SEC Form 10-Q filed by Helix Energy Solutions Group Inc.

SEC Form 10-Q filed by Helix Energy Solutions Group Inc.

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2024

☐ 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		95-3409686
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3505 West Sam Houston Parkway North
Suite 400
Houston Texas		77043
(Address of principal executive offices)		(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)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, no par value	HLX	New York Stock Exchange

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. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No

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


Large accelerated filer ☑	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☐	Emerging growth company ☐

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

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

As of April 22, 2024, 152,453,000 shares of common stock were outstanding.

Table of Contents

TABLE OF CONTENTS


PART I.	FINANCIAL INFORMATION	PAGE

Item 1.	Financial Statements:	3
	Condensed Consolidated Balance Sheets – March 31, 2024 (Unaudited) and December 31, 2023	3

	Condensed Consolidated Statements of Operations (Unaudited) – Three months ended March 31, 2024 and 2023	4

	Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) – Three months ended March 31, 2024 and 2023	4

	Condensed Consolidated Statements of Shareholders’ Equity (Unaudited) – Three months ended March 31, 2024 and 2023	5

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Three months ended March 31, 2024 and 2023	6

	Notes to Condensed Consolidated Financial Statements (Unaudited)	7

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34

Item 4.	Controls and Procedures	34

PART II.	OTHER INFORMATION	35

Item 1.	Legal Proceedings	35

Item 1A.	Risk Factors	35

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35

Item 3.	Defaults Upon Senior Securities	35

Item 4.	Mine Safety Disclosures	35

Item 5.	Other Information	35

Item 6.	Exhibits	36

	Signatures	37

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)


	March 31,		December 31,
	2024		2023
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	323,849	$	332,191
Accounts receivable, net of allowance for credit losses of $3,700 and $3,407, respectively		219,844		280,427
Other current assets		62,064		85,223
Total current assets		605,757		697,841
Property and equipment		3,067,478		3,078,571
Less accumulated depreciation		(1,537,843)		(1,505,722)
Property and equipment, net		1,529,635		1,572,849
Operating lease right-of-use assets		358,285		169,233
Deferred recertification and dry dock costs, net		73,091		71,290
Other assets, net		47,046		44,823
Total assets	$	2,613,814	$	2,556,036

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	120,375	$	134,552
Accrued liabilities		163,797		203,112
Current maturities of long-term debt		8,965		48,292
Current operating lease liabilities		54,892		62,662
Total current liabilities		348,029		448,618
Long-term debt		309,199		313,430
Operating lease liabilities		314,351		116,185
Deferred tax liabilities		109,981		110,555
Other non-current liabilities		65,432		66,248
Total liabilities		1,146,992		1,055,036
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 152,450 and 152,291 shares issued, respectively		1,270,357		1,271,565
Retained earnings		286,163		312,450
Accumulated other comprehensive loss		(89,698)		(83,015)
Total shareholders’ equity		1,466,822		1,501,000
Total liabilities and shareholders’ equity	$	2,613,814	$	2,556,036

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)


	Three Months Ended
	March 31,
	2024		2023
Net revenues	$	296,211	$	250,084
Cost of sales		276,657		234,900
Gross profit		19,554		15,184
Gain (loss) on disposition of assets, net		(150)		367
Acquisition and integration costs		—		(231)
Change in fair value of contingent consideration		—		(3,992)
Selling, general and administrative expenses		(20,680)		(19,631)
Loss from operations		(1,276)		(8,303)
Net interest expense		(5,477)		(4,187)
Losses related to convertible senior notes		(20,922)		—
Other income (expense), net		(2,216)		3,444
Royalty income and other		1,906		1,863
Loss before income taxes		(27,985)		(7,183)
Income tax benefit		(1,698)		(2,018)
Net loss	$	(26,287)	$	(5,165)

Loss per share of common stock:
Basic	$	(0.17)	$	(0.03)
Diluted	$	(0.17)	$	(0.03)

Weighted average common shares outstanding:
Basic		152,369		151,764
Diluted		152,369		151,764

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)


	Three Months Ended
	March 31,
	2024		2023
Net loss	$	(26,287)	$	(5,165)
Other comprehensive income (loss), net of tax:
Foreign currency translation gain (loss)		(6,683)		8,432
Other comprehensive income (loss), net of tax		(6,683)		8,432
Comprehensive income (loss)	$	(32,970)	$	3,267

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)


						Accumulated
						Other		Total
	Common Stock			Retained		Comprehensive		Shareholders’
	Shares	Amount		Earnings		Loss		Equity
Balance, December 31, 2023	152,291	$	1,271,565	$	312,450	$	(83,015)	$	1,501,000
Net loss	—		—		(26,287)		—		(26,287)
Foreign currency translation adjustments	—		—		—		(6,683)		(6,683)
Settlement of convertible debt conversion	—		(84)		—		—		(84)
Repurchases of common stock	(463)		(5,032)		—		—		(5,032)
Termination of capped calls	—		4,381		—		—		4,381
Activity in company stock plans, net and other	622		(2,071)		—		—		(2,071)
Share-based compensation	—		1,598		—		—		1,598
Balance, March 31, 2024	152,450	$	1,270,357	$	286,163	$	(89,698)	$	1,466,822

Balance, December 31, 2022	151,935	$	1,298,740	$	323,288	$	(105,319)	$	1,516,709
Net loss	—		—		(5,165)		—		(5,165)
Foreign currency translation adjustments	—		—		—		8,432		8,432
Repurchases of common stock	(660)		(5,006)		—		—		(5,006)
Activity in company stock plans, net and other	219		(742)		—		—		(742)
Share-based compensation	—		1,492		—		—		1,492
Balance, March 31, 2023	151,494	$	1,294,484	$	318,123	$	(96,887)	$	1,515,720

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)


	Three Months Ended
	March 31,
	2024		2023
Cash flows from operating activities:
Net loss	$	(26,287)	$	(5,165)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		46,353		37,537
Amortization of debt discount		53		—
Amortization of debt issuance costs		570		596
Share-based compensation		1,711		1,575
Deferred income taxes		(574)		(1,306)
(Gain) loss on disposition of assets, net		150		(367)
Losses related to convertible senior notes		20,922		—
Unrealized foreign currency (gain) loss		2,117		(3,333)
Change in fair value of contingent consideration		—		3,992
Changes in operating assets and liabilities:
Accounts receivable, net		59,059		(2,484)
Income tax receivable, net of income tax payable		(2,510)		(2,419)
Other current assets		23,196		(1,961)
Accounts payable and accrued liabilities		(50,489)		(18,036)
Deferred recertification and dry dock costs, net		(9,594)		(17,154)
Other, net		(193)		3,133
Net cash provided by (used in) operating activities		64,484		(5,392)

Cash flows from investing activities:
Capital expenditures		(3,605)		(6,665)
Proceeds from sale of assets		—		365
Proceeds from insurance recoveries		363		—
Net cash used in investing activities		(3,242)		(6,300)

Cash flows from financing activities:
Payments related to convertible senior notes		(60,699)		—
Repayment of MARAD Debt		(4,322)		(4,116)
Proceeds from settlement of capped calls		4,381		—
Debt issuance costs		(984)		—
Repurchases of common stock		(4,177)		(4,983)
Payments related to tax withholding for share-based compensation		(4,003)		(564)
Proceeds from issuance of ESPP shares		500		239
Net cash used in financing activities		(69,304)		(9,424)

Effect of exchange rate changes on cash and cash equivalents		(280)		1,187
Net decrease in cash and cash equivalents		(8,342)		(19,929)
Cash and cash equivalents:
Balance, beginning of year		332,191		189,111
Balance, end of period	$	323,849	$	169,182

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Basis of Presentation and New Accounting Standards

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

The 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, unless otherwise disclosed, are of normal recurring nature, that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive loss, statements of shareholders’ equity and statements of cash flows, as applicable. The operating results for the three-month period ended March 31, 2024 are not necessarily indicative of the results that may be expected for the year ending December 31, 2024. Our balance sheet as of December 31, 2023 included herein has been derived from the audited balance sheet as of December 31, 2023 included in our 2023 Annual Report on Form 10-K (our “2023 Form 10-K”). These unaudited condensed consolidated financial statements should be read in conjunction with the audited annual consolidated financial statements and notes thereto included in our 2023 Form 10-K.

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

New accounting standards

In November 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, “Improvements to Reportable Segment Disclosures,” which requires entities to disclose, on an annual and interim basis, significant segment expenses that are regularly provided to the chief operating decision maker (the “CODM”) and included within each reported measure of segment profit or loss as well as an amount for other segment items by reportable segment and a description of its composition. ASU No. 2023-07 requires all annual disclosures about a reportable segment’s profit or loss and assets to be provided in interim periods as well. Among other things, this ASU also requires that a public entity disclose the title and position of the CODM and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. ASU No. 2023-07 will be effective on a retrospective basis for annual periods beginning January 1, 2024 and for interim periods beginning January 1, 2025. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements.

In December 2023, the FASB issued ASU No. 2023-09, “Improvements to Income Tax Disclosures,” which requires entities to disclose, on an annual basis, specific categories in a tabular rate reconciliation using both percentages and reporting currency amounts and to provide additional information for reconciling items that meet a quantitative threshold. This ASU also requires that entities disclose on an annual basis: a) income taxes paid (net) disaggregated by federal, state and foreign taxes, b) income taxes paid (net) by individual jurisdiction, c) income (or loss) from continuing operations before income tax expense (or benefit) between domestic and foreign, and d) income tax expense (or benefit) from continuing operations by federal, state and foreign. Certain previous disclosure requirements on unrecognized tax benefits and cumulative amount of temporary differences are eliminated. ASU No. 2023-09 will be effective for us for annual periods beginning January 1, 2025. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements.

We do not expect other recently issued accounting standards to have a material impact on our financial position, results of operations or cash flows when they become effective.

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Note 2 — Company Overview

●

Production maximization — our assets and methodologies are specifically designed to efficiently enhance and extend the lives of existing oil and gas reserves; we also offer an alternative to take over end-of-life reserves in preparation for their abandonment;

●

Decommissioning — we are a full-field abandonment contractor and believe that regulatory push for plug and abandonment (“P&A”) and transition to renewable energy will facilitate the continued growth of the abandonment market; and

●

Renewables — we are an established global leader in jet trenching and provide specialty support services to renewable energy developments such as offshore wind farms, including boulder removal and unexploded ordnance clearance.

We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of Mexico (deepwater and shelf), U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations and our Gulf of Mexico shelf operations are usually subject to seasonal changes in demand, which generally peaks in the summer months and declines in the winter months. Our services are segregated into four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities.

Our Well Intervention segment provides services enabling our customers to safely access subsea offshore wells for the purpose of performing production enhancement or decommissioning operations, thereby mitigating the need to drill new wells by extending the useful lives of existing wells and preserving the environment by preventing uncontrolled releases of oil and natural gas. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and two chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. Our well intervention equipment includes intervention systems such as intervention riser systems (“IRSs”), subsea intervention lubricators (“SILs”) and the Riserless Open-water Abandonment Module, some of which we provide on a stand-alone basis.

Our Robotics segment provides trenching, seabed clearance, offshore construction and inspection, repair and maintenance (“IRM”) services to both the oil and gas and the renewable energy markets globally, thereby assisting the delivery of renewable energy and supporting the responsible transition away from a carbon-based economy. Additionally, our robotics services are used in and complement our well intervention services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, IROV boulder grabs and robotics support vessels under term charters as well as spot vessels as needed. We offer our ROVs, trenchers and IROV boulder grabs on a stand-alone basis or on an integrated basis with chartered robotics support vessels.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes Helix Alliance that was acquired in July 2022, which offers a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat, P&A systems and coiled tubing (“CT”) systems.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamically positioned floating production vessel, the Helix Fast Response System (the “HFRS”), which combines the HP 1, the Q4000 and the Q5000 with certain well control equipment that can be deployed to respond to a well control incident, and our ownership of mature oil and gas properties. All of our current Production Facilities activities are located in the Gulf of Mexico.

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Note 3 — Details of Certain Accounts

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


	March 31,		December 31,
	2024		2023
Prepaids	$	23,813	$	28,352
Income tax receivable		447		—
Contract assets (Note 8)		5,520		5,824
Deferred costs (Note 8)		21,581		36,041
Other		10,703		15,006
Total other current assets	$	62,064	$	85,223

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


	March 31,		December 31,
	2024		2023
Prepaid charter ⁽¹⁾	$	12,544	$	12,544
Deferred costs (Note 8)		2,450		587
Other receivable ⁽²⁾		26,236		25,623
Intangible assets with finite lives, net		3,968		4,105
Other		1,848		1,964
Total other assets, net	$	47,046	$	44,823

(1)	Represents prepayments to the owner of the Siem Helix 1 and the Siem Helix 2 to offset certain payment obligations associated with the vessels at the end of their respective charter term.

(2)	Represents the present value of the agreed-upon amounts that we are entitled to receive from Marathon Oil Corporation (“Marathon Oil”) for remaining P&A work to be performed by us on Droshky oil and gas properties we acquired from Marathon Oil in 2019.

Accrued liabilities consist of the following (in thousands):


	March 31,		December 31,
	2024		2023
Accrued payroll and related benefits	$	31,472	$	59,010
Accrued interest		2,720		4,181
Income tax payable		—		1,938
Deferred revenue (Note 8)		20,856		32,763
Earn-out consideration ⁽¹⁾		85,000		85,000
Other ⁽²⁾		23,749		20,220
Total accrued liabilities	$	163,797	$	203,112

(1)	Represents the final amount of the earn-out consideration associated with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022, which was paid to the seller of Alliance in cash on April 3, 2024.

(2)	Amounts as of March 31, 2024 and December 31, 2023 included $11.6 million and $9.0 million, respectively, of credits towards future services that we granted for the purchase of five P&A systems and other assets.

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


	March 31,		December 31,
	2024		2023
Asset retirement obligations (Note 12)	$	62,732	$	61,356
Other ⁽¹⁾		2,700		4,892
Total other non-current liabilities	$	65,432	$	66,248

(1)	Amount as of December 31, 2023 included $2.6 million of credits offered by us in exchange for the purchase of P&A equipment (see above).

Note 4 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031.

The following table details the components of our lease cost (in thousands):


	Three Months Ended
	March 31,
	2024		2023
Operating lease cost	$	20,475	$	17,006
Variable lease cost		3,057		4,910
Short-term lease cost		8,914		6,977
Sublease income		(22)		(331)
Net lease cost	$	32,424	$	28,562

Maturities of our operating lease liabilities as of March 31, 2024 are as follows (in thousands):


			Facilities and
	Vessels		Equipment		Total
Less than one year	$	75,235	$	6,232	$	81,467
One to two years		76,992		2,575		79,567
Two to three years		63,907		1,270		65,177
Three to four years		61,941		1,262		63,203
Four to five years		53,539		1,169		54,708
Over five years		125,999		1,656		127,655
Total lease payments	$	457,613	$	14,164	$	471,777
Less: imputed interest		(100,746)		(1,788)		(102,534)
Total operating lease liabilities	$	356,867	$	12,376	$	369,243

Current operating lease liabilities	$	49,135	$	5,757	$	54,892
Non-current operating lease liabilities		307,732		6,619		314,351
Total operating lease liabilities	$	356,867	$	12,376	$	369,243

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Maturities of our operating lease liabilities as of December 31, 2023 are as follows (in thousands):


			Facilities and
	Vessels		Equipment		Total
Less than one year	$	67,488	$	6,639	$	74,127
One to two years		55,453		3,508		58,961
Two to three years		35,200		1,289		36,489
Three to four years		26,245		1,272		27,517
Four to five years		3,040		1,244		4,284
Over five years		—		1,926		1,926
Total lease payments	$	187,426	$	15,878	$	203,304
Less: imputed interest		(22,419)		(2,038)		(24,457)
Total operating lease liabilities	$	165,007	$	13,840	$	178,847

Current operating lease liabilities	$	56,602	$	6,060	$	62,662
Non-current operating lease liabilities		108,405		7,780		116,185
Total operating lease liabilities	$	165,007	$	13,840	$	178,847

The following table presents the weighted average remaining lease term and discount rate:


	March 31,		December 31,
	2024		2023
Weighted average remaining lease term	6.3	years	3.1	years
Weighted average discount rate	7.96	%	8.20	%

The following table presents other information related to our operating leases (in thousands):

(1)

Our operating lease additions during the three-month period ended March 31, 2024 are primarily related to the charter extensions for the Siem Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon (Note 13). Our operating lease additions during the three-month period ended March 31, 2023 are primarily related to the vessel charter for the Glomar Wave.

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Note 5 — Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of March 31, 2024 are as follows (in thousands):


	MARAD		2029
	Debt		Notes		Total
Less than one year	$	8,965	$	—	$	8,965
One to two years		9,412		—		9,412
Two to three years		9,881		—		9,881
Three to four years		—		—		—
Four to five years		—		—		—
Over five years		—		300,000		300,000
Gross debt		28,258		300,000		328,258
Unamortized debt discount ⁽¹⁾		—		(1,351)		(1,351)
Unamortized debt issuance costs ⁽¹⁾		(1,463)		(7,280)		(8,743)
Total debt		26,795		291,369		318,164
Less current maturities		(8,965)		—		(8,965)
Long-term debt	$	17,830	$	291,369	$	309,199

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

Below is a summary of our indebtedness:

Credit Agreement

On September 30, 2021 we entered into an asset-based credit agreement with Bank of America, N.A. (“Bank of America”), Wells Fargo Bank, N.A. and Zions Bancorporation and subsequently we entered into amendments to the credit agreement on July 1, 2022, June 23, 2023 and November 15, 2023 (collectively, the “Amended ABL Facility”). The Amended ABL Facility provides a $120 million asset-based revolving credit facility, which matures on September 30, 2026, with a springing maturity 91 days prior to the maturity of any outstanding indebtedness with a principal amount in excess of $50 million. The Amended ABL Facility also permits us to request an increase of the facility by up to $30 million, subject to certain conditions.

Commitments under the Amended ABL Facility are comprised of separate U.S. and U.K. revolving credit facility commitments of $85 million and $35 million, respectively. The Amended ABL Facility provides funding based on a borrowing base calculation that includes eligible U.S. and U.K. customer accounts receivable and cash, and provides for a $20 million sub-limit for the issuance of letters of credit. As of March 31, 2024, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity, based on the borrowing base, totaled $95.6 million, net of $3.4 million of letters of credit issued.

We and certain of our U.S. and U.K. subsidiaries are the current borrowers under the Amended ABL Facility, whose obligations under the Amended ABL Facility are guaranteed by those borrowers and certain other U.S. and U.K. subsidiaries, excluding Cal Dive I – Title XI, Inc. (“CDI Title XI”), Helix Offshore Services Limited and certain other enumerated subsidiaries. Other subsidiaries may be added as guarantors of the facility in the future. The Amended ABL Facility is secured by all accounts receivable and designated deposit accounts of the U.S. borrowers and guarantors, and by substantially all of the assets of the U.K. borrowers and guarantors.

U.S. borrowings under the Amended ABL Facility bear interest at the Term SOFR rate (also known as CME Term SOFR as administered by CME Group, Inc.) plus a margin of 1.50% to 2.00% or at a base rate plus a margin of 0.50% to 1.00%. U.K. borrowings under the Amended ABL Facility denominated in U.S. dollars bear interest at the Term SOFR rate with SOFR adjustment of 0.10% and U.K. borrowings denominated in the British pound bear interest at the SONIA daily rate, each plus a margin of 1.50% to 2.00%. We also pay a commitment fee of 0.375% to 0.50% per annum on the unused portion of the facility.

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The Amended ABL Facility includes certain limitations on our ability to incur additional indebtedness, grant liens on assets, pay dividends and make distributions on equity interests, dispose of assets, make investments, repay certain indebtedness, engage in mergers, and other matters, in each case subject to certain exceptions. The Amended ABL Facility contains customary default provisions which, if triggered, could result in acceleration of all amounts then outstanding. The Amended ABL Facility requires us to satisfy and maintain a fixed charge coverage ratio of not less than 1.0 to 1.0 if availability is less than the greater of 10% of the borrowing base or $12 million.

The Amended ABL Facility also (i) limits the amount of permitted debt for the deferred purchase price of property not to exceed $50 million, and (ii) provides for potential ESG-related pricing adjustments based on specific metrics and performance targets determined by us and Bank of America, as agent with respect to the Amended ABL Facility.

MARAD Debt

In 2005, Helix’s subsidiary CDI – Title XI issued its U.S. Government Guaranteed Ship Financing Bonds, Q4000 Series, to refinance the construction financing originally granted in 2002 of the Q4000 vessel (the “MARAD Debt”). The MARAD Debt is guaranteed by the U.S. government pursuant to Title XI of the Merchant Marine Act of 1936, administered by the Maritime Administration (“MARAD”). The obligation of CDI Title XI to reimburse MARAD in the event CDI Title XI fails to repay the MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. In addition, we have agreed to bareboat charter the Q4000 from CDI Title XI for so long as the MARAD Debt remains outstanding. The MARAD Debt is payable in equal semi-annual installments through February 2027 and bears interest at a rate of 4.93%. We believe the agreements relating to the bonds and the terms and conditions of our obligations to MARAD in respect of the MARAD Debt were typical for U.S. government-guaranteed ship financing transactions when they were entered into, including customary restrictions on incurring additional liens on the Q4000 and trading restrictions with respect to the vessel as well as working capital requirements.

Senior Notes Due 2029 (“2029 Notes”)

On December 1, 2023, we issued $300 million aggregate principal amount of the 2029 Notes. The net proceeds from the issuance of the 2029 Notes were approximately $291.1 million, after deducting the purchasers’ discount and debt issuance costs. We used cash proceeds from the offering to retire the Convertible Senior Notes due 2026 (the “2026 Notes”). See details regarding the 2026 Notes below.

The 2029 Notes bear interest at a coupon interest rate of 9.75% per annum payable semi-annually in arrears on March 1 and September 1 of each year, beginning on March 1, 2024. The 2029 Notes mature on March 1, 2029 unless earlier redeemed or repurchased by us.

Prior to March 1, 2026, we may, at our option, redeem the 2029 Notes, in whole or in part, at a price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus a make-whole premium and accrued and unpaid interest, if any, to, but excluding, the redemption date. On or after March 1, 2026, we may, at our option, redeem the 2029 Notes, in whole or in part, at the redemption prices (expressed as percentages of the principal amount of the notes to be redeemed) set forth below, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. Prior to March 1, 2026, following certain equity offerings we may, at our option, on any one or more occasions, redeem up to 40% of the 2029 Notes at a price equal to 109.750% of the aggregate principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, in an amount not exceeding the proceeds of such equity offerings.


		Redemption
Year		Price
2026		104.875%
2027		102.438%
2028 and thereafter		100.000%

Upon the occurrence of a Change of Control Triggering Event, as defined in the indenture governing the 2029 Notes, we may be required to make an offer to repurchase all of the notes then outstanding at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the repurchase date.

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The indenture governing the 2029 Notes contains customary terms and covenants, including limitations on additional indebtedness, restricted payments, liens, asset sales, transactions with affiliates, mergers and consolidations, designation of unrestricted subsidiaries, and dividend and other restrictions affecting restricted subsidiaries.

The 2029 Notes are guaranteed on a senior unsecured basis by the subsidiaries that guarantee the Amended ABL Facility, as well as certain future subsidiaries that may guarantee certain of our indebtedness, including the Amended ABL Facility. The 2029 Notes are junior in right of payment to all our existing and future secured indebtedness and obligations and rank equally in right of payment with all our existing and future senior unsecured indebtedness. The 2029 Notes rank senior in right of payment to any of our future subordinated indebtedness and are fully and unconditionally guaranteed by the guarantors described above on a senior basis.

2026 Notes

During December 2023 and the first quarter 2024, we retired the 2026 Notes through various transactions using proceeds from the 2029 Notes as well as the issuance of our common stock.

In December 2023, we entered into privately negotiated agreements with certain holders of the 2026 Notes to repurchase $159.8 million aggregate principal amount of the 2026 Notes (the “2026 Notes Repurchases”) for 1.5 million shares of our common stock and aggregate cash payments of $229.7 million, plus accrued and unpaid cash interest of $3.8 million. We recognized pre-tax inducement charges of $37.4 million for the 2026 Notes Repurchases in the fourth quarter 2023, representing the total settlement value in excess of the total conversion value of the 2026 Notes Repurchases when the final negotiated offers were accepted. The conversion value paid in excess of the carrying amount of the 2026 Notes Repurchases is reflected in “Common stock” in the shareholders’ equity section of the accompanying condensed consolidated balance sheets.

In December 2023, $0.2 million aggregate principal amount of the 2026 Notes was tendered for conversion. We settled the conversions for $0.3 million cash in March 2024. The conversion value paid in excess of the $0.2 million carrying amount of the 2026 Notes that were tentered for conversion is reflected in “Common stock” in the shareholders’ equity section of the accompanying condensed consolidated balance sheet.

In January 2024, we issued a notice for the redemption of the remaining $40.0 million aggregate principal amount of the 2026 Notes to be settled in March 2024 (the “2026 Notes Redemptions”). The redemption price consisted of the principal amount and the make-whole premium, plus accrued and unpaid interest. Our redemption notice enabled holders of $39.7 million aggregate principal amount of the 2026 Notes to tender their notes for conversion prior to the redemption date, with the remaining $0.3 million aggregate principal amount of the notes redeemed. We settled both the conversions and redemptions for an aggregate $60.2 million cash in March 2024 and recognized pre-tax losses of $20.9 million. These losses are reflected in “Losses related to convertible senior notes” in the accompanying condensed consolidated statement of operations.

The 2026 Notes had a coupon interest rate of 6.75% per annum and an effective interest rate of 7.6%. For the three-month periods ended March 31, 2024 and 2023, total interest expense related to the 2026 Notes was $0.4 million and $3.7 million, respectively, with coupon interest expense of $0.3 million and $3.4 million, respectively, and the amortization of debt issuance costs of $0.1 million and $0.3 million, respectively.

2026 Capped Calls

In connection with the 2026 Notes offering, we had entered into capped call transactions (the “2026 Capped Calls”) with three separate counterparties to hedge the dilution risk of the 2026 Notes. Concurrently with the 2026 Notes Repurchases in December 2023, we terminated a proportionate amount of the 2026 Capped Calls and received $15.6 million in cash, recognizing an increase to “Common stock” of $14.2 million and a $1.4 million gain. Concurrent with the settlement of the 2026 Notes Redemptions in March 2024, we terminated the remaining 2026 Capped Calls and received $4.4 million in cash, recognizing an increase to “Common stock” in the shareholders’ equity section of the accompanying condensed consolidated balance sheet.

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Other

In accordance with the Amended ABL Facility, the MARAD Debt and the 2029 Notes, we are required to comply with certain covenants, including minimum liquidity and a springing fixed charge coverage ratio (applicable under certain conditions that are currently not applicable) with respect to the Amended ABL Facility and the maintenance of net worth, working capital and debt-to-equity requirements with respect to the MARAD Debt. As of March 31, 2024, we were in compliance with these covenants.

The Convertible Senior Notes due 2023 (the “2023 Notes”) matured on September 15, 2023. Upon maturity of the 2023 Notes, we paid $29.6 million in cash to settle the conversion of $29.2 million aggregate principal amount of the notes, plus accrued and unpaid interest. We recorded the conversion value in excess of such principal amount converted to “Common stock” in the accompanying condensed consolidated balance sheets. Notes representing the remaining $0.8 million aggregate principal amount of the 2023 Notes were redeemed at par, plus accrued and unpaid interest. The 2023 Notes had a coupon interest rate of 4.125% per annum and an effective interest rate of 4.8%. For the three-month period ended March 31, 2023, total interest expense related to the 2023 Notes was $0.4 million, primarily from coupon interest expense.

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


	Three Months Ended
	March 31,
	2024		2023
Interest expense	$	8,778	$	4,869
Interest income		(3,301)		(682)
Net interest expense	$	5,477	$	4,187

Note 6 — Income Taxes

We operate in multiple jurisdictions with complex tax laws subject to interpretation and judgment. We believe that our application of such laws and the tax impact thereof are reasonable and fairly presented in our condensed consolidated financial statements.

For the three-month periods ended March 31, 2024 and 2023, we recognized income tax benefit of $1.7 million and $2.0 million, respectively, resulting in effective tax rates of 6.1% and 28.1%, respectively. The effective tax rate for the three-month period ended March 31, 2024 was lower than the U.S. statutory rate primarily due to the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event and reported in the current quarter. The effective tax rate for the three-month period ended March 31, 2023 was higher than the U.S. statutory rate primarily due to certain non-deductible expenses and non-creditable foreign income taxes.

Note 7 — Share Repurchase Programs

In February 2023, our Board of Directors (our “Board”) authorized a share repurchase program to repurchase issued and outstanding shares of our common stock up to $200 million (the “2023 Repurchase Program”). During the three-month period ended March 31, 2024, we repurchased a total of 462,585 shares of our common stock pursuant to the 2023 Repurchase Program for approximately $5.0 million or an average of $10.88 per share, of which approximately $0.9 million was accrued as of March 31, 2024.

The 2023 Repurchase Program has no set expiration date. Repurchases under the 2023 Repurchase Program have been made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, but may also be made through privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. The manner, timing and amount of any purchase will be determined by management at its discretion based on an evaluation of market conditions, stock price, liquidity and other factors. The 2023 Repurchase Program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. Any repurchased shares are cancelled.

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Note 8 — Revenue from Contracts with Customers

Disaggregation of Revenue

Our service contracts generally contain provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) but we occasionally contract on a lump sum basis (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities.

Our revenues are primarily derived from short-term and long-term service contracts with customers. Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration. The following table provides information about disaggregated revenue by contract duration (in thousands):


	Well				Shallow Water		Production		Intercompany		Total
	Intervention		Robotics		Abandonment		Facilities		Eliminations		Revenue
Three months ended March 31, 2024
Short-term	$	134,414	$	25,176	$	25,363	$	—	$	(6,327)	$	178,626
Long-term		82,045		25,133		1,490		24,152		(15,235)		117,585
Total	$	216,459	$	50,309	$	26,853	$	24,152	$	(21,562)	$	296,211

Three months ended March 31, 2023
Short-term	$	77,767	$	35,205	$	49,381	$	—	$	—	$	162,353
Long-term		64,671		14,017		—		20,905		(11,862)		87,731
Total	$	142,438	$	49,222	$	49,381	$	20,905	$	(11,862)	$	250,084

We provide services to our customers in the following markets that are key to our energy transition strategy: Production maximization, Decommissioning and Renewables. The following table provides information about disaggregated revenue by market strategy (in thousands):


	Well				Shallow Water		Production		Intercompany		Total
	Intervention		Robotics		Abandonment		Facilities		Eliminations		Revenue
Three months ended March 31, 2024
Production maximization	$	70,449	$	18,436	$	3,242	$	24,152	$	(11,392)	$	104,887
Decommissioning		142,685		5,412		23,611		—		(6,928)		164,780
Renewables		2,504		24,172		—		—		(2,504)		24,172
Other		821		2,289		—		—		(738)		2,372
Total	$	216,459	$	50,309	$	26,853	$	24,152	$	(21,562)	$	296,211

Three months ended March 31, 2023
Production maximization	$	47,267	$	26,719	$	3,407	$	20,905	$	(3,817)	$	94,481
Decommissioning		92,620		11,048		45,974		—		(5,071)		144,571
Renewables		1,326		8,678		—		—		(1,326)		8,678
Other		1,225		2,777		—		—		(1,648)		2,354
Total	$	142,438	$	49,222	$	49,381	$	20,905	$	(11,862)	$	250,084

Contract Balances

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” in the accompanying condensed consolidated balance sheets (Note 3). Contract assets were $5.5 million as of March 31, 2024 and $5.8 million as of December 31, 2023. We had no credit losses on our contract assets for the three-month periods ended March 31, 2024 and 2023.

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Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to a single performance obligation and recognized ratably over the contract term and/or (ii) amounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” in the accompanying condensed consolidated balance sheets (Note 3). Contract liabilities totaled $20.9 million as of March 31, 2024 and $32.8 million as of December 31, 2023. Revenue recognized for the three-month periods ended March 31, 2024 and 2023 included $16.4 million and $3.9 million, respectively, that were included in the contract liability balance at the beginning of each period.

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

Performance Obligations

As of March 31, 2024, $996.6 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $663.4 million, $309.7 million and $23.5 million in 2024, 2025 and 2026, respectively. These amounts include fixed consideration and estimated variable consideration for both wholly and partially unsatisfied performance obligations, including mobilization and demobilization fees. These amounts are derived from the specific terms of our contracts, and the expected timing for revenue recognition is based on the estimated start date and duration of each contract according to the information known at March 31, 2024.

For the three-month periods ended March 31, 2024 and 2023, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

Contract Fulfillment Costs

Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying condensed consolidated balance sheets (Note 3). Our deferred contract costs totaled $24.0 million as of March 31, 2024 and $36.6 million as of December 31, 2023. For the three-month periods ended March 31, 2024 and 2023, we recorded $20.3 million and $4.7 million, respectively, related to amortization of these deferred contract costs. There were no associated impairment losses for any period presented.

For additional information regarding revenue recognition, see Notes 2 and 11 to our 2023 Form 10-K.

Note 9 — Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. Because holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common stock, we are required to compute earnings per share (“EPS”) under the two-class method in periods in which we have earnings. Under the two-class method, net income for each period is allocated based on the participation rights of both common shareholders and the holders of any participating securities as if earnings for the respective periods had been distributed. For periods in which we have a net loss we do not use the two-class method as holders of our restricted shares are not obligated to share in such losses.

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Basic EPS is computed by dividing net income allocated to common shareholders or net loss by the weighted average shares of our common stock outstanding. Diluted EPS is computed in a similar manner after considering the potential dilutive effect of share-based awards and convertible senior notes and taking the more dilutive of the two-class method and the treasury stock method or if-converted method, as applicable. The dilutive effect of share-based awards is computed using the treasury stock method, as applicable, which includes the incremental shares that would be hypothetically vested in excess of the number of shares assumed to be hypothetically repurchased with the assumed proceeds. The effect of convertible senior notes is computed for the periods in which they are outstanding using the if-converted method, if dilutive, which assumes conversion of the convertible senior notes into shares of our common stock at the beginning of the period, giving income recognition for the add-back of related interest expense (net of tax). The computations of the numerator (earnings or loss) 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
	March 31, 2024			March 31, 2023
	Income		Shares	Income		Shares
Basic and Diluted:
Net loss	$	(26,287)		$	(5,165)
Net loss available to common shareholders	$	(26,287)	152,369	$	(5,165)	151,764

Loss per share	$	(0.17)		$	(0.03)

We had net losses for the three-month periods ended March 31, 2024 and 2023. Accordingly, our diluted EPS calculation for these periods excluded the dilutive effect of share-based awards because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):


	Three Months Ended
	March 31,
	2024	2023
Diluted shares (as reported)	152,369	151,764
Share-based awards	2,705	2,740
Total	155,074	154,504

The following potentially dilutive shares related to the 2023 Notes and the 2026 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):


	Three Months Ended
	March 31,
	2024	2023
2023 Notes	—	3,168
2026 Notes	5,187	28,676

We have outstanding restricted stock units (“RSUs”) (Note 10) that can be settled in either cash or shares of our common stock or a combination thereof, which are not included in the computation of diluted EPS as cash settlement is assumed.

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Note 10 — Employee Benefit Plans

Long-Term Incentive Plan

As of March 31, 2024, there were approximately 2.5 million shares of our common stock available for issuance under our 2005 Long-Term Incentive Plan, as amended and restated (the “2005 Incentive Plan”). During the three-month period ended March 31, 2024, the following grants of share-based awards were made under the 2005 Incentive Plan:


			Grant Date
			Fair Value
Date of Grant	Award Type	Shares/Units	Per Share/Unit		Vesting Period/Vesting Date
January 1, 2024 ⁽¹⁾	RSU	375,730	$	10.28	33% per year over three years
January 1, 2024 ⁽¹⁾	PSU	351,410	$	12.30	100% on December 31, 2026
January 1, 2024 ⁽²⁾	Restricted stock	5,776	$	10.28	100% on January 1, 2026

(1)	Reflects grants to our executive officers.

(2)	Reflects grants to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash.

Restricted stock awards are based solely on service conditions and are accounted for as equity awards. Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting period on a straight-line basis. Forfeitures are recognized as they occur. No restricted stock awards have been granted to our executive officers or other employees since 2020. For each of the three-month periods ended March 31, 2024 and 2023, we recognized $0.3 million as share-based compensation related to restricted stock.

Our performance share units (“PSUs”) granted beginning in January 2021 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee of our Board and have been accounted for as equity awards. Those PSUs consist of two components: (i) 50% based on the performance of our common stock against peer group companies, which component contains a service and a market condition, and (ii) 50% based on cumulative total Free Cash Flow, which component contains a service and a performance condition. Free Cash Flow is calculated as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. Our PSUs cliff vest at the end of a three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being zero.

For PSUs with a service and a market condition that are accounted for as equity awards, compensation cost is measured based on the grant date estimated fair value determined using a Monte Carlo simulation model and subsequently recognized over the vesting period on a straight-line basis. For PSUs with a service and a performance condition that are accounted for as equity awards, compensation cost is initially measured based on the grant date fair value. Cumulative compensation cost is subsequently adjusted at the end of each reporting period to reflect the current estimation of achieving the performance condition. For the three-month periods ended March 31, 2024 and 2023, $1.3 million and $1.2 million, respectively, were recognized as share-based compensation related to PSUs. In the first quarter 2024, based on the performance of our common stock price as compared to our performance peer group and our cumulative total Free Cash Flow, in each case over a three-year performance period, 452,381 PSUs granted in 2021 vested at 181%, representing 818,812 shares of our common stock with a total market value of $8.4 million.

Our currently outstanding RSUs may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee and have been accounted for as liability awards. Liability RSUs are measured at their estimated fair value based on the closing share price of our common stock as of each balance sheet date, and subsequent changes in the fair value of the awards are recognized in earnings for the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability RSUs equals the actual payout value upon vesting. For the three-month periods ended March 31, 2024 and 2023, $1.5 million and $1.2 million, respectively, were recognized as compensation cost.

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In 2024 and 2023, we granted fixed-value cash awards of $6.1 million and $6.0 million, respectively, to select management employees under the 2005 Incentive Plan. The value of these cash awards is recognized on a straight-line basis over a vesting period of three years. For the three-month periods ended March 31, 2024 and 2023, $1.4 million and $1.2 million, respectively, were recognized as compensation cost.

Defined Contribution Plans

We sponsor a defined contribution 401(k) retirement plan (the “401(k) Plan”) in the U.S. We also contribute to various other defined contribution plans globally. For the three-month periods ended March 31, 2024 and 2023, we made contributions to our defined contribution plans totaling $1.4 million and $1.1 million, respectively.

Employee Stock Purchase Plan (“ESPP”)

As of March 31, 2024, 1.1 million shares were available for issuance under the ESPP. The ESPP currently has a purchase limit of 260 shares per employee per purchase period.

For more information regarding our employee benefit plans, including the 2005 Incentive Plan, the defined contribution plans and the ESPP, see Note 13 to our 2023 Form 10-K.

Note 11 — Business Segment Information

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. Our U.S., U.K. and Brazil Well Intervention operating segments are aggregated into the Well Intervention segment for financial reporting purposes. All material intercompany transactions between the segments have been eliminated. See Note 2 for more information on our business segments.

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


	Three Months Ended
	March 31,
	2024		2023
Net revenues —
Well Intervention	$	216,459	$	142,438
Robotics		50,309		49,222
Shallow Water Abandonment		26,853		49,381
Production Facilities		24,152		20,905
Intercompany eliminations		(21,562)		(11,862)
Total	$	296,211	$	250,084

Income (loss) from operations —
Well Intervention	$	18,679	$	(8,143)
Robotics		5,450		5,094
Shallow Water Abandonment		(12,428)		6,822
Production Facilities		(1,543)		5,157
Segment operating income (loss)		10,158		8,930
Change in fair value of contingent consideration		—		(3,992)
Corporate, eliminations and other		(11,434)		(13,241)
Total	$	(1,276)	$	(8,303)
Net interest expense		(5,477)		(4,187)
Losses related to convertible senior notes		(20,922)		—
Other non-operating income (expense), net		(310)		5,307
Loss before income taxes	$	(27,985)	$	(7,183)

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Intercompany segment amounts are derived primarily from equipment and services provided to other business segments. Intercompany segment revenues are as follows (in thousands):


	Three Months Ended
	March 31,
	2024		2023
Well Intervention	$	11,252	$	4,469
Robotics		10,228		7,393
Shallow Water Abandonment		82		—
Total	$	21,562	$	11,862

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


	March 31,		December 31,
	2024		2023
Well Intervention	$	1,891,832	$	1,790,971
Robotics		204,777		177,801
Shallow Water Abandonment		176,019		256,356
Production Facilities		115,283		120,234
Corporate and other		225,903		210,674
Total	$	2,613,814	$	2,556,036

Note 12 — Asset Retirement Obligations

Our asset retirement obligations (“AROs”) relate to mature offshore oil and gas properties (Droshky and Thunder Hawk Field) that we acquired with the intention to perform decommissioning work at the end of their life cycles. AROs are recorded initially at fair value and consist of estimated costs for subsea infrastructure decommissioning and P&A activities associated with our oil and gas properties. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the passage of time as accretion expense, which is a component of our depreciation and amortization expense. An ARO liability may also change based on revisions in estimated costs and/or timing to settle the obligations. The following table describes the changes in our AROs (in thousands):


	2024		2023
AROs at January 1,	$	61,356	$	51,956
Accretion expense		1,376		1,168
AROs at March 31,	$	62,732	$	53,124

Note 13 — Commitments and Contingencies and Other Matters

Commitments

Our Well Intervention segment has long-term charter agreements with Siem Offshore AS for the Siem Helix 1 and Siem Helix 2 vessels, whose terms expire in December 2030 and December 2031, respectively. Our Robotics segment has vessel charters for the Grand Canyon II, the Grand Canyon III, the Shelia Bordelon, the North Sea Enabler and the Glomar Wave. Our time charter agreement for the Grand Canyon II expires in December 2030. Our time charter agreement for the Grand Canyon III expires in May 2028. Our time charter agreement for the Shelia Bordelon in the Gulf of Mexico expires in June 2026. Our time charter agreement for the North Sea Enabler expires in December 2025. We have a three-year charter agreement for the Glomar Wave in the North Sea that expires in 2025.

Contingencies and Claims

From time to time, we may incur losses related to our contracts for matters such as costs in excess of contract consideration or claims related to disputes with customers and any obligations thereunder. While we believe we maintain appropriate accruals for such matters, the actual cost to us may be more or less than the amounts reserved.

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We are involved in various legal proceedings in the normal couse of business, including claims under the General Maritime Laws of the United States and the Merchant Marine Act of 1920 (commonly referred to as the Jones Act), contract-related disputes, employee-related disputes and subsequently identified legacy issues related to Alliance. We recognize losses for lawsuits when the probability of an unfavorable outcome is probable and we can reasonably estimate the amount of the loss. For insured claims, we recognize such losses to the extent they exceed applicable insurance coverage. Although we can give no assurance about the outcome of litigation, claims or other proceedings, we do not currently believe that any loss resulting from litigation, claims or other proceedings, to the extent not otherwise covered by insurance, will have a material adverse impact on our consolidated financial statements.

Note 14 — 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):

(1)	Exclusive of any income tax refunds.

Our capital additions include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions were $0.2 million at March 31, 2024 and $1.1 million at December 31, 2023.

Note 15 — Allowance for Credit Losses

We estimate current expected credit losses on our accounts receivable at each reporting date based on our credit loss history, adjusted for current factors including global economic and business conditions, offshore energy industry and market conditions, customer mix, contract payment terms and past due accounts receivable. The following table sets forth the activity in our allowance for credit losses (in thousands):


	2024		2023
Balance at January 1,	$	3,407	$	2,277
Additions ⁽¹⁾		293		141
Balance at March 31,	$	3,700	$	2,418

(1)	Additions reflect reserves for expected credit losses during the respective periods.

Note 16 — Fair Value Measurements

Our financial instruments include cash and cash equivalents, receivables, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments.

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


	March 31, 2024				December 31, 2023
	Principal		Fair		Principal		Fair
	Amount ⁽¹⁾		Value ⁽²⁾		Amount ⁽¹⁾		Value ⁽²⁾
2026 Notes (fully redeemed March 2024)	$	—	$	—	$	40,199	$	64,117
MARAD Debt (matures February 2027)		28,258		27,906		32,580		32,348
2029 Notes (mature March 2029)		300,000		318,000		300,000		315,987
Total debt	$	328,258	$	345,906	$	372,779	$	412,452

(1)	Principal amount includes current maturities and excludes any related unamortized debt discount and debt issuance costs. See Note 5 for additional disclosures on our long-term debt.

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(2)	The estimated fair value was determined using Level 2 fair value inputs under the market approach, which was determined using quotes in inactive markets.

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 or incorporates by reference various statements that contain forward-looking information regarding Helix and represent our current expectations or forecasts of 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 by reference herein that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “budget,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements although not all forward-looking statements contain such identifying words. Included in forward-looking statements are, among other things:

●

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

●

statements regarding projections of revenues, gross margins, expenses, earnings or losses, working capital, debt and liquidity, cash flows, future operations expenditures or other financial items;

●

statements regarding our backlog and commercial contracts and rates thereunder;

●

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

●

statements regarding the spot market, the continuation of our current backlog, visibility and future utilization, our spending and cost management efforts and our ability to manage changes, oil price volatility and its effects and results on the foregoing as well as our protocols and plans;

●

statements regarding energy transition and energy security;

●

statements regarding our ability to identify, effect and integrate acquisitions, joint ventures or other transactions and any subsequently identified legacy issues with respect thereto;

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statements regarding the acquisition, construction, completion, upgrades to or maintenance and/or regulatory certification of vessels, systems or equipment and any anticipated costs or downtime related thereto;

●

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

●

statements regarding our trade receivables and their collectability;

●

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

●

statements regarding our sustainability initiatives and the successes thereon or regarding our environmental efforts, including with respect to greenhouse gas emissions;

●

statements regarding global, market or investor sentiment with respect to fossil fuels;

●

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

●

statements regarding our existing activities in, and future expansion into, the offshore renewable energy market;

●

statements regarding potential developments, industry trends, performance or industry ranking;

●

statements regarding our human capital resources, including our ability to retain our senior management and other key employees;

●

statements regarding our share repurchase authorization or program;

●

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

●

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

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

●

the impact of domestic and global economic and market conditions and the future impact of such conditions on the offshore energy industry and the demand for our services;

●

the general impact of oil and natural gas price volatility and the cyclical nature of the oil and gas market;

●

the potential effects of regional tensions that have escalated or may escalate, including into conflicts or wars, and their impact on the global economy, oil and gas market, our operations, international trade, or our ability to do business with certain parties or in certain regions, and any governmental sanctions resulting therefrom;

●

the results of corporate initiatives such as alliances, partnerships, joint ventures, mergers, acquisitions, divestitures and restructurings, and any amounts payable in connection therewith, or the determination not to pursue or effect such initiatives;

●

the operating results of acquired properties and/or equipment;

●

the impact of inflation and our ability to recoup rising costs in the rates we charge to our customers;

●

the impact of our ability to secure and realize backlog, including any potential cancellation, deferral or modification of our work or contracts by our customers;

●

the ability to effectively bid, renew and perform our contracts, including the impact of equipment problems or failure;

●

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

●

the performance of contracts by customers, suppliers and other counterparties;

●

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

●

unexpected future operations expenditures, including the amount and nature thereof;

●

the effectiveness and timing of our vessel and/or system upgrades, regulatory certification and inspection as well as major maintenance items;

●

operating hazards, including unexpected delays in the delivery, chartering or customer acceptance, and terms of acceptance, of our assets;

●

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

●

the impact of foreign currency exchange controls, potential illiquidity of those currencies and exchange rate fluctuations;

●

the effectiveness of our risk management activities and processes, including with respect to our cybersecurity initiatives and disclosures;

●

the effects of competition;

●

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

●

the effects of our indebtedness, our ability to comply with debt covenants and our ability to reduce capital commitments;

●

the impact of our stock price on our financing activities such as repurchases of our common stock under share repurchase programs;

●

the effectiveness of our sustainability initiatives and disclosures;

●

the impact of current and future laws and governmental regulations and how they will be interpreted or enforced, including related to fossil fuel production, decommissioning, and litigation and similar claims in which we may be involved;

●

the future impact of international activity and trade agreements on our business, operations and financial condition;

●

the effectiveness of any future hedging activities;

●

the potential impact of a negative event related to our human capital resources, including a loss of one or more key employees;

●

the impact of general, market, industry or business conditions; and

●

the factors generally described in Item 1A. Risk Factors in our 2023 Form 10-K.

Our actual results could also differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2023 Form 10-K. Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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We caution you not to place undue reliance on forward-looking statements. 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 forward-looking statements, all of which are expressly qualified by the statements in this section, or provide reasons why actual results may differ. All forward-looking statements, express or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. We urge you to carefully review and consider the disclosures made in this Quarterly Report and our reports filed with the SEC and incorporated by reference in our 2023 Form 10-K that attempt to advise interested parties of the risks and factors that may affect our business.

EXECUTIVE SUMMARY

Our Business

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention, robotics and decommissioning operations. Our services are key in supporting a global energy transition by maximizing production of existing oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments. Our well intervention fleet includes seven purpose-built well intervention vessels and 12 subsea intervention systems. Our robotics equipment includes 39 work-class ROVs, six trenchers and two IROV boulder grabs. We charter robotics support vessels on long-term, short-term, flexible and spot bases to facilitate our ROV and trenching operations. Our Shallow Water Abandonment segment includes nine liftboats, six OSVs, three DSVs, one heavy lift derrick barge, one crew boat, 20 P&A systems and six CT systems. Our Production Facilities segment includes the HP I, the HFRS and our ownership of mature oil and gas properties.

Industry Influences and Market Environment

Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets and, in particular, the willingness of offshore energy companies to spend on operational activities and capital projects. The performance of our business is largely affected by the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, global health, and various other factors. Demand for decommissioning, which has been an area of growth for us in recent years, is affected by commodity prices as well as governmental regulations and political forces globally.

Oil prices continue to be volatile but have generally remained robust since 2020. Global demand for oil continues to experience growth, and we expect the current market conditions will maintain continued customer spending for the industry. Despite the current commodity price environment, factors that could threaten the current commodity price environment persist, including regional conflicts, unrest in the Middle East, decisions from members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”), various governmental and customer sustainability initiatives and continued shifting of resource allocation to renewable energy. We expect these factors will continue to contribute to commodity price volatility with the potential to temper customer spending for oil and gas projects.

We maximize production of existing oil and gas reserves for our customers primarily in our Well Intervention segment. Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig day rates are a pricing indicator for our services. Our customers have used drilling rigs on existing long-term contracts (rig overhang) to perform well intervention work instead of new drilling activities. Current volumes of work, rig utilization rates, the day rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our assets and services.

We are seeing oil and gas companies continue to invest in long-cycle exploration projects in addition to maintaining and/or increasing production from their existing reserves. As historically production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we expect oil and gas companies to continue to focus on optimizing production of their existing subsea wells.

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We support the energy transition to renewable energy through our services in offshore wind farm developments, primarily including subsea cable trenching and burial as well as seabed clearance and preparation services. Demand for our services in the renewable energy market is affected by various factors, including the pace of consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase the generation and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water and other regions, and government subsidies for renewable energy projects. We expect growth in our renewables services as the energy market transitions to continued offshore renewable energy developments.

Once end-of-life oil and gas wells have depleted their production, we decommission wells and infrastructure in our Well Intervention and Shallow Water Abandonment segments. Our operations service the life cycle of an oil and gas field and provide P&A and decommissioning services at the end of the life of a field as required by governmental regulations. We believe that we have a competitive advantage in performing these services efficiently. The demand for P&A services should grow over the mid- to long-term as the subsea tree base expands, as government regulations continue to place stronger emphasis on decommissioning aged wells worldwide (including subsea trees as well as mature dry tree wells in the shallow waters of the Gulf of Mexico), as customers look to reduce their decommissioning obligations and as customers shift resources to renewable energy.

Outlook

In 2024, despite a backdrop of a somewhat uncertain macro environment globally, we expect to experience another strong year of performance driven by increasing demand for our decommissioning services internationally and continued growth in the offshore renewables trenching market. The demand for shallow water decommissioning services in the Gulf of Mexico is expected to soften in the near term but should grow over the mid- to long-term.

Backlog

Our backlog is represented by signed contracts. As of March 31, 2024, our consolidated backlog totaled approximately $997 million, of which $663 million is expected to be performed over the remainder of 2024. Our various contracts with Shell globally, our contracts with Trident Energy and Petrobras in Brazil, our contracts with ExxonMobil globally, and our agreement for the HP I in the Gulf of Mexico represented approximately 65% of our total backlog as of March 31, 2024. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under GAAP. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.

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We evaluate our operating performance and financial condition based on EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt. EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand and compare our results to other companies that have different financing, capital and tax structures. Other companies may calculate their measures of EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other data prepared in accordance with GAAP.

We define EBITDA as earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude gains or losses on disposition of assets, acquisition and integration costs, gains or losses related to convertible senior notes, the change in fair value of contingent consideration and the general provision (release) for current expected credit losses, if any. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from asset sales and insurance recoveries (related to property and equipment), if any. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents. In the following reconciliations, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted.

The reconciliation of our net loss to EBITDA and Adjusted EBITDA is as follows (in thousands):


	Three Months Ended
	March 31,
	2024		2023
Net loss	$	(26,287)	$	(5,165)
Adjustments:
Income tax benefit		(1,698)		(2,018)
Net interest expense		5,477		4,187
Other (income) expense, net		2,216		(3,444)
Depreciation and amortization		46,353		37,537
EBITDA		26,061		31,097
Adjustments:
(Gain) loss on disposition of assets, net		150		(367)
Acquisition and integration costs		—		231
Change in fair value of contingent consideration		—		3,992
General provision (release) for current expected credit losses		(143)		141
Losses related to convertible senior notes		20,922		—
Adjusted EBITDA	$	46,990	$	35,094

The reconciliation of our cash flows from operating activities to Free Cash Flow is as follows (in thousands):


	Three Months Ended
	March 31,
	2024		2023
Cash flows from operating activities	$	64,484	$	(5,392)
Less: Capital expenditures, net of proceeds from asset sales and insurance recoveries		(3,242)		(6,300)
Free Cash Flow	$	61,242	$	(11,692)

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The reconciliation of our long-term debt to Net Debt is as follows (in thousands):


	March 31,		December 31,
	2024		2023
Long-term debt including current maturities	$	318,164	$	361,722
Less: Cash and cash equivalents		(323,849)		(332,191)
Net Debt	$	(5,685)	$	29,531

Comparison of Three Months Ended March 31, 2024 and 2023

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our condensed consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars in thousands):


	Three Months Ended						Increase/
	March 31,						(Decrease)
	2024			2023			Amount		Percent
Net revenues —
Well Intervention	$	216,459		$	142,438		$	74,021	52	%
Robotics		50,309			49,222			1,087	2	%
Shallow Water Abandonment		26,853			49,381			(22,528)	(46)	%
Production Facilities		24,152			20,905			3,247	16	%
Intercompany eliminations		(21,562)			(11,862)			(9,700)
	$	296,211		$	250,084		$	46,127	18	%

Gross profit (loss) —
Well Intervention	$	23,144		$	(4,362)		$	27,506	631	%
Robotics		8,183			7,007			1,176	17	%
Shallow Water Abandonment		(9,763)			7,498			(17,261)	(230)	%
Production Facilities		(1,306)			5,783			(7,089)	(123)	%
Corporate, eliminations and other		(704)			(742)			38
	$	19,554		$	15,184		$	4,370	29	%

Gross margin —
Well Intervention		11	%		(3)	%
Robotics		16	%		14	%
Shallow Water Abandonment		(36)	%		15	%
Production Facilities		(5)	%		28	%
Total company		7	%		6	%

Number of vessels, Robotics assets or Shallow Water Abandonment systems ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels		7 / 90	%		7 / 80	%
Robotics assets ⁽³⁾		47 / 58	%		46 / 56	%
Chartered Robotics vessels		6 / 74	%		5 / 91	%
Shallow Water Abandonment vessels ⁽⁴⁾		20 / 41	%		20 / 58	%
Shallow Water Abandonment systems ⁽⁵⁾		26 / 26	%		21 / 68	%

(1)

Represents the number of vessels, Robotics assets or Shallow Water Abandonment systems as of the end of the period, including spot vessels and those under term charters, and excluding acquired vessels prior to their in-service dates, vessels managed on behalf of third parties and vessels or assets disposed of and/or taken out of service.

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(2)

Represents the average utilization rate, which is calculated by dividing the total number of days the vessels, Robotics assets or Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period. Utilization rates of chartered Robotics vessels during the three-month periods ended March 31, 2024 and 2023 included 91 spot vessel days at full utilization and 13 spot vessel days at 81% utilization, respectively.

(3)	Consists of ROVs, trenchers and IROV boulder grabs.

(4)	Consists of liftboats, OSVs, DSVs, a heavy lift derrick barge and a crew boat.

(5)	Consists of P&A and CT systems.

Intercompany segment amounts are derived primarily from equipment and services provided to other business segments. Intercompany segment revenues are as follows (in thousands):


	Three Months Ended
	March 31,				Increase/
	2024		2023		(Decrease)
Well Intervention	$	11,252	$	4,469	$	6,783
Robotics		10,228		7,393		2,835
Shallow Water Abandonment		82		—		82
	$	21,562	$	11,862	$	9,700

Net Revenues. Our consolidated net revenues for the three-month period ended March 31, 2024 increased by 18% as compared to the same period in 2023, reflecting higher revenues in our Well Intervention, Robotics and Production Facilities business segments, offset in part by lower revenues in our Shallow Water Abandonment segment.

Our Well Intervention revenues increased by 52% for the three-month period ended March 31, 2024 as compared to the same period in 2023, primarily reflecting higher revenues on the Q7000 and the Q5000 and higher rates and utilization on the Seawell, offset in part by lower utilization on the Well Enhancer. The Q7000 had full utilization during the first quarter 2024 whereas the vessel was transiting from West Africa to Asia Pacific and undergoing regulatory and project related dockings during the first quarter 2023, and utilization increased on the Q5000 during the first quarter 2024 as the vessel underwent a regulatory docking during the first quarter 2023. The Seawell benefitted from being on contract during the entire first quarter 2024 in the western Mediterranean as compared to having had lower seasonal utilization and rates in the North Sea during the first quarter 2023. The Well Enhancer in the North Sea had lower utilization as compared to the prior year period as the vessel underwent a 54-day scheduled dry dock during the first quarter 2024.

Our Robotics revenues increased by 2% for the three-month period ended March 31, 2024 as compared to the same period in 2023, primarily reflecting higher chartered vessel days and trenching and ROV activities during the first quarter 2024. Chartered vessel days increased to 333 days during the first quarter 2024 as compared to 295 days during the first quarter 2023, although chartered vessel days in the first quarter 2024 included approximately 64 days of standby utilization at reduced rates. ROV and trencher utilization increased to 58% in the first quarter 2024 from 56% during the first quarter 2023 and included 85 days of integrated vessel trenching in the first quarter 2024 as compared to 66 days in the first quarter 2023.

Our Shallow Water Abandonment revenues decreased by 46% for the three-month period ended March 31, 2024 as compared to the same period in 2023. The decrease in revenues is due to lower activity levels that are reflective of the variable nature of operator spending as well as higher customer concentrations in the Gulf of Mexico shelf market, resulting in lower vessel and system utilization during the first quarter 2024 as compared to the first quarter 2023. Overall vessel utilization was 41% during the first quarter 2024 as compared to 58% during the first quarter 2023. P&A systems and CT systems achieved 626 days of utilization, or 26% on 26 systems, during the first quarter 2024 as compared to 1,277 days of utilization, or 68% on 21 systems, during the first quarter 2023.

Our Production Facilities revenues increased by 16% for the three-month period ended March 31, 2024 as compared to the same period in 2023, primarily reflecting higher oil and gas production as the Thunder Hawk wells were shut in for planned maintenance during the first quarter 2023.

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Gross Profit (Loss). Our consolidated gross profit increased by $4.4 million for the three-month period ended March 31, 2024 as compared to the same period in 2023, primarily reflecting increased profits from our Well Intervention and Robotics business segments, offset in part by losses from our Shallow Water Abandonment and Production Facilities segments.

Our Well Intervention segment had a gross profit of $23.1 million for the three-month period ended March 31, 2024 as compared to a gross loss of $4.4 million for the same period in 2023, primarily reflecting higher segment revenues.

Our Robotics gross profit increased by $1.2 million for the three-month period ended March 31, 2024 as compared to the same period in 2023, primarily reflecting higher revenues due to increased activities.

Our Shallow Water Abandonment segment had a gross loss of $9.8 million for the three-month period ended March 31, 2024 as compared to a gross profit of $7.5 million for the same period in 2023, primarily reflecting lower segment revenues.

Our Production Facilities segment had a gross loss of $1.3 million for the three-month period ended March 31, 2024 as compared to a gross profit of $5.8 million for the same period in 2023, primarily reflecting well workover costs of approximately $8.6 million related to the Thunder Hawk wells during the first quarter 2024.

Change in Fair Value of Contingent Consideration. The change in fair value of contingent consideration in the first quarter 2023 reflected an improvement in Helix Alliance’s results during the first quarter. We entered into an agreement and set the final earn-out during the fourth quarter 2023, which was paid on April 3, 2024.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $21.0 million for the three-month period ended March 31, 2024 as compared to $19.6 million for the same period in 2023, primarily reflecting an increase in professional fees, third party services and office-related costs.

Net Interest Expense. Our net interest expense totaled $5.5 million for the three-month period ended March 31, 2024 as compared to $4.2 million for the same period in 2023, primarily reflecting interest expense on our 2029 Notes, offset in part by higher interest income on our invested cash reserves (Note 5).

Losses Related to Convertible Senior Notes. The $20.9 million loss for the three-month period ended March 31, 2024 was associated with the retirement of our 2026 Notes (Note 5).

Other Income (Expense), Net. Net other expense was $2.2 million for the three-month period ended March 31, 2024 as compared to net other income of $3.4 million for the same period in 2023, primarily reflecting foreign currency losses related to the depreciation of the British pound primarily on U.S. dollar denominated intercompany debt in our U.K. entities.

Income Tax Benefit. Income tax benefit was $1.7 million for the three-month period ended March 31, 2024 as compared to $2.0 million for the same period in 2023. The effective tax rates for the three-month periods ended March 31, 2024 and 2023 were 6.1% and 28.1%, respectively. The decrease in effective tax rates was primarily attributable to the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event and reported in the current quarter (Note 6).

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LIQUIDITY AND CAPITAL RESOURCES

Financial Condition and Liquidity

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


	March 31,		December 31,
	2024		2023
Net working capital	$	257,728	$	249,223
Long-term debt (excluding current maturities)		309,199		313,430
Liquidity		419,401		431,471

Net Working Capital

Net working capital is equal to current assets minus current liabilities and includes cash and cash equivalents, current maturities of long-term debt and current operating lease liabilities. Net working capital measures short-term liquidity and is important for predicting cash flow and debt requirements. Net working capital at March 31, 2024 and December 31, 2023 includes $85.0 million of Alliance earn-out consideration that was paid in cash on April 3, 2024.

Long-Term Debt

Long-term debt in the table above includes our MARAD Debt, the 2023 Notes, the 2026 Notes and the 2029 Notes and excludes current maturities of $9.0 million at March 31, 2024 and $48.3 million at December 31, 2023, and is net of unamortized debt discount and debt issuance costs. See Note 5 for information relating to our long-term debt.

Liquidity

We define liquidity as cash and cash equivalents plus available capacity under our credit facility. Our liquidity at March 31, 2024 included $323.8 million of cash and cash equivalents and $95.6 million of available borrowing capacity under the Amended ABL Facility (Note 5). In March 2024, we settled the remaining $40.2 million aggregate principal amount of the 2026 Notes for $60.5 million in cash (excluding costs), offset in part by $4.4 million from the settlement of the remaining 2026 Capped Calls. Our liquidity at December 31, 2023 included $332.2 million of cash and cash equivalents and $99.3 million of available borrowing capacity under the Amended ABL Facility. In December 2023, we used $229.7 million of the cash proceeds from the 2029 Notes, as well as 1.5 million shares of our common stock, to repurchase $159.8 million aggregate principal amount of the 2026 Notes, offset in part by $15.6 million from the associated 2026 Capped Calls. On April 3, 2024, we paid $85.0 million of earn-out consideration in cash to the seller in the Alliance transaction.

In the current market environment, following the settlement of the Alliance earn-out we expect strong ongoing operating performance and cash flows, continued availability on the Amended ABL Facility and reductions in Net Debt (See “Results of Operations — Non-GAAP Financial Measures” for the definition of Net Debt). We believe that our cash on hand, internally generated cash flows and availability under the Amended ABL Facility will be sufficient to fund our operations and service our debt and other obligations over at least the next 12 months.

A period of weak industry activity may make it difficult to comply with the covenants and other restrictions in our debt agreements. Our failure to comply with the covenants and other restrictions could lead to an event of default. Decreases in our borrowing base may limit our ability to fully access the Amended ABL Facility. We currently do not anticipate borrowing under the Amended ABL Facility other than for the issuance of letters of credit.

During the three-month period ended March 31, 2024, we repurchased a total of 462,585 shares of our common stock for approximately $5.0 million pursuant to the 2023 Repurchase Program.

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Cash Flows

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


	Three Months Ended
	March 31,
	2024		2023
Cash provided by (used in):
Operating activities	$	64,484	$	(5,392)
Investing activities		(3,242)		(6,300)
Financing activities		(69,304)		(9,424)

Operating Activities

The increase in our operating cash flows for the three-month period ended March 31, 2024 as compared to the same period in 2023 primarily reflects lower operating losses, higher working capital inflows and lower regulatory recertification costs for our vessels and systems. Regulatory recertification spend on our vessels and systems amounted to $9.6 million and $17.2 million, respectively, during the comparable year over year periods.

Investing Activities

Cash flows used in investing activities for the three-month periods ended March 31, 2024 and 2023 reflect lower capital expenditures during the first quarter 2024.

Financing Activities

Net cash outflows from financing activities for the three-month period ended March 31, 2024 primarily reflect cash outflows of $60.7 million related to the 2026 Notes, $4.2 million in repurchases of our common stock under the 2023 Repurchase Program and the principal repayment of $4.3 million related to the MARAD Debt, offset in part by $4.4 million from the proportionate settlement of the 2026 Capped Calls. Net cash outflows from financing activities for the three-month period ended March 31, 2023 primarily reflect $5.0 million in repurchases of our common stock under the 2023 Repurchase Program and the repayment of $4.1 million related to the MARAD Debt.

Material Cash Requirements

Our material cash requirements include our obligations to repay our long-term debt, satisfy other contractual cash commitments and fund other obligations.

Long-term debt and other contractual commitments

The following table summarizes (in thousands) the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for property and equipment, operating lease obligations and Alliance earn-out consideration, as of March 31, 2024 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated maturities. Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory recertification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of March 31, 2024.

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We acquired Helix Alliance in July 2022 for total consideration that included cash plus an earn-out to the extent Helix Alliance’s financial results exceeded certain thresholds in 2022 and 2023. During the fourth quarter 2023, we finalized the calculation and agreed with the seller in the Alliance transaction on an $85.0 million earn-out that was paid in cash on April 3, 2024. Accordingly, we reported $85.0 million of Alliance earn-out consideration in “Accrued liabilities” in the condensed consolidated balance sheets (Note 3).


	Total		Short-Term		Long-Term
MARAD debt	$	28,258	$	8,965	$	19,293
2029 Notes		300,000		—		300,000
Interest related to debt		147,722		31,104		116,618
Property and equipment		17,924		17,924		—
Operating leases ⁽¹⁾		1,005,264		135,257		870,007
Earn-out consideration		85,000		85,000		—
Total cash obligations	$	1,584,168	$	278,250	$	1,305,918

(1)

Operating leases include vessel charters and facility and equipment leases. At March 31, 2024, our commitment related to long-term vessel charters totaled approximately $990.9 million, of which $533.3 million was related to the non-lease (services) components that are not included in operating lease liabilities in the condensed consolidated balance sheet as of March 31, 2024.

Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 12). Those obligations, which are presented on a discounted basis on the condensed consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk Field oil and gas properties and $37.1 million (undiscounted) for Droshky oil and gas properties as of March 31, 2024, none of which is expected to be paid during the next 12 months. We are entitled to receive $30.0 million (undiscounted) from Marathon Oil as certain decommissioning obligations associated with Droshky oil and gas properties are fulfilled.

Regulatory recertification and dry dock. Our vessels and systems are subject to certain regulatory recertification requirements that must be satisfied in order for the vessels and systems to operate. Recertification may require dry dock and other compliance costs on a periodic basis, usually every 30 months. Although the amount and timing of these costs may vary and are dependent on the timing of the certification renewal period, they generally range between $0.2 million to $15.0 million per vessel and $0.5 million to $5.0 million per system.

We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations and existing cash on hand, but may also come from availability under the Amended ABL Facility and access to capital markets.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our discussion and analysis of our financial condition and results of operations, as reflected in the condensed consolidated financial statements and related footnotes, are prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that have had or are reasonably likely to have a material impact on our financial condition or results of operations. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates involve a significant level of estimation uncertainty and may change over time as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. For information regarding our critical accounting estimates, see our “Critical Accounting Estimates” as disclosed in our 2023 Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

As a multi-national organization, we are subject to market risks associated with foreign currency exchange rates, interest rates and commodity prices.

Foreign Currency Exchange Rate Risk. Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. As such, our earnings are impacted by movements in foreign currency exchange rates when (i) transactions are denominated in currencies other than the functional currency of the relevant Helix entity or (ii) the functional currency of our subsidiaries is not the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the U.S., we endeavor to pay a portion of our expenses in local currencies to partially offset revenues that are denominated in the same local currencies. In addition, a substantial portion of our contracts are denominated, and provide for collections from our customers, in U.S. dollars.

Assets and liabilities of our subsidiaries that do not have the U.S. dollar as their functional currency are translated using the exchange rates in effect at the balance sheet date, and changes in the exchange rates can result in translation adjustments that are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of our condensed consolidated balance sheets. For the three-month period ended March 31, 2024, we recorded foreign currency translation losses of $6.7 million to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments as any outside stock basis differences would be realized in a tax-free manner.

When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the condensed consolidated statements of operations as a component of “Other income (expense), net.” Foreign currency gains or losses from the remeasurement of monetary assets and liabilities as well as unsettled foreign currency transactions, including intercompany transactions that are not of a long-term investment nature, are also recognized as a component of “Other income (expense), net.” For the three-month period ended March 31, 2024, we recorded net foreign currency losses of $2.2 million, primarily reflecting foreign currency losses related to U.S. dollar denominated intercompany debt in our U.K. entities.

Interest Rate Risk. In order to minimize the risk of changes to our cash flow due to changing interest rates, we generally borrow at fixed rates, but may borrow at variable rates from time to time. For fixed rate debt, changes in interest rates may not affect our interest expense, but could result in changes in the fair value of the debt instrument prior to maturity and we may be at risk upon refinancing maturing debt. For variable rate debt, changes in interest rates could affect our future interest expense and cash flows. We currently have no amounts outstanding under our ABL Facility or other debt subject to floating rates.

Commodity Price Risk. We are exposed to market price risks related to oil and natural gas with respect to offshore oil and gas production in our Production Facilities business. Prices are volatile and unpredictable and are dependent on many factors beyond our control. See Item 1A. Risk Factors in our 2023 Form 10-K for a list of factors affecting oil and gas prices.

Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of March 31, 2024. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2024 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

(b) Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the three-month period ended March 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 13 — Commitments and Contingencies and Other Matters to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Item 1A. Risk Factors

There have been no material changes during the period ended March 31, 2024 in our “Risk Factors” as discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2023.

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

Issuer Purchases of Equity Securities


				(c)	(d)
				Total number	Approximate dollar
				of shares	value of shares
	(a)	(b)		purchased as	that may yet be
	Total number	Average		part of publicly	purchased under the
	of shares	price paid		announced plans	plans or programs ⁽³⁾
Period	purchased ⁽¹⁾	per share		or programs ⁽²⁾	(in thousands)
January 1 to January 31, 2024	68,074	$	10.04	—	$	188,012
February 1 to February 29, 2024	—		—	—		188,012
March 1 to March 31, 2024	784,789		10.63	462,585		182,980
	852,863	$	10.58	462,585

(1)	Includes shares repurchased in open-market transactions pursuant to the 2023 Repurchase Program and shares forfeited in satisfaction of tax obligations upon vesting of share-based awards under our existing long-term incentive plans.

(2)	Represents shares repurchased under the 2023 Repurchase Program.

(3)	See Note 7 to this Quarterly Report on Form 10-Q and Note 10 to our 2023 Annual Report on Form 10-K for additional information regarding our share repurchase programs.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

(c) During the three-month period ended March 31, 2024, no director or “officer” of Helix adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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Item 6. Exhibits


Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.1	2005 Amended and Restated Articles of Incorporation, as amended, of Helix Energy Solutions Group, Inc.	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 Energy Solutions Group, Inc., as amended.	Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
31.1	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer.	Filed herewith
31.2	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Erik Staffeldt, Chief Financial Officer.	Filed herewith
32.1	Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.	Furnished herewith
101.INS	XBRL Instance Document.	The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Taxonomy Extension Schema Document.	Filed herewith
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.	Filed herewith
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith
104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).	Filed herewith

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SIGNATURES

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


		HELIX ENERGY SOLUTIONS GROUP, INC.
		(Registrant)

Date: April 26, 2024	By:	/s/ Owen Kratz
		Owen Kratz
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: April 26, 2024	By:	/s/ Erik Staffeldt
		Erik Staffeldt
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer)

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Date	Price Target	Rating	Analyst
10/24/2024		Buy → Neutral	BTIG Research
9/19/2024	$14.00	Strong Buy	Raymond James
10/26/2022	$10.00	Neutral → Buy	BTIG Research
7/27/2022	$6.00 → $8.00	In-line → Outperform	Evercore ISI
3/7/2022	$5.60 → $6.30	Overweight	Piper Sandler
2/1/2022	$4.50 → $5.60	Neutral → Overweight	Piper Sandler
7/28/2021	$5.30 → $4.50	Overweight → Neutral	Piper Sandler
7/16/2021		Neutral → Underperform	BofA Securities

Three Months Ended

March 31,

Cash paid for operating lease liabilities

Right-of-use assets obtained in exchange for new operating lease liabilities ⁽¹⁾