Note 6), we were required to use a portion of the proceeds from the sale of ERT, as well as the sale of the ~~Caesar~~ ~~and~~ ~~Express~~ vessels, to make payments to reduce our indebtedness. Because of the probability that the former term loan debt would be totally repaid before the expiration of our then existing interest rate swaps, we also concluded that those swaps no longer qualified as cash flow hedges. The mark-to-market adjustments related to our commodity derivative contracts and interest rate swaps are reflected in “Loss on commodity derivative contracts” and “Other expense, net,” respectively, in the accompanying condensed consolidated statements of operations.

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

September 30, 2014 December 31, 2013
Balance Sheet Fair Balance Sheet Fair
Location Value Location Value
Asset Derivatives:
Foreign exchange contracts Other current assets $ — Other current assets $ 69
$ — $ 69

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

September 30, 2014 December 31, 2013
Balance Sheet Fair Balance Sheet Fair
Location Value Location Value
Asset Derivatives:
Interest rate swaps Other assets, net $ 578 Other assets, net $ 446
$ 578 $ 446

Liability Derivatives:
Foreign exchange contracts Accrued liabilities $ 5,255 Accrued liabilities $ 1,905
Interest rate swaps Accrued liabilities 662 Accrued liabilities 746
Foreign exchange contracts Other non-current liabilities 17,235 Other non-current liabilities 13,166
$ 23,152 $ 15,817



	March 31, 2015			December 31, 2014
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivatives:
Interest rate swaps	Other assets, net	$	79	Other assets, net	$	369
		$	79		$	369

Liability Derivatives:
Foreign exchange contracts	Accrued liabilities	$	16,967	Accrued liabilities	$	12,661
Interest rate swaps	Accrued liabilities	523		Accrued liabilities	561
Foreign exchange contracts	Other non-current liabilities	45,428		Other non-current liabilities	37,767
		$	62,918		$	50,989

~~Table~~For the three-month period ended March 31, 2015, we recorded losses totaling $3.4 million in “Other expense, net” in the accompanying condensed consolidated statement of ~~Contents~~operations related to ineffectiveness associated with our foreign currency hedges with respect to the

Grand Canyon III charter payments as a result of the deferral of the vessel’s delivery until February 2016. Ineffectiveness associated with our ~~derivatives~~cash flow hedges was immaterial for ~~all periods presented.~~the three-month period ended March 31, 2014. The following tables present the impact that derivative instruments designated as cash flow hedges had on our Accumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of ~~September 30, 2014 $3.8~~March 31, 2015, $9.1 million of ~~unrealized~~ losses in Accumulated OCI associated with our derivatives is expected to be reclassified into earnings within the next 12 months.

Gain (Loss) Recognized in OCI
on Derivatives, Net of Tax
(Effective Portion)
Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013

Foreign exchange contracts $ (5,713 ) $ 1,186 $ (4,823 ) $ (9,645 )
Interest rate swaps 255 (202 ) 141 (202 )
$ (5,458 ) $ 984 $ (4,682 ) $ (9,847 )

Gain (Loss) Reclassified from
Accumulated OCI into Earnings
Location of Gain (Loss) (Effective Portion)
Reclassified from Three Months Ended Nine Months Ended
Accumulated OCI into Earnings September 30, September 30,
(Effective Portion) 2014 2013 2014 2013

Interest rate swaps Net interest expense $ (215 ) $ — $ (646 ) $ —
Foreign exchange contracts Cost of sales (597 ) (396 ) (1,434 ) (900 )
$ (812 ) $ (396 ) $ (2,080 ) $ (900 )

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

		Gain (Loss) Recognized
		in Earnings on Derivatives
	Location of Gain (Loss)	Three Months Ended				Nine Months Ended					Gain (Loss) Recognized in OCI on Derivatives, Net of Tax
	Recognized in Earnings	September 30,				September 30,					Three Months Ended March 31,
	on Derivatives	2014		2013		2014		2013			2015			2014

Oil and natural gas commodity contracts	Loss on commodity derivative contracts	$	—	$	—	$	—	$	(14,113	)
Foreign exchange contracts											$	(6,361	)	$	3,024
Interest rate swaps	Other expense, net		—		—		—		(86	)	(164		)	39
Foreign exchange contracts	Other expense, net		—		498		7		(693	)
		$	—	$	498	$	7	$	(14,892	)	$	(6,525	)	$	3,063



	Location of Loss Reclassified from Accumulated OCI into Earnings	Loss Reclassified from Accumulated OCI into Earnings
		Three Months Ended March 31,
		2015			2014

Foreign exchange contracts	Cost of sales	$	(1,474	)	$	(444	)
Interest rate swaps	Net interest expense	(199		)	(214		)
		$	(1,673	)	$	(658	)

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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 Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements included herein or incorporated herein by reference that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements. Included in forward-looking statements are, among other things:

	•		~~statements regarding our business strategy or any other business plans, forecasts or objectives, any or all of which are subject to change;~~
	•		statements regarding our business strategy or any other business plans, forecasts or objectives, any or all of which are subject to change; statements regarding the construction, upgrades or acquisition of vessels or equipment and any anticipated costs related thereto, including the construction of our Q5000 and Q7000 vessels and the construction of two chartered vessels to be used in connection with our contracts to provide well intervention services offshore Brazil (Note 12); statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items; statements regarding our backlog and long-term contracts; statements regarding any financing transactions or arrangements, or ability to enter into such transactions; statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions; statements regarding the collectability of our trade receivables; statements regarding anticipated developments, industry trends, performance or industry ranking; statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business; statements regarding our ability to retain key members of our senior management and key employees; statements regarding the underlying assumptions related to any projection or forward-looking statement; and ~~statements relating to the construction, upgrades or acquisition of vessels or equipment and any anticipated costs related thereto, including the construction of the~~ ~~Q5000~~ ~~and the~~ ~~Q7000~~ ~~and the construction of two chartered vessels that are expected to be delivered in 2016 and used in connection with our contracts to provide well intervention services offshore Brazil (Note 12);~~
	•		~~statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items;~~
	•		~~statements regarding any financing transactions or arrangements, or ability to enter into such transactions;~~
	•		~~statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;~~
	•		~~statements regarding the collectability of our trade receivables;~~
	•		~~statements regarding anticipated developments, industry trends, performance or industry ranking;~~
	•		~~statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business;~~
	•		~~statements related to our ability to retain key members of our senior management and key employees;~~
	•		~~statements related to the underlying assumptions related to any projection or forward-looking statement; and~~
	•		any other statements that relate to non-historical or future information.

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

	•		impact of domestic and global economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;
	•		~~unexpected delays in the delivery or chartering of new vessels for our well intervention and robotics fleet, including the~~ ~~Q5000~~ ~~(expected in 2015), the~~ ~~Q7000~~ ~~(expected in 2016), the~~ ~~Grand Canyon II~~ ~~and the~~ ~~Grand Canyon III~~ ~~(both expected in 2015);~~
	•		~~unexpected delays in the delivery of the two newbuild chartered vessels to be used to perform contracted well intervention work in Brazil (both expected in 2016);~~
	•		~~unexpected future capital expenditures (including the amount and nature thereof);~~
	•		~~the effectiveness and timing of completion of our vessel upgrades and major maintenance items;~~
	•		~~the results of our continuing efforts to control costs and improve performance;~~
	•		~~the success of our risk management activities;~~
	•		~~the effects of competition;~~
	•		the effects of indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt and could have other adverse consequences to us;

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

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unexpected delays in the delivery or chartering of new vessels for our well intervention and robotics fleet, including the Q5000, the Q7000, the Grand Canyon III and the two newbuild chartered vessels to be used to perform contracted well intervention work in Brazil;

unexpected future capital expenditures (including the amount and nature thereof);

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

	•		~~the impact of current and future laws and governmental regulations, including tax and accounting developments;~~
	•		~~the effect of adverse weather conditions and/or other risks associated with marine operations;~~
	•		~~the effectiveness of our current and future hedging activities;~~
	•		~~the long-term availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations, and the terms of any such financing;~~
	•		~~the potential impact of a loss of one or more key employees; and~~
	•		the results of our continuing efforts to control costs and improve performance; the success of our risk management activities; the effects of competition; the impact of current and future laws and governmental regulations, including tax and accounting developments; the effect of adverse weather conditions and/or other risks associated with marine operations; the effectiveness of our current and future hedging activities; the long-term availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations; the effects of our indebtedness; the potential impact of a loss of one or more key employees; and the impact of general, market, industry or business conditions.

Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 1A. “Risk Factors” in our ~~2013~~2014 Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

Executive Summary

Business Strategy

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on ~~our~~ well intervention and robotics operations. For several years since 2008 we were focused on improving our balance sheet and increasing our liquidity through dispositions of non-core business assets and the related repayment of a significant portion of our indebtedness. We substantially finalized this process with the sale of ERT in February 2013, the sale of our two remaining pipelay vessels in mid-year 2013, and the sale of our Ingleside spoolbase in January 2014. As such, we believe that we are now positioned for growth and expansion in our well intervention and robotics operations.

~~Our focus is on expanding our well intervention and robotics businesses.~~ We believe that focusing on these services will deliver ~~higher~~favorable long-term financial ~~returns to us than the businesses and assets that we have chosen to monetize.~~returns. We are making strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. Our well intervention fleet ~~has expanded with the addition of the~~ ~~Helix 534, which was placed in service in February 2014. Our well intervention fleet~~ will ~~further~~ expand following the completion of the two newbuild semi-submersible vessels currently under construction, the Q5000and the Q7000, and the expected delivery in 2016 of two newbuild monohull vessels which we will charter in connection with the well intervention ~~service~~ agreements that we entered into with ~~Petrobras~~Petrobras. We will take delivery of the Grand Canyon II in ~~February 2014. In addition, we are expanding~~late April 2015. We will further expand our robotics operations by acquiring additional ROVs ~~and trenchers~~ as well as chartering ~~two newbuild ROV support vessels,~~ the ~~Grand Canyon II~~ ~~and the~~ Grand Canyon III~~both of which are expected to be delivered in 2015.~~.

On January 5, 2015, Helix, OneSubsea LLC, ~~a Cameron and Schlumberger company, Helix and~~OneSubsea B.V., Schlumberger Technology Corporation, ~~announced in August 2014 that a letter of intent was~~Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into ~~to form an~~a Strategic Alliance Agreement and related agreements for the parties’ strategic alliance to design, develop, ~~technologies~~manufacture, promote, market and ~~deliver~~sell on a global basis integrated equipment and services ~~to optimize the cost and efficiency of~~for subsea well ~~intervention systems. Upon agreement of the final terms of the~~intervention. The alliance ~~definitive agreement, the alliance will~~is expected to leverage the parties’ capabilities ~~of Helix, OneSubsea and Schlumberger,~~ to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies.

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Economic Outlook and Industry Influences

Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including but not limited to:

worldwide economic activity, including available access to global capital and capital markets;

27demand 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;

~~Table~~actions taken by the Organization of ~~Contents~~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 ability of oil and gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;

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

technological advances affecting energy exploration production transportation and consumption;

weather conditions;

environmental and other governmental regulations; and

domestic and international tax laws, regulations and policies.

	•		~~worldwide economic activity, including available access to global capital and capital markets;~~
	•		~~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;~~
	•		~~the effect of regulations on offshore Gulf of Mexico oil and gas operations;~~
	•		~~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 gas;~~
	•		~~the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;~~
	•		~~the sale and expiration dates of offshore leases in the United States and overseas;~~
	•		~~technological advances affecting energy exploration production transportation and consumption;~~
	•		~~weather conditions;~~
	•		~~environmental and other governmental regulations; and~~
	•		~~domestic and international tax policies.~~

~~The global price~~Global prices for oil ~~has~~and natural gas have declined significantly since mid-year 2014, ~~based on concerns over excess supply coupled~~ with ~~a slowing global economic outlook. The trading~~these price ~~for crude oil on~~decreases accelerating during the ~~New York Mercantile Exchange fell below $80 per barrel in October~~fourth quarter of 2014 ~~for the first time since June 2012.~~and early portion of 2015. Many analysts currently predict that prices for oil ~~prices may decrease further through~~and natural gas will remain low throughout 2015. The decrease in oil and gas prices ~~may be partially~~is attributable to a global supply and demand imbalance which reflects both increased production in certain countries ~~primarily in~~(primarily the United ~~States reflecting the effect fracking has had on domestic production~~States), and a general weakening inof the global ~~economic~~economy that has primarily affected ~~both~~ Europe and Asia. In light of the sharp decline in oil and gas prices, many oil and gas companies announced substantial reductions in their planned capital spending for 2015. Any additional news suggesting weak or declining economic data could affect global equity and ~~commodity~~the oil and gas markets, which could affect normal business activities. Weaker global equity and ~~commodity~~oil and gas markets could potentially reduce investment in offshore oil and gas capital projects, which may affect rates that drilling rig contractors can charge for their services. We believe that capital would be less likely to be expended on the beginning of offshore projects, for example for exploration drilling projects, than on projects that span the life of an oil and gas field’s production. However, during periods of sustained low oil and gas prices, no one in the industry is immune to the effect of any near term planned capital spending reductions, including us. Our Well Intervention and Robotics operations are intended to service the life span of an oil and gas field as well as to provide abandonment services at the end of the life of a field as required by governmental regulations. Thus over the longer term, we believe that fundamentals for our business remain favorable as the need for continual ~~replenishment of~~ oil and gas production is the primary driver of demand for our services.

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In addition, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long-term ~~increasing~~ world demand for oil and natural gas emphasizing the need for continual ~~oil~~production and ~~gas production;~~the replacement thereof; (2) mature global production rates for offshore and subsea wells; (3) globalization of the natural gas market; (4) an increasing number of mature and small reservoirs; (5) ~~increasing~~a general long-term growth trend in offshore activity ~~particularly in deepwater;~~and deepwater well count; and (6) an increasing number of subsea developments.

Helix Fast Response System

We developed the HFRS as a culmination of our experience as a responder in the Macondo well control and containment efforts. The HFRS centers on two of our vessels, the HP Iand the Q4000, both of which played a key role in the Macondo well control and containment efforts and are currently operating in the Gulf of Mexico. In 2011, we signed an agreement with Clean Gulf Associates ~~("CGA"~~(“CGA”), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available to certain CGA participants who executed utilization agreements with us that specified the day rates to be charged should the HFRS be deployed in connection with a well control incident. The original set of agreements expired on March 31, 2013, and we entered into a new set of substantially similar agreements effective April 1, 2013 with the operators who formed HWCG LLC, a Delaware limited liability company comprised of some of the original CGA members as well as other industry participants, to perform the same functions as CGA with respect to the HFRS. ~~These new agreements became effective April 1, 2013, and have~~HWCG LLC recently exercised a ~~four-year term.~~one-year option to extend the agreement with us through March 31, 2018.

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RESULTS OF OPERATIONS

We have ~~four~~three reportable business segments: Well Intervention, Robotics ~~Subsea Construction~~ and Production Facilities. Our Subsea Construction activities have significantly diminished following the sale of substantially all of our remaining assets related to this reportable segment, including the sale of our Ingleside spoolbase in January 2014. Previously, we had an additional business segment, Oil and Gas. In February 2013, we completed the sale of ERT (Note 2). Accordingly, the results of ERT are presented as discontinued operations for the three- and nine-month periods ended September 30, 2013 in this Quarterly Report on Form 10-Q.

All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our consolidated results of operations.

~~Continuing Operations~~

We seek to provide services and methodologies that we believe are critical to developing offshore reservoirs and maximizing production economics. We operate primarily in deepwater in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, with services that cover the lifecycle of an offshore oil or gas field. In addition, our Robotics operations are often contracted for the development of renewable energy projects (wind farms). As of ~~September 30, 2014,~~March 31, 2015, our ~~services had~~consolidated backlog that is supported by written agreements or contracts totaled $2.1 billion, of ~~$2.4 billion, including $162.5~~which $360.0 million is expected to be performed over the remainder of ~~2014.~~2015. The substantial majority of our backlog is associated with our Well Intervention business segment. As of ~~September 30, 2014,~~March 31, 2015, our well intervention backlog was ~~$2.1~~$1.9 billion, including ~~$94.1~~$228.9 million expected to be performed over the remainder of ~~2014. This includes a~~2015. Our five-year contract with BP to provide well intervention services with our Q5000 semi-submersible vessel ~~once its construction is completed (expected in 2015)~~ and our four-year agreements with Petrobras, both of which are scheduled to ~~provide well intervention services offshore Brazil with two chartered newbuild monohull vessels (both expected to be placed~~commence in ~~service in 2016).~~2016, represent approximately 68% of our total backlog. Backlog contracts are cancelable sometimes without ~~penalty in many cases. Backlog~~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 ~~revenue~~revenues for our services as contracts may be added, deferred, canceled and in many cases modified while in progress.

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Non-GAAP Financial Measures

A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position, or cash flows that includes or excludes amounts from the most directly comparable measure under U.S. GAAP. We measure our operating performance based on EBITDA, a non-GAAP financial measure that is commonly used but is not a recognized accounting term under GAAP. We use EBITDA to monitor and facilitate the internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe our measure of EBITDA provides useful information to the public regarding our ability to service debt and fund capital expenditures and may help our investors understand our operating performance and compare our results to other companies that have different financing, capital and tax structures.

We define EBITDA as net income ~~from continuing operations~~ plus income taxes, depreciation and amortization expense, and net interest expense and other. We separately disclose our non-cash asset impairment charges, which, if not material, would be reflected as a component of our depreciation and amortization expense. Loss on early extinguishment of long-term debt is considered equivalent to additional interest expense and thus is added back to net income from continuing operations.

In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted. This means that these amounts are recorded at 100% even if we do not own 100% of all of our subsidiaries. Accordingly, to arrive at our measure of Adjusted EBITDA, ~~from continuing operations,~~ when applicable, we deduct the noncontrolling interests related to the adjustment components of EBITDA and the gain or loss on disposition of ~~assets from continuing operations.~~

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assets.

Other companies may calculate their measures of EBITDA and Adjusted EBITDA differently than we do, which may limit their usefulness as comparative measures. Because EBITDA is not a financial measure calculated in accordance with U.S. GAAP, it should not be considered in isolation or as a substitute for net income attributable to common shareholders or cash flows from operations, but used as a supplement to these GAAP financial measures. The reconciliation of our net income ~~from continuing operations~~ to EBITDA ~~from continuing operations~~ and Adjusted EBITDA ~~from continuing operations~~ is as follows (in thousands):



	Three Months Ended March 31,
	2015		2014

Net income applicable to common shareholders	$	19,642	$	53,719
Adjustments:
Net income applicable to noncontrolling interests	—		503
Income tax provision	407		20,417
Net interest expense and other	5,226		5,293
Depreciation and amortization	26,089		24,726
EBITDA	51,364		104,658
Adjustments:
Noncontrolling interests	—		(661		)
Gain on disposition of assets, net	—		(11,496		)
ADJUSTED EBITDA	$	51,364	$	92,501

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013

Net income from continuing operations $ 75,586 $ 45,348 $ 187,590 $ 74,711
Adjustments:
Income tax provision 29,832 7,058 67,778 16,078
Net interest expense and other 3,258 4,219 13,085 30,136
Loss on early extinguishment of long-term debt — 8,572 — 12,100
Depreciation and amortization 28,421 21,850 81,274 71,542
EBITDA from continuing operations 137,097 87,047 349,727 204,567
Adjustments:
Noncontrolling interests — (1,037 ) (661 ) (3,078 )
Gain on disposition of assets, net — (15,812 ) (10,418 ) (14,727 )
ADJUSTED EBITDA from continuing operations $ 137,097 $ 70,198 $ 338,648 $ 186,762

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Comparison of Three Months Ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~

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


	Three Months Ended
	September 30,						Increase/			Three Months Ended March 31,						Increase/ (Decrease)
	2014			2013			(Decrease)			2015			2014			Increase/ (Decrease)
Net revenues —
Well Intervention	$	205,139		$	114,238		$	90,901		$	104,051		$	159,700		$	(55,649	)
Robotics		131,707			90,370			41,337		80,171			87,890			(7,719		)
Subsea Construction		—			4,120			(4,120	)
Production Facilities		24,184			24,366			(182	)	18,385			23,140			(4,755		)
Other										—			358			(358		)
Intercompany elimination		(20,193	)		(12,977	)		(7,216	)	(12,966		)	(17,516		)	4,550
	$	340,837		$	220,117		$	120,720		$	189,641		$	253,572		$	(63,931	)

Gross profit —
Well Intervention	$	84,166		$	36,406		$	47,760		$	18,548		$	52,789		$	(34,241	)
Robotics		31,457			19,685			11,772		12,690			13,345			(655		)
Subsea Construction		43			(335	)		378
Production Facilities		11,422			14,287			(2,865	)	4,769			11,536			(6,767		)
Corporate and other		(944	)		(607	)		(337	)	(1,166		)	(626		)	(540		)
Intercompany elimination		103			21			82		106			(1,198		)	1,304
	$	126,247		$	69,457		$	56,790		$	34,947		$	75,846		$	(40,899	)

Gross margin —
Well Intervention		41	%		32	%				18%			33%
Robotics		24	%		22	%				16%			15%
Subsea Construction		N/A			(8	)%
Production Facilities		47	%		59	%				26%			50%
Total company		37	%		32	%				18%			30%

Number of vessels or ROV assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels										4/68%			5/91%
ROVs										59/61%			56/75%
Robotics vessels										4/86%			5/80%

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Three Months Ended
September 30,
2014 2013
Number of vessels (1) / Utilization (2)

Well Intervention vessels 5/97 % 4/84 %
ROVs 63/78 % 57/68 %
Robotics vessels 6/90 % 5/98 %
Subsea Construction vessels N/A N/A


(1)	Represents number of vessels or ROV assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. The Seawell was excluded from the numbers for the first quarter of 2015 as it was taken out of service for the entire quarter to undergo major capital upgrades.


(2)	Average vessel utilization rate is calculated by dividing the total number of days the vessels ~~in each category~~or ROV assets generated revenues by the total number of calendar days in the applicable period.

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	Three Months Ended
	September 30,				Increase/		Three Months Ended March 31,				Increase/ (Decrease)
	2014		2013		(Decrease)		2015		2014		Increase/ (Decrease)

Well Intervention	$	8,635	$	4,784	$	3,851	$	4,946	$	5,461	$	(515	)
Robotics		11,558		8,193		3,365	8,020		12,055		(4,035		)
	$	20,193	$	12,977	$	7,216	$	12,966	$	17,516	$	(4,550	)

Intercompany segment profit (loss) is as follows (in thousands):

Three Months Ended
September 30, Increase/
2014 2013 (Decrease)

Well Intervention $ (87 ) $ (45 ) $ (42 )
Robotics 28 67 (39 )
Production Facilities (44 ) (43 ) (1 )
$ (103 ) $ (21 ) $ (82 )

In reviewing the discussion below of our results of operations, please refer to the tables above and Note 11 for supplemental information regarding our business segment results. This discussion specifically refers to our Well Intervention, Robotics and Production Facilities segments. We sold our remaining Subsea Construction pipelay vessels in mid-year 2013.



	Three Months Ended March 31,						Increase/ (Decrease)
	2015			2014			Increase/ (Decrease)

Well Intervention	$	(86	)	$	(62	)	$	(24	)
Robotics	24			1,304			(1,280		)
Production Facilities	(44		)	(44		)	—
	$	(106	)	$	1,198		$	(1,304	)

Net Revenues. Our total net revenues ~~increased~~decreased by ~~55%~~25% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014. The ~~increase~~decreased revenues for the three-month period in ~~net revenues~~2015 included the adverse impact of reduced opportunities for near term work for some of our assets following the industry-wide reaction to the substantial downturn in the ~~comparable year~~oil and natural gas market over ~~year periods reflects~~ the ~~addition~~last six-to-nine months. In late 2014, two of our previously contracted projects were canceled shortly before that work was scheduled to commence. In both of these instances, we were entitled to termination fees associated with the canceled contracted work; however, the amount of such fees is substantially less than the rates we would have generated if the services were performed in accordance with the terms of the canceled contracts. One of the canceled contracts provided for a $11.6 million termination fee as compensation for the 150-day void in the Helix 534 ~~to our Well Intervention fleet~~’s schedule caused by the contract cancellation. This termination fee was recognized in ~~February 2014~~the first quarter of 2015 and ~~the increased number of assets and asset utilization within our Robotics segment.~~received on April 6, 2015.

Our Well Intervention revenues ~~increased~~decreased by ~~80%~~35% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013~~2014 primarily reflecting decreased utilization of our in-service well intervention vessels and the ~~Helix 534~~Seawell being ~~placed~~out of service for the entire first quarter of 2015 as it undergoes certain capital upgrades intended to extend the useful life of the vessel. We currently expect the Seawell to return to service around mid-year 2015. In the North Sea, the Skandi Constructor was idle for the majority of the first quarter of 2015 as compared to being nearly fully utilized for the same period in ~~service~~2014. The Well Enhancer was essentially fully utilized for the first quarter of 2015 while the vessel was in regulatory dry dock for 24 days in the first quarter of 2014. In the Gulf of Mexico, ~~in February 2014, and increased revenues~~we attempted to arrange replacement projects to fill the 150-day void in the ~~North Sea region reflecting~~Helix 534’s schedule caused by the above-referenced contract cancellation. We were successful in filling all but 26 days in the first quarter of 2015. The ~~Skandi Constructor~~Q4000 ~~being placed~~ had full utilization in both periods except for some downtime attributable to IRS system mechanical issues in January 2015. The Q4000 is currently in dry dock undergoing its regulatory inspections and is expected to return to service in ~~2013~~mid-May 2015. In general, we have good visibility for work over the next two quarters and ~~performing a high revenue project offshore Canada~~we expect utilization rates to improve during that time frame. However, we still have relatively few confirmed projects for the ~~three-month period ended September 30, 2014. Our vessels had near full utilization (97%) during the third~~fourth quarter of ~~2014 as compared to 84% utilization in the same period last year, with this lower utilization reflecting downtime for the~~ ~~Skandi Constructor~~ ~~as the vessel underwent modifications prior commencing well intervention service in September 2013.~~ 2015.

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Robotics revenues ~~increased~~decreased by ~~46%~~9% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014. The ~~increase~~decrease primarily ~~reflects the addition of five ROVs and one trencher to our fleet, the higher~~reflected lower utilization of our ROVs as some units have been affected by other industry participants laying up vessels or canceling work as a result of the oil and ~~trenchers,~~gas market downturn. However, utilization of our chartered ROV and ~~197 additional days~~trencher support vessels increased reflecting full utilization of ~~spot vessel utilization. Our~~the Grand Canyon for a trenching ~~activities, primarily conducted in the North Sea region, have significantly increased during 2014 as compared to the unusually weak market that was experienced in 2013.~~project offshore Qatar.

Our Production Facilities revenues ~~remained relatively unchanged.~~

~~Gross Profit.~~ ~~Our total gross profit increased~~decreased by ~~82%~~21% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014, which reflected the decrease in our variable throughput fee as a result of both the decline in oil prices and the reduced production. The reduced production was the result of the Phoenix field being shut in for the majority of March 2015 for some development activities within the field and during which time the HP I underwent required maintenance. The Phoenix field recommenced production in late March 2015.

Gross Profit. Our total gross profit ~~associated with our Well Intervention segment increased~~decreased by ~~131%~~54% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013 primarily reflecting the addition of the~~ ~~Helix 534~~2014. The gross profit related to our ~~fleet in February 2014 and the~~ ~~Skandi Constructor~~ ~~being fully utilized in well intervention operations during~~Well Intervention segment decreased by 65% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to ~~approximately 30 days of utilization during~~ the same period in ~~2013.~~2014 reflecting reduced revenues as a result of the Seawell being in dry dock and the Skandi Constructor and the Helix 534 being idle for considerable periods of time during the first quarter of 2015 due to lack of available projects.

The gross profit associated with our Robotics segment ~~increased by 60% for~~remained flat in the ~~three-month period ended September 30, 2014 as compared to the same period in 2013. The variance~~comparable year-over-year periods primarily ~~reflects~~reflecting increased utilization for our ROV and trencher support vessels, partially offset by decreased utilization of our ROVs and trenching assets. ~~Utilization for our trenching assets increased significantly reflecting the resumption of trenching projects in the North Sea region following an unusually weak year for that work in 2013.~~

The gross profit related to our Production Facilities segment decreased by ~~20%~~59% for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014. The decrease primarily ~~reflects~~reflected the ~~amortization of~~decrease in revenues associated with our variable throughput fee and increased maintenance costs incurred in March 2015 while the ~~deferred regulatory dry dock costs for the~~ HP I ~~that were incurred during~~ was disconnected from the ~~fourth quarter of 2013.~~production buoy at the Phoenix field.

Gain on Disposition of ~~Assets.~~Assets, Net. The ~~$15.8~~$11.5 million gain on disposition of assets for the three-month period ended ~~September 30, 2013~~March 31, 2014 primarily ~~reflects~~reflected a $10.5 million gain associated with the sale of ~~the~~ ~~Express~~our Ingleside spoolbase in ~~July 2013.~~January 2014.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by ~~$2.7~~$7.8 million for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014. The decrease was primarily ~~reflects~~attributable to a ~~$2.3 million net recovery~~reduction of ~~amounts previously drawn on a letter of credit~~costs associated with ~~a completed international well abandonment project that were previously assessed as uncollectible in 2012.~~our variable performance-based incentive compensation programs (Note 10).

Equity in Earnings of Investments. Equity in earnings of investments decreased by ~~$0.3~~$0.7 million for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014. The decrease primarily ~~reflects~~reflected lower revenues for both Deepwater Gateway and Independence Hub reflecting lower production at the fields being processed at each facility.

Net Interest Expense. Our net interest expense ~~totaled $3.9~~decreased by $0.4 million for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to ~~$6.6~~the same period in 2014 primarily reflecting an increase in capitalized interest. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $3.7 million for the first quarter of 2015 as compared to $3.2 million for the first quarter of 2014.

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Other Expense, Net. We reported net other expense of $1.2 million for the three-month period ended March 31, 2015 as compared to $0.8 million for the same period in 2013. The decrease primarily reflects a reduction in interest expense and an increase in interest income partially offset by a decrease in capitalized interest. The decrease in interest expense reflects the reduction in our indebtedness with a higher interest rate mainly as a result of our redemption in July 2013 of the remaining $275 million of our Senior Unsecured Notes then outstanding. Interest income totaled $2.7 million for the three-month period ended September 30, 2014 as compared to $0.3 million for the same period in 2013. The amount of interest income for the third quarter of 2014 includes $2.1 million from an IRS income tax refund (Note 7) and $0.5 million on the promissory note held in connection with the sale of our Ingleside spoolbase (Note 3). Capitalized interest totaled $2.4 million for the third quarter of 2014 as compared to $2.6 million for the third quarter of 2013. Generally, our capitalized interest will be increasing as the construction of our vessels and related equipment progresses.

~~Loss on Early Extinguishment of Long-term Debt.~~ The $8.6 million loss in the third quarter of 2013 was associated with our redemption of the remaining $275 million Senior Unsecured Notes then outstanding. The loss reflects the $6.5 million call premium and the acceleration of the remaining $2.1 million of unamortized deferred financing fees related to the original issuance of the Senior Unsecured Notes.

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~~Other Income, Net.~~ ~~We reported net other income of $0.6 million for the three-month period ended September 30, 2014 as compared to $2.4 million for the same period in 2013.~~2014. These amounts primarily ~~reflect~~reflected foreign exchange fluctuations in our non-U.S. dollar functional currencies. ~~The~~We recorded gains of $2.4 million related to foreign ~~exchange gains~~currency transactions during the first quarter of 2015 as compared to losses of $0.8 million during the first quarter of 2014. Also included in net other expense for the three-month period ended March 31, 2015 were ~~attributed to the weakening~~losses of ~~the U.S. dollar against other global currencies. Included in these foreign exchange gains was $0.5~~$3.6 million ~~of gains~~ related to our foreign currency exchange ~~forward contracts~~contracts. Of those losses, $3.4 million was related to ineffectiveness associated with our foreign currency hedges with respect to the Grand Canyon III charter payments and $0.2 million was related to the contract settlement amounts in excess of the ~~three-month period ended September 30, 2013 (Note 15).~~ineffectiveness that was recorded for our Grand Canyon II hedges at the end of 2014.

Other Income – Oil and Gas. ~~The $0.2~~ Our other income – oil and gas decreased by $9.4 million ~~increase~~ for the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013~~2014. The decrease was primarily ~~associated with higher~~attributable to a $7.2 million insurance reimbursement in the first quarter of 2014 related to asset retirement work previously performed as well as the decrease in our overriding royalty ~~payments reflecting higher production at ERT’s Wang well.~~interests. The reduction in the overriding royalty income is significantly affected by the decline in oil prices since the first quarter of 2014 as well as the shut-in of the Phoenix field for the majority of March 2015 as previously discussed.

Income Tax Provision. Income taxes reflected expenses of ~~$29.8~~$0.4 million in the three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to ~~$7.1~~$20.4 million in the same period last year. The variance primarily ~~reflects increased~~reflected decreased profitability in the current year period. The effective tax rate of ~~28.3%~~2.0% for the three-month period ended ~~September 30, 2014~~March 31, 2015 was ~~higher~~lower than the ~~13.5%~~27.4% effective tax rate for the same period in ~~2013~~2014 as a result of ~~projected year-over-year increases in profitability in~~ the ~~United States~~earnings mix between our higher and ~~the 2013 tax benefit of a reduction in the U.K. statutory~~lower tax rate ~~(Note 7).~~jurisdictions.

~~Comparison of Nine Months Ended September 30, 2014 and 2013~~

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

Nine Months Ended
September 30, Increase/
2014 2013 (Decrease)
Net revenues —
Well Intervention $ 546,057 $ 319,893 $ 226,164
Robotics 339,301 242,940 96,361
Subsea Construction 358 69,305 (68,947 )
Production Facilities 71,373 68,933 2,440
Intercompany elimination (57,093 ) (51,347 ) (5,746 )
$ 899,996 $ 649,724 $ 250,272

Gross profit —
Well Intervention $ 205,498 $ 101,887 $ 103,611
Robotics 75,230 38,000 37,230
Subsea Construction 403 15,439 (15,036 )
Production Facilities 33,583 40,420 (6,837 )
Corporate and other (2,433 ) (3,687 ) 1,254
Intercompany elimination (1,050 ) (2,538 ) 1,488
$ 311,231 $ 189,521 $ 121,710

Gross margin —
Well Intervention 38 % 32 %
Robotics 22 % 16 %
Subsea Construction 113 % 22 %
Production Facilities 47 % 59 %
Total company 35 % 29 %

Number of vessels (1) / Utilization (2)

Well Intervention vessels 5/95 % 4/91 %
ROVs 63/77 % 57/61 %
Robotics vessels 6/87 % 5/89 %
Subsea Construction vessels N/A 0/92 %

~~(1)~~

Represents number of vessels as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party.

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~~(2)~~

~~Average vessel utilization rate is calculated by dividing the total number of days the vessels in each category generated revenues by the total number of calendar days in the applicable period.~~

~~Intercompany segment revenues are as follows (in thousands):~~

Nine Months Ended
September 30, Increase/
2014 2013 (Decrease)

Well Intervention $ 22,052 $ 15,052 $ 7,000
Robotics 35,041 31,305 3,736
Subsea Construction — 317 (317 )
Production Facilities — 4,673 (4,673 )
$ 57,093 $ 51,347 $ 5,746

~~Intercompany segment profit is as follows (in thousands):~~

Nine Months Ended
September 30, Increase/
2014 2013 (Decrease)

Well Intervention $ (236 ) $ (91 ) $ (145 )
Robotics 1,417 2,602 (1,185 )
Subsea Construction — 158 (158 )
Production Facilities (131 ) (131 ) —
$ 1,050 $ 2,538 $ (1,488 )

~~Net Revenues.~~ Our total net revenues increased by 39% for the nine-month period ended September 30, 2014 as compared to the same period in 2013. Net revenues for our business segments increased in the comparable year over year periods, reflecting the addition of vessels in our Well Intervention business, the increased number of assets and asset utilization within our Robotics segment, and the slightly higher revenues for the ~~HP I~~ ~~reflecting the variable production component of the fee arrangement in the Phoenix field. Our Subsea Construction revenues decreased reflecting the sale of our pipelay vessels in mid-year 2013.~~

~~Our Well Intervention revenues increased by 71% for the nine-month period ended September 30, 2014 as compared to the same period in 2013 reflecting the addition of a chartered vessel, the~~ ~~Skandi Constructor, in April 2013 and the~~ ~~Helix 534~~ ~~being placed in service in the Gulf of Mexico in February 2014. Our vessels had high utilization (95%) during the first nine months of 2014 with the primary exception being the~~ ~~Well Enhancer~~ ~~that went into regulatory dry dock in mid-December 2013 and returned to service in late January 2014. The~~ ~~Skandi Constructor~~ ~~and the~~ ~~Seawell~~ ~~are currently scheduled for dry dock in the fourth quarter of 2014. The~~ ~~Skandi Constructor~~ ~~is scheduled for its normal regulatory dry dock in November 2014, which should take approximately one month to complete. The~~ ~~Seawell~~ is scheduled for both normal regulatory dry dock and certain capital upgrades during its dry dock, which is scheduled to commence in December 2014 and expected to last approximately four months in duration. Upgrades to the ~~Seawell~~ ~~are intended to extend the vessel’s useful economic life.~~

Robotics revenues increased by 40% for the nine-month period ended September 30, 2014 as compared to the same period in 2013. The increase primarily reflects the addition of five ROVs and one trencher to our fleet, the higher utilization of our ROVs and trenchers, and 300 additional days of spot vessel utilization. Our trenching activities, primarily conducted in the North Sea region, have significantly increased during 2014 as compared to the unusually weak market that was experienced in 2013.

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Our Production Facilities revenues increased by 4% for the nine-month period ended September 30, 2014 as compared to the same period in 2013, which reflects an increase in our total revenues under our fee arrangement for the ~~HP I, including the variable portion of the fee for throughput processed by the~~ ~~HP I. The quarterly HFRS retainer fees also increased effective April 1, 2013 as a result of new four-year agreements.~~

~~Gross Profit.~~ Our total gross profit increased by 64% for the nine-month period ended September 30, 2014 as compared to the same period in 2013. The gross profit associated with our Well Intervention segment increased by 102% for the nine-month period ended September 30, 2014 as compared to the same period in 2013 reflecting the addition of two vessels to our fleet since March 31, 2013.

The gross profit associated with our Robotics segment increased by 98% for the nine-month period ended September 30, 2014 as compared to the same period in 2013. The variance primarily reflects increased utilization for our ROVs and trenching assets and related support vessels. Utilization for our trenching assets increased significantly reflecting the resumption of trenching projects in the North Sea region following an unusually weak year for that work in 2013.

The gross profit related to our Production Facilities segment decreased by 17% for the nine-month period ended September 30, 2014 as compared to the same period in 2013. The decrease primarily reflects the amortization of the deferred regulatory dry dock costs for the ~~HP I~~ ~~that were incurred during the fourth quarter of 2013.~~

~~Loss on Commodity Derivative Contracts.~~ In December 2012, following the announcement of the sale of ERT, we de-designated our oil and gas commodity derivative contracts and interest rate swap contracts as hedging instruments (Note 15). The $14.1 million loss on commodity derivative contracts reflects the net loss on our oil and gas commodity derivative contracts during the first quarter of 2013. In February 2013, we paid approximately $22.5 million to settle our remaining open commodity derivative contracts.

~~Gain on Disposition of Assets, Net.~~ The $10.4 million net gain on disposition of assets for the nine-month period ended September 30, 2014 primarily reflects a $10.5 million gain associated with the sale of our Ingleside spoolbase in January 2014. The $14.7 million gain on disposition of assets for the nine-month period ended September 30, 2013 primarily reflects a $1.1 million loss on the sale of the ~~Caesar~~ ~~in June 2013 and a $15.6 million gain on the sale of the~~ ~~Express~~ ~~in July 2013.~~

~~Selling, General and Administrative Expenses.~~ Our selling, general and administrative expenses increased by $4.6 million for the nine-month period ended September 30, 2014 as compared to the same period in 2013. The increase primarily reflects $5.2 million of charges associated with the provision for uncertain collection of a portion of our existing trade receivables (Note 13).

~~Equity in Earnings of Investments.~~ Equity in earnings of investments decreased by $1.4 million for the nine-month period ended September 30, 2014 as compared to the same period in 2013. The decrease primarily reflects lower revenues for both Deepwater Gateway and Independence Hub reflecting lower production at the fields being processed at each facility. Additionally, Deepwater Gateway’s operations were affected by a fire at the facility in early May 2014 that shut in production at the platform for most of the second quarter. Production was restored to the facility in July 2014.

~~Net Interest Expense.~~ Our net interest expense totaled $12.9 million for the nine-month period ended September 30, 2014 as compared to $28.3 million for the same period in 2013. The decrease consists of both a reduction in interest expense and increases in interest income and capitalized interest. The decrease in interest expense reflects the substantial reduction in our indebtedness, including the $318.4 million repayment of debt in February 2013 following the sale of ERT and our redemption in July 2013 of the remaining $275 million of our Senior Unsecured Notes then outstanding. Interest income totaled $4.1 million for the nine-month period ended September 30, 2014 as compared to $0.9 million for the same period in 2013. The amount of interest income for the first nine months of 2014 includes $2.1 million from an IRS income tax refund (Note 7) and $1.4 million on the promissory note held in connection with the sale of our Ingleside spoolbase (Note 3). Capitalized interest totaled $7.5 million for the first nine months of 2014 as compared to $6.8 million for the first nine months of 2013. Generally, our capitalized interest will be increasing as the construction of our vessels and related equipment progresses.

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~~Loss on Early Extinguishment of Long-term Debt.~~ The $12.1 million loss in the nine-month period ended September 30, 2013 included the $8.6 million loss in connection with our redemption in July 2013 of the remaining $275 million Senior Unsecured Notes then outstanding and the acceleration of the remaining $3.5 million of deferred financing fees related to the term loan component of our former credit agreement following the repayments of indebtedness and the related termination of the facility.

~~Other Expense, Net.~~ We reported net other expense of $0.2 million for the nine-month period ended September 30, 2014 as compared to $1.9 million for the same period in 2013. These amounts primarily reflect foreign exchange fluctuations in our non-U.S. dollar functional currencies. The foreign exchange losses were attributed to the strengthening of the U.S. dollar against other global currencies. Included in these foreign exchange losses was $0.7 million related to our foreign exchange forward contracts in the nine-month period ended September 30, 2013 (Note 15).

~~Other Income – Oil and Gas.~~ The $15.7 million income for the nine-month period ended September 30, 2014 includes a $7.2 million insurance reimbursement related to asset retirement work previously performed with the remaining income associated with our overriding royalty interests in ERT’s Wang well, which commenced production in late April 2013. The $5.8 million income for the nine-month period ended September 30, 2013 primarily represents cash payments related to services we provided to ERT following its sale to a third party and the initial proceeds associated with our overriding royalty interests in ERT’s Wang well.

~~Income Tax Provision.~~ Income taxes reflected expenses of $67.8 million in the nine-month period ended September 30, 2014 as compared to $16.1 million in the same period last year. The variance primarily reflects increased profitability in the current year period. The effective tax rate of 26.5% for the nine-month period ended September 30, 2014 was higher than the 17.7% effective tax rate for the same period in 2013 as a result of projected year-over-year increases in profitability in the United States and the 2013 tax benefit of a reduction in the U.K. statutory tax rate (Note 7).

~~Oil and Gas~~

All of our oil and gas assets sold in February 2013 were located in the U.S. Gulf of Mexico. The operating results of our discontinued oil and gas operations during 2013 are presented in our Quarterly Report on Form 10-Q for the three-month period ended March 31, 2013. Our continuing operations include one oil and gas property located offshore of the United Kingdom (“U.K.”). During the first quarter of 2013, we recorded a $1.6 million charge reflecting the estimated final costs to complete our U.K. property’s abandonment activities. We completed the reclamation activities for this offshore property in 2013 in accordance with applicable U.K. regulations.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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


	September 30,		December 31,
	2014		2013		March 31, 2015		December 31, 2014

Net working capital	$	575,841	$	553,427	$	434,026	$	468,660
Long-term debt (1)	$	529,281	$	545,776	$	514,265	$	523,228
Liquidity (2)	$	1,129,699	$	1,062,413	$	999,025	$	1,060,092


(1)	Long-term debt does not include the current maturities portion of our long-term debt as that amount is included in net working capital. It is also net of unamortized debt discount on the 2032 Notes. See Note 6 for information ~~related~~relating to our existing debt.

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(2)

Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under our Revolving Credit Facility, which capacity is reduced by letters of credit drawn against the facility. ~~As of September 30, 2014, our~~Our liquidity at March 31, 2015 included cash and cash equivalents of ~~$546.5~~$415.3 million and ~~$583.2~~$583.7 million of available borrowing capacity under our Revolving Credit Facility (Note 6). ~~As of~~Our liquidity at December 31, ~~2013, our liquidity~~2014 included cash and cash equivalents of ~~$478.2~~$476.5 million and ~~$584.2~~$583.6 million of available borrowing capacity under our Revolving Credit Facility.

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The carrying amount of our long-term debt, including current maturities, is as follows (in thousands):


	September 30,		December 31,
	2014		2013		March 31, 2015		December 31, 2014

Term Loan (matures June 2018)	$	281,250	$	292,500	$	273,750	$	277,500
2032 Notes (mature March 2032) (1)		177,633		173,484	180,544		179,080
MARAD Debt (matures February 2027)		94,792		100,168	92,004		94,792
Total debt	$	553,675	$	566,152	$	546,298	$	551,372

(1)

~~Amounts~~These amounts are net of the unamortized debt discount of ~~$22.4~~$19.5 million at March 31, 2015 and ~~$26.5~~$20.9 million ~~respectively.~~at December 31, 2014. The 2032 Notes will increase to ~~the~~their $200 million face amount through accretion of non-cash interest charges through March 15, 2018, which is the first date on which the holders of the notes may require us to repurchase the notes.

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

Nine Months Ended
September 30,
2014 2013
Cash provided by (used in):
Operating activities $ 301,561 $ 50,309
Investing activities $ (208,498 ) $ (80,771 )
Financing activities $ (25,982 ) $ (477,623 )
Discontinued operations (1)
$ — $ 552,462

~~(1)~~

Represents total cash flows associated with the operations of ERT. ERT was sold in February 2013. Proceeds from the sale of ERT totaled $614.8 million, net of transaction costs. Other cash flows in the table above reflect our continuing operations.



	Three Months Ended March 31,
	2015			2014
Cash provided by (used in):
Operating activities	$	(2,543	)	$	48,837
Investing activities	$	(51,145	)	$	(44,910	)
Financing activities	$	(6,005	)	$	(11,311	)

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

WeAs a further response to the recent announcements regarding industry-wide reductions in capital spending, we remain even more focused on maintaining a strong balance sheet and adequate liquidity. ~~We have a reasonable basis for estimating our future cash flows supported by our existing and expanding backlog.~~Over the near term, we may seek to reduce, defer or cancel certain planned capital expenditures. We believe that internally generated cash flows, ~~and~~ available borrowing capacity under our Revolving Credit Facility and the Nordea Credit Agreement will be sufficient to fund our operations over at least the next ~~twelve~~12 months.

In accordance with our Credit Agreement, the 2032 Notes, the MARAD Debt agreements, and the Nordea Credit Agreement, we are required to comply with certain covenants, including certain financial ratios such as a consolidated interest coverage ratio and consolidated leverage ratio, as well as the maintenance of minimum net worth, working capital and debt-to-equity requirements. 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 Credit Agreement indebtedness) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. The 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 of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, we were in compliance with all of our debt covenants.

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A prolonged period of weak economic activity may make it difficult to comply with our covenants and other restrictions in agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to access the full available commitment of $600 million under our Revolving Credit Facility may be impacted. Our ability to comply with these covenants and other restrictions is affected by economic conditions and other events beyond our control. If we fail to comply with these covenants and other restrictions, ~~that~~such failure could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral.

~~In July 2013, we borrowed $300 million under our Term Loan in connection with our early redemption~~Subject to the terms of the ~~remaining $275 million Senior Unsecured Notes then outstanding. We~~Credit Agreement, we may borrow and/or obtain letters of credit up to $600 million under our Revolving Credit Facility. Subject to ~~customary conditions,~~lender participation, we may request that aggregate commitments with respect to the Revolving Credit Facility be increased by, or additional term loans be made of, or a combination thereof, up to $200 million. See Note 6 for additional information relating to our long-term debt, including more information regarding our ~~current and former credit agreements,~~Credit Agreement, including covenants and collateral.

The 2032 Notes can be converted to ~~equity~~our common stock prior to their stated maturity upon certain triggering events specified in the Indenture governing the notes. Beginning in March 15, 2018, the holders of the 2032 Notes may require us to repurchase these notes or we may at our own option elect to repurchase them. To the extent we do not have cash on hand or long-term financing secured to cover the conversion, the 2032 Notes would be classified as current liabilities in our condensed consolidated balance sheet. No conversion triggers were met during the ~~nine-month~~three-month periods ended ~~September 30, 2014~~March 31, 2015 and ~~2013.~~ 2014.

Operating Cash Flows

Total cash flows from operating activities ~~increased~~decreased by ~~$281.8~~$51.4 million infor the ~~nine-month~~three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period in ~~2013.~~2014. This ~~increase~~decrease primarily ~~reflects increases~~reflected decreases in income from operations and changes in working capital, and a $35.2 million IRS income tax refund we received in September 2014. Operating cash flows for the nine-month period ended September 30, 2013 also included $30.5 million of net cash used in discontinued operations related to ERT, which was sold in February 2013. capital.

Investing Activities

Capital expenditures have consisted principally of the purchase or construction of dynamically positioned vessels, improvements and modifications to existing assets, and investments in our production facilities. Significant sources (uses) of cash associated with investing activities are as follows (in thousands):


	Nine Months Ended
	September 30,						Three Months Ended March 31,
	2014			2013			2015			2014
Capital expenditures:
Well Intervention	$	(167,227	)	$	(245,105	)	$	(45,797	)	$	(32,841	)
Robotics		(36,287	)		(29,514	)	(5,827		)	(5,767		)
Production Facilities		(769	)		(504	)	—			(5		)
Other		(245	)		(812	)	(900		)	622
Distributions from equity investments, net (1)		5,041			6,110		1,379			2,092
Proceeds from sale of assets (2)		11,074			189,054		—			11,074
Acquisition of noncontrolling interests (3)		(20,085	)		—		—			(20,085		)
Net cash used in investing activities – continuing operations		(208,498	)		(80,771	)
Oil and Gas capital expenditures		—			(31,855	)
Proceeds from sale of ERT, net of transaction costs		—			614,820
Net cash provided by investing activities – discontinued operations		—			582,965
Net cash provided by (used in) investing activities	$	(208,498	)	$	502,194
Net cash used in investing activities							$	(51,145	)	$	(44,910	)

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(1)	Distributions from equity investments are net of undistributed equity earnings from our equity investments. Gross distributions from our equity investments for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~ were ~~$5.8~~$1.4 million and ~~$8.3~~$2.8 million, respectively (Note 5).

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(2)	Primarily reflects cash received from the sale of our ~~two remaining pipelay vessels in mid-year 2013 and from the sale of our~~ Ingleside spoolbase in January 2014.


(3)	Relates to the acquisition in February 2014 of our former minority partner’s noncontrolling interests in the entity that owns the HP I ~~(Note 2)~~.

Capital expenditures associated with our business primarily include payments associated with the construction of ~~the~~ our Q5000 and ~~the~~ Q7000 vessels (see below), payments in connection with the ~~acquisition~~Seawell refit activities in 2015 and ~~subsequent~~the upgrades to and modifications of the Helix 534 in 2014, the investment in the topside well intervention equipment for the two newbuild monohull vessels that we expect to charter to perform our agreements with Petrobras (see below), and ~~the costs incurred in~~ the acquisition of additional ROVs and trenchers ~~related to~~for our robotics ~~operations.~~ business.

In March 2012, we executed a contract with a shipyard in Singapore for the construction of a newbuild semi-submersible well intervention vessel, the Q5000. This $386.5 million shipyard contract represents the majority of the expected costs associated with the construction of the Q5000. Pursuant to the terms of this contract, payments are made in a fixed percentage of the contract price, together with any variations, on contractually scheduled dates. At ~~September 30, 2014,~~March 31, 2015, our total investment in the Q5000 was ~~$282.0~~$359.2 million, including ~~$231.9~~$289.4 million of scheduled payments made to the shipyard. We plan to incur costs of approximately ~~$69~~$142 million on the Q5000 over the remainder of ~~2014,~~2015, including ~~a $58 million~~the last remaining shipyard ~~payment.~~milestone payment of $97.1 million. The vessel is expected to be ~~completed~~delivered in the second quarter of 2015 and ~~placed in service in early 2015.~~will subsequently transit to the Gulf of Mexico. The Q5000 will commence its five-year charter contract with BP on April 1, 2016 but may work for other industry participants prior to that date. In September 2014, we entered into the Nordea Credit Agreement to partially finance the construction of the Q5000and other future capital ~~projects.~~projects (Note 6). The Nordea Term Loan will be funded at or near the time of the delivery of the Q5000 ~~(Note 6)~~.

In September 2013, we executed a second contract with the same shipyard in Singapore that is currently constructing the Q5000. This contract provides for the construction of a newbuild semi-submersible well intervention vessel, theQ7000, which will be built to North Sea standards. This $346.0 million million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the current terms of this contract, 20% of the contract price was paid upon the signing of the contract and the remaining 80% will be paid upon the delivery of the vessel. We are in discussions with the shipyard to slow down the construction of the Q7000 and delay delivery of this vessel ~~which is expected to occur in 2016.~~until 2017. At ~~September 30, 2014,~~March 31, 2015, our total investment in the Q7000 was ~~$95.7~~$98.4 million, including $69.2 million paid to the shipyard upon signing the contract. We plan to incur approximately $8$36 million onof costs related to the construction of the Q7000 over the remainder of ~~2014.~~ 2015.

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. In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two newbuild monohull vessels, both of which are expected to be in service for Petrobras in 2016. Our total investment in the topside equipment for both vessels is expected to be approximately $260 million. We have invested ~~$31.0~~$61.5 million as of ~~September 30, 2014~~March 31, 2015 and plan to invest approximately ~~$14~~$36 million in the topside equipment over the remainder of ~~2014.~~

Net cash used in discontinued operations relates to capital expenditures associated with ERT. Oil and Gas capital expenditures for the first quarter of 2013 included costs associated with the exploration and development activities primarily related to the Wang well within the Phoenix field at Green Canyon Block 237.2015.

Outlook

We anticipate that our ~~total~~ capital expenditures for ~~2014~~2015 will betotal approximately ~~$385~~$360 million. This estimate may ~~increase or decrease~~change based on various economic factors and/or the existence of additional investment opportunities. However, we may reduce the level of our planned future capital expenditures given any prolonged economic downturn. We believe that our cash on hand, ~~internally-generated~~internally generated cash flows, and availability under our credit facility will provide the capital necessary to continue funding our ~~2014~~2015 initiatives.

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Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of ~~September 30, 2014~~March 31, 2015 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

2032 Notes ⁽²⁾	$	200,000	$	—	$	—	$	—	$	200,000
Term Loan ⁽³⁾	273,750		26,250		60,000		187,500		—
MARAD debt	92,004		5,783		12,447		13,720		60,054
Interest related to debt ⁽⁴⁾	173,890		22,503		40,784		21,667		88,936
Property and equipment ⁽⁵⁾	496,015		204,961		291,054		—		—
Operating leases ⁽⁶⁾	1,001,250		138,770		322,802		253,187		286,491
Total cash obligations	$	2,236,909	$	398,267	$	727,087	$	476,074	$	635,481

Less Than More Than

Total (1)
1 Year 1-3 Years 3-5 Years 5 Years

2032 Notes (2)
$ 200,000 $ — $ — $ — $ 200,000
Term Loan (3)
281,250 18,750 60,000 202,500 —
MARAD debt 94,792 5,644 12,148 13,390 63,610
Interest related to debt 191,220 24,964 44,090 27,281 94,885
Property and equipment (4)
573,175 274,527 298,648 — —
Operating leases (5)
1,061,217 136,455 329,323 264,753 330,686
Total cash obligations $ 2,401,654 $ 460,340 $ 744,209 $ 507,924 $ 689,181


(1)	Excludes unsecured letters of credit outstanding at ~~September 30, 2014~~March 31, 2015 totaling ~~$16.8~~$16.3 million. These letters of credit ~~guarantee items~~support various obligations, such as ~~various~~ contractual obligations, customs duties, contract bidding and insurance activities.

(2)

Notes mature in 2032. The 2032 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 130% of ~~its~~their issuance price on that 30^th trading day (i.e., $32.53 per share). At ~~September 30, 2014,~~March 31, 2015, the conversion trigger was not met. The first date that the holders of these notes may require us to repurchase the notes is March 15, 2018. See Note 6 for additional information.


(3)	Amount reflects borrowings made in July 2013. The Term Loan will mature on June 19, 2018.


(4)	Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at March 31, 2015 for variable rate debt.


(5)	Primarily reflects the costs associated with our well intervention assets currently under construction, including our new semi-submersible well intervention vessels, the Q5000and the Q7000, and the topside equipment for the two newbuild monohull vessels that we plan to charter (Note 12).

~~(5)~~
(6)	Operating leases include vessel charters and facility leases. At ~~September 30, 2014,~~March 31, 2015, our vessel charter ~~and ROV lease~~ commitments totaled approximately $1.0 billion, including ~~four~~three vessels that will not be delivered to us until ~~2015 and~~ 2016.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. We prepare these financial statements and related footnotes in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. For additional information regarding our critical accounting policies and estimates, please read our “Critical Accounting Policies and Estimates” as disclosed in our ~~2013~~2014 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 ~~September 30, 2014, $281.3~~March 31, 2015, $273.8 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may rise, increasing our interest expense and related cash outlay. To reduce the impact of this market risk, in September 2013, we entered into interest rate swap contracts to fix the interest rate on $148.1 million of our Term ~~Loan.~~Loan debt. These swap contracts, which are settled monthly, began in October 2013 and extend through October 2016. The impact of market risk is estimated using a hypothetical increase in interest rates by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional ~~$1.1~~$0.3 million in interest expense for the ~~nine-month~~three-month period ended ~~September 30, 2014.~~March 31, 2015.

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 (primarily with respect to our North Sea operations). As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the United States, we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the ~~nine-month~~three-month period ended ~~September 30, 2014,~~March 31, 2015, we recognized ~~losses~~gains of ~~$0.2~~$2.4 million related to foreign currency transactions in “Other expense, net” in our condensed consolidated statement of operations.

We also entered into various foreign currency exchange contracts to stabilize expected cash outflows ~~relating~~related to certain vessel charters denominated in ~~British pounds and~~ Norwegian kroners. In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 the foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon IIand theGrand Canyon III charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. These contracts currently qualify for hedge accounting treatment. ~~All~~For the three-month period ended March 31, 2015, we recorded losses totaling $3.6 million as a component of “Other expense, net” in our ~~remaining foreign exchange contracts that were not accounted for as hedge contracts have been settled. We had no~~condensed consolidated statement of operations. Of those losses, $3.4 million was related to ineffectiveness associated with our foreign currency ~~exchange contracts~~hedges with respect to the Grand Canyon III charter payments and $0.2 million was related to the contract settlement amounts in excess of the ineffectiveness that was recorded for ~~vessel charters denominated in British pounds as~~our Grand Canyon II hedges at the end of ~~September 30, 2014 (Note 15).~~2014.

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Item 4.Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) ~~promulgated~~ under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of ~~the end of the fiscal quarter ended September 30, 2014.~~March 31, 2015. Based on this evaluation, ~~the~~our principal executive officer and ~~the~~ principal financial officer have concluded that our disclosure controls and procedures were effective as of ~~the end of the fiscal quarter ended September 30, 2014~~March 31, 2015 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~~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 ~~as defined in Rule 13a-15(f) of~~that occurred during the ~~Exchange Act, in the period covered by this report~~quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

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

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

Issuer Purchases of Equity Securities

Period
(a)
Total number
of shares
purchased (1)

(b)
Average
price paid
per share

(c)
Total number
of shares
purchased as
part of publicly
announced
program (2)

(d)
Maximum
number of shares
that may yet be
purchased under
the program (2)

July 1 to July 31, 2014 — $ — — 7,448
August 1 to August 31, 2014 — — — 7,448
September 1 to September 30, 2014 72,140 26.12 72,140 —
72,140 $ 26.12 72,140



Period	(a) Total number of shares purchased ⁽¹⁾	(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 ⁽²⁾
January 1 to January 31, 2015	45,928	$	21.67	—	423,042
February 1 to February 28, 2015	—	—		—	425,706
March 1 to March 31, 2015	—	—		—	425,706
	45,928	$	21.67	—


(1)	Includes shares delivered to the Company by employees in satisfaction of minimum withholding taxes upon vesting of restricted shares.

(2)

Under the terms of our stock repurchase program, the issuance of shares to members of our Board of Directors and to certain employees, including shares issued to our employees under the ~~Employee Stock Purchase Plan (the “ESPP”)~~ESPP (Note 10), increases the amount of shares available for repurchase. ~~The shares purchased include the ESPP shares issued to our employees in September 2014.~~ For additional information regarding our stock repurchase program, see Note 1110 to our ~~2013~~2014 Form 10-K.

Item 6. Exhibits

The exhibits to this report are listed in the Exhibit Index ~~beginning~~ on Page 4440 hereof.

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SIGNATURES

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




		HELIX ENERGY SOLUTIONS GROUP, INC. (Registrant)
Date: ~~October~~	April 22, ~~2014~~2015		By:	/s/ Owen Kratz
				Owen Kratz President and Chief Executive Officer (Principal Executive Officer)

Date: ~~October~~	April 22, ~~2014~~2015		By:	/s/ Anthony Tripodo
				Anthony Tripodo Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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INDEX TO EXHIBITS

HELIX ENERGY SOLUTIONS GROUP, INC.



Exhibits	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.1	2005 Amended and Restated Articles of Incorporation, as amended, of Helix.	Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739)
3.2	Second Amended and Restated By-Laws of Helix, as amended.	Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
~~4.1~~31.1	Credit Agreement dated September 26, 2014, by and among Helix Q5000 Holdings S.à r.l., Helix Vessel Finance S.à r.l. and Nordea Bank Finland PLC, London Branch as administrative agent and collateral agent, together with the other lenders party thereto.	~~Exhibit 4.1 to the Current Report on Form 8-K filed on September 30, 2014 (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 Anthony Tripodo, Chief Financial Officer.	Filed herewith
32.1	Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.	Furnished herewith

101.INS	XBRL Instance Document.	Furnished herewith
101.SCH	XBRL Schema Document.	Furnished herewith
101.CAL	XBRL Calculation Linkbase Document.	Furnished herewith
101.PRE	XBRL Presentation Linkbase Document.	Furnished herewith
101.DEF	XBRL Definition Linkbase Document.	Furnished herewith
101.LAB	XBRL Label Linkbase Document.	Furnished herewith

	September 30, 2014							December 31, 2013
	Gross Carrying Amount		Accumulated Amortization			Net		Gross Carrying Amount		Accumulated Amortization			Net

Term Loan (matures June 2018) (1)	$	3,638	$	(909	)	$	2,729	$	3,638	$	(364	)	$	3,274
Revolving Credit Facility (matures June 2018) (1)		13,275		(3,319	)		9,956		13,275		(1,327	)		11,948
2032 Notes (mature March 2032)		3,759		(1,609	)		2,150		3,759		(1,148	)		2,611
MARAD Debt (matures February 2027)		12,200		(6,101	)		6,099		12,200		(5,736	)		6,464
Nordea Term Loan		3,143		—			3,143		—		—			—
Total deferred financing costs	$	36,015	$	(11,938	)	$	24,077	$	32,872	$	(8,575	)	$	24,297

Discontinued operations:
Income from discontinued operations, net of tax		$	—				104,997			$	44				105,029

Diluted:
Continuing operations:
Net income applicable to common shareholders �� continuing operations	$	75,194	104,997	$	44,212	105,029
Effect of dilutive securities:
Share-based awards other than participating securities		—	341		—	107
Undistributed income reallocated to participating securities		1	—		—	—
Net income applicable to common shareholders – continuing operations	$	75,195	105,338	$	44,212	105,136

Discontinued operations:
Income from discontinued operations, net of tax	$	—	105,338	$	44	105,136

Discontinued operations:
Income from discontinued operations, net of tax	$	—		$	1,073
Less: Undistributed income allocable to participating securities – discontinued operations		—			(8	)
Net income applicable to common shareholders – discontinued operations	$	—	105,038	$	1,065		105,036

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

January 2, 2014 (1)		73,609	$	23.18	33% per year over three years
January 2, 2014 (2)		73,609	$	26.79	100% on January 1, 2017
January 2, 2014 (3)		2,724	$	23.18	100% on January 1, 2016
April 1, 2014 (3)		4,051	$	22.98	100% on January 1, 2016
July 1, 2014 (3)		3,397	$	26.31	100% on January 1, 2016

Balance at December 31, 2013	$	2,234
Provision (1)		5,196
Write-offs		(1,459	)
Balance at September 30, 2014	$	5,971

	September 30, 2014
	Carrying Value		Fair Value (b)

Term Loan (matures June 2018)	$	281,250	$	278,438
2032 Notes (mature March 2032) (a)		200,000		234,840
MARAD Debt (matures February 2027)		94,792		104,300
Total debt	$	576,042	$	617,578

	September 30, 2014			December 31, 2013
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Asset Derivatives:
Foreign exchange contracts	Other current assets	$	—	Other current assets	$	69
		$	—		$	69

	Gain (Loss) Recognized in OCI
	on Derivatives, Net of Tax
	(Effective Portion)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Foreign exchange contracts	$	(5,713	)	$	1,186		$	(4,823	)	$	(9,645	)
Interest rate swaps		255			(202	)		141			(202	)
	$	(5,458	)	$	984		$	(4,682	)	$	(9,847	)

		Gain (Loss) Reclassified from
		Accumulated OCI into Earnings
	Location of Gain (Loss)	(Effective Portion)
	Reclassified from	Three Months Ended						Nine Months Ended
	Accumulated OCI into Earnings	September 30,						September 30,
	(Effective Portion)	2014			2013			2014			2013

Interest rate swaps	Net interest expense	$	(215	)	$	—		$	(646	)	$	—
Foreign exchange contracts	Cost of sales		(597	)		(396	)		(1,434	)		(900	)
		$	(812	)	$	(396	)	$	(2,080	)	$	(900	)

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

2032 Notes (2)	$	200,000	$	—	$	—	$	—	$	200,000
Term Loan (3)		281,250		18,750		60,000		202,500		—
MARAD debt		94,792		5,644		12,148		13,390		63,610
Interest related to debt		191,220		24,964		44,090		27,281		94,885
Property and equipment (4)		573,175		274,527		298,648		—		—
Operating leases (5)		1,061,217		136,455		329,323		264,753		330,686
Total cash obligations	$	2,401,654	$	460,340	$	744,209	$	507,924	$	689,181

Period	(a) Total number of shares purchased (1)		(b) Average price paid per share		(c) Total number of shares purchased as part of publicly announced program (2)		(d) Maximum number of shares that may yet be purchased under the program (2)
July 1 to July 31, 2014		—	$	—		—		7,448
August 1 to August 31, 2014		—		—		—		7,448
September 1 to September 30, 2014		72,140		26.12		72,140		—
		72,140	$	26.12		72,140