Edgar Filing: HORNBECK OFFSHORE SERVICES INC /LA

Hornbeck Offshore Services, Inc.

Date: August 9, 2013

/S/ JAMES O. HARP, JR.

James O. Harp, Jr.

Executive Vice President and Chief Financial Officer

Form 10-Q

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 June 30, 2013

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 001-32108

Hornbeck Offshore Services, Inc.

(Exact Name of Registrant as Specified in Its Charter)


Delaware		72-1375844
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

103 NORTHPARK BOULEVARD, SUITE 300

COVINGTON, LA 70433

(Address of Principal Executive Offices) (Zip Code)

(985) 727-2000

(Registrant’s Telephone Number, Including Area Code)

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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



Large accelerated filer x		Non-accelerated filer ¨

Accelerated filer ¨		Smaller reporting company ¨

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

The total number of shares of common stock, par value $.01 per share, outstanding as of July 31, 2013 was 36,025,027.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2013

TABLE OF CONTENTS


PART 1—FINANCIAL INFORMATION			1
Item 1—Financial Statements			1
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations			14
Item 3—Quantitative and Qualitative Disclosures About Market Risk			35
Item 4—Controls and Procedures			35

PART II—OTHER INFORMATION			36
Item 1—Legal Proceedings			36
Item 1A—Risk Factors			36
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds			36
Item 3—Defaults Upon Senior Securities			36
Item 4—Mine Safety Disclosures			36
Item 5—Other Information			36
Item 6—Exhibits			40

SIGNATURE			44

PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	June 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	636,174		$	576,678
Accounts receivable, net of allowance for doubtful accounts of $2,881 and $3,028, respectively		109,316			103,265
Deferred tax assets, net		43,880			28,720
Other current assets		20,763			22,846

Total current assets		810,133			731,509

Property, plant and equipment, net		2,018,432			1,812,110
Deferred charges, net		79,128			74,835
Other assets		12,813			13,277

Total assets	$	2,920,506		$	2,631,731

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	43,259		$	48,286
Accrued interest		13,706			14,790
Accrued payroll and benefits		15,660			13,748
Deferred revenue		21,419			19,425
Current portion of long-term debt, net of original issue discount of $4,517 and $11,093, respectively		245,483			238,907
Other accrued liabilities		13,416			8,349

Total current liabilities		352,943			343,505
Long-term debt, net of original issue discount of $65,403 and $74,470, respectively		1,059,597			850,530
Deferred tax liabilities, net		297,550			270,478
Other liabilities		2,820			1,373

Total liabilities		1,712,910			1,465,886

Stockholders’ equity:
Preferred stock: $0.01 par value; 5,000 shares authorized; no shares issued and outstanding		—			—
Common stock: $0.01 par value; 100,000 shares authorized; 36,016 and 35,479 shares issued and outstanding, respectively		360			355
Additional paid-in-capital		717,738			705,658
Retained earnings		490,079			460,090
Accumulated other comprehensive loss		(581	)		(258	)

Total stockholders’ equity		1,207,596			1,165,845

Total liabilities and stockholders’ equity	$	2,920,506		$	2,631,731

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(Unaudited)						(Unaudited)
Revenues	$	154,323		$	131,645		$	301,839		$	251,618
Costs and expenses:
Operating expenses		65,899			63,456			129,264			122,665
Depreciation		15,413			15,171			30,723			30,253
Amortization		8,628			7,107			16,184			13,024
General and administrative expenses		13,819			12,081			27,698			23,207

		103,759			97,815			203,869			189,149

Gain (loss) on sale of assets		1,599			(11	)		1,599			(3	)

Operating income		52,163			33,819			99,569			62,466
Other income (expense):
Loss on early extinguishment of debt		(1,457	)		(855	)		(25,776	)		(6,048	)
Interest income		668			461			1,245			1,014
Interest expense		(13,242	)		(14,342	)		(26,964	)		(28,274	)
Other income (expense), net		93			224			(14	)		329

		(13,938	)		(14,512	)		(51,509	)		(32,979	)

Income before income taxes		38,225			19,307			48,060			29,487
Income tax expense		14,395			7,293			18,071			11,166

Net income	$	23,830		$	12,014		$	29,989		$	18,321

Basic earnings per common share	$	0.66		$	0.34		$	0.84		$	0.52

Diluted earnings per common share	$	0.65		$	0.33		$	0.82		$	0.51

Weighted average basic shares outstanding		35,864			35,308			35,742			35,222

Weighted average diluted shares outstanding		36,499			36,050			36,425			36,029

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(Unaudited)						(Unaudited)
Net income	$	23,830		$	12,014		$	29,989		$	18,321
Other comprehensive income, net of tax:
Foreign currency translation loss		(435	)		(477	)		(323	)		(97	)

Total comprehensive income	$	23,395		$	11,537		$	29,666		$	18,224

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

HORNBECK OFFSHORE SERVICES, INC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Six Months Ended June 30,
	2013			2012
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	29,989		$	18,321
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		30,723			30,253
Amortization		16,184			13,024
Stock-based compensation expense		6,444			4,435
Loss on early extinguishment of debt		25,776			6,048
Provision for bad debts		(147	)		430
Deferred tax expense		11,559			10,723
Amortization of deferred financing costs		9,735			7,608
(Gain) loss on sale of assets		(1,599	)		3
Changes in operating assets and liabilities:
Accounts receivable		(5,653	)		(21,128	)
Other receivables and current assets		4,289			(2,241	)
Deferred drydocking charges		(18,726	)		(19,745	)
Accounts payable		(156	)		4,749
Accrued liabilities and other liabilities		2,140			1,585
Accrued interest		(1,083	)		5,023

Net cash provided by operating activities		109,475			59,088
CASH FLOWS FROM INVESTING ACTIVITIES:
Costs incurred for OSV newbuild program #5		(222,591	)		(80,793	)
Net proceeds from sale of assets		17,536			1,332
Vessel capital expenditures		(28,384	)		(9,728	)
Non-vessel capital expenditures		(2,938	)		(994	)

Net cash used in investing activities		(236,377	)		(90,183	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Tax benefit from share-based payments		4,757			—
Repayment of senior notes		(250,000	)		(300,000	)
Proceeds from the issuance of senior notes		450,000			375,000
Premium on the retirement of debt		(17,658	)		(3,692	)
Payments for public offering of common stock		—			(180	)
Deferred financing costs		(7,673	)		(7,531	)
Net cash proceeds from other shares issued		7,295			2,336

Net cash provided by financing activities		186,721			65,933

Effects of exchange rate changes on cash		(323	)		(97	)

Net increase in cash and cash equivalents		59,496			34,741
Cash and cash equivalents at beginning of period		576,678			356,849

Cash and cash equivalents at end of period	$	636,174		$	391,590

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES:
Cash paid for interest	$	27,932		$	18,377

Cash paid for income taxes	$	1,925		$	729

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

The accompanying unaudited consolidated financial statements do not include certain information and footnote disclosures required by United States generally accepted accounting principles, or GAAP. The interim financial statements and notes are presented as permitted by instructions to the Quarterly Report on Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, all adjustments necessary for a fair presentation of the interim financial statements have been included and consist only of normal recurring items. The unaudited quarterly financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Annual Report on Form 10-K of Hornbeck Offshore Services, Inc. (together with its subsidiaries, the “Company”) for the year ended December 31, 2012. The results of operations for the six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. Certain reclassifications have been made to prior period results to conform to current year presentation.

The consolidated balance sheet at December 31, 2012 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.

2. Earnings Per Share

Basic earnings per common share was calculated by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share was calculated by dividing net income by the weighted average number of common shares outstanding during the year plus the effect of dilutive stock options and restricted stock unit awards. Weighted average number of common shares outstanding was calculated by using the sum of the shares determined on a daily basis divided by the number of days in the period. The table below reconciles the Company’s earnings per share (in thousands, except for per share data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Net income (1)	$	23,830	$	12,014	$	29,989	$	18,321

Weighted average number of shares of common stock outstanding		35,864		35,308		35,742		35,222
Add: Net effect of dilutive stock options and unvested restricted stock (2)(3)(4)		635		742		683		807

Weighted average number of dilutive shares of common stock outstanding		36,499		36,050		36,425		36,029

Earnings per common share:
Basic	$	0.66	$	0.34	$	0.84	$	0.52

Diluted	$	0.65	$	0.33	$	0.82	$	0.51

(1)

Net income for the three and six months ended June 30, 2013 includes loss on early extinguishment of debt of $1.5 million and $25.8 million, respectively. Net income for the three and six months ended June 30, 2012 includes loss on early extinguishment of debt of $0.9 million and $6.0 million, respectively. See Note 3 for further information regarding the Company’s debt.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

(2)

For the three and six months ended June 30, 2013 and 2012, the Company had no anti-dilutive stock options. Stock options are anti-dilutive when the exercise price of the options is greater than the average market price of the common stock for the period or when the results from operations are a net loss.

(3)	As of June 30, 2013, the 2019 convertible senior notes and 2026 convertible senior notes were not dilutive, and as of June 30, 2012, the 2026 convertible senior notes were not dilutive, as the average price of the Company’s stock was less than the effective conversion price of such notes.

(4)

Dilutive unvested restricted stock units are expected to fluctuate from quarter to quarter depending on the Company’s performance compared to a predetermined set of performance criteria. See Note 4 to these financial statements for further information regarding certain of the Company’s restricted stock.

3. Long-Term Debt

As of the dates indicated, the Company had the following outstanding long-term debt (in thousands):


	June 30, 2013			December 31, 2012
8.000% senior notes due 2017, net of original issue discount of $4,771	$	—		$	245,229
5.875% senior notes due 2020		375,000			375,000
5.000% senior notes due 2021		450,000			—
1.500% convertible senior notes due 2019, net of original issue discount of $65,403 and $69,699		234,597			230,301
1.625% convertible senior notes due 2026, net of original issue discount of $4,517 and $11,093 (1)		245,483			238,907
Revolving credit facility due 2016		—			—

		1,305,080			1,089,437
Less current maturities		(245,483	)		(238,907	)

	$	1,059,597		$	850,530

(1)

The notes initially bear interest at a fixed rate of 1.625% per year, declining to 1.375% beginning on November 15, 2013. A portion of the proceeds from the Company’s 2019 convertible senior notes offering in August 2012 are expected to be used to retire the 2026 convertible senior notes in November 2013.

The Company’s 8.000% senior notes due 2017, or 2017 senior notes, had semi-annual cash interest payments of $10.0 million due and payable each March 1 and September 1, prior to the repurchase and redemption of such notes in March and May 2013, respectively, as discussed below. The Company’s 5.875% senior notes due 2020, or 2020 senior notes, have semi-annual cash interest payments of $11.0 million due and payable each April 1 and October 1. The Company’s 1.500% convertible senior notes due 2019, or 2019 convertible senior notes, have semi-annual cash interest payments of $2.3 million due and payable each March 1 and September 1. The Company’s 1.625% convertible senior notes due 2026, or 2026 convertible senior notes, have semi-annual cash interest payments of $2.0 million due May 15 and November 15, declining to 1.375%, or $1.7 million semi-annually, beginning on November 15, 2013. Subject to certain conversion and redemption features of the 2026 convertible senior notes, holders of such notes may require the Company to purchase all or a portion of their notes on each of November 15, 2013, November 15, 2016 and November 15, 2021. The Company intends to redeem all of the 2026 convertible senior notes at par on or after November 15, 2013.

On March 14, 2013, the Company commenced a cash tender offer for all of the outstanding $250.0 million aggregate principal amount of its 2017 senior notes. Senior notes

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

totaling approximately $234.7 million, or approximately 94% of the 2017 senior notes outstanding, were validly tendered during the designated tender period and were repurchased at 107.12% of par on March 28, 2013. The remaining $15.3 million of 2017 senior notes were redeemed at 106.20% of par on May 13, 2013. A loss on early extinguishment of debt for the 2017 senior notes of approximately $24.3 million was recorded during the first quarter of 2013 and includes the tender offer costs, an allocable portion of the write-off of unamortized financing costs and original issue discount, and a bond redemption premium. A loss on early extinguishment of debt of approximately $1.5 million was recorded during the second quarter of 2013 for those costs allocable to the 2017 senior notes redeemed on May 13, 2013.

On March 14, 2013, the Company issued $450.0 million in aggregate principal amount of 5.000% senior notes due 2021, or 2021 senior notes. The net proceeds to the Company from the offering were approximately $442.4 million, net of estimated transaction costs. The Company used $252.7 million of such proceeds to repurchase approximately 94% of the outstanding 2017 senior notes pursuant to its tender offer noted above. The Company used approximately $16.3 million of proceeds on May 13, 2013 to redeem the remaining 6% of the outstanding 2017 senior notes pursuant to the redemption noted above. The remaining proceeds are available for general corporate purposes, which may include funding for the acquisition, construction or retrofit of vessels. The 2021 senior notes mature on March 1, 2021 and require semi-annual interest payments of $11.3 million due and payable each March 1 and September 1 of each year until maturity, commencing September 1, 2013. The effective interest rate on the new senior notes is 5.21%. No principal payments are due until maturity. Holders of the 2021 senior notes are entitled to certain registration rights as set forth in an exchange and registration rights agreement dated as of March 28, 2013. The 2021 senior notes are senior unsecured obligations and rank equally in right of payment with other existing and future senior indebtedness and senior in right of payment to any subordinated indebtedness that may be incurred by the Company in the future. The 2021 senior notes are guaranteed by certain of the Company’s subsidiaries. The guarantees are full and unconditional, joint and several, and all of the Company’s non-guarantor subsidiaries are minor as defined in the Securities and Exchange Commission regulations. Hornbeck Offshore Services, Inc., as the parent company issuer of the 2021 senior notes, has no independent assets or operations other than its ownership interest in its subsidiaries and affiliates. There are no significant restrictions on the Company’s ability, or the ability of any guarantor, to obtain funds from its subsidiaries by such means as a dividend or loan, except for certain restrictions contained in the Company’s revolving credit facility restricting the payment of dividends by the Company’s two principal subsidiaries. The Company may, at its option, redeem all or part of the 2021 senior notes from time to time at specified redemption prices and subject to certain conditions required by the indenture governing the 2021 senior notes. The Company is permitted under the terms of the indenture to incur additional indebtedness in the future, provided that certain financial conditions set forth in the indenture are satisfied by the Company.

The Company has an undrawn senior secured revolving credit facility, with a borrowing base of $300.0 million and an accordion feature that allows for the potential expansion of the facility up to an aggregate of $500.0 million. The facility matures in November 2016.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

Under the Company’s revolving credit facility, it has the option of borrowing at a variable rate of interest equal to either (i) LIBOR, plus an applicable margin, or (ii) the greatest of the Prime Rate, the Federal Funds Effective Rate plus ¹/₂ of 1% and the one-month LIBOR plus 1%, plus in each case an applicable margin. The applicable margin for each base rate is determined by a pricing grid, which is based on the Company’s leverage ratio, as defined in the credit agreement governing the amended revolving credit facility. Unused commitment fees are payable quarterly at the annual rate ranging from 37.5 basis points to 50.0 basis points as determined by a pricing grid.

As of June 30, 2013, there were no amounts drawn under the Company’s $300.0 million revolving credit facility and $0.9 million posted as letters of credit. As of June 30, 2013, the Company was in compliance with all financial covenants required by its revolving credit facility and the full amount of the undrawn borrowing base under the facility was available to the Company for all permissible uses of proceeds, including working capital, if necessary.

The Company estimates the fair value of its 2020 senior notes, 2021 senior notes, 2019 convertible senior notes and 2026 convertible senior notes by primarily using quoted market prices. The fair value of the Company’s revolving credit facility, when there are outstanding balances, approximates its carrying value. The face value, carrying value and fair value of the Company’s total debt was $1,375.0 million, $1,305.1 million and $1,453.7 million, respectively, as of June 30, 2013. Given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2, of the three-level valuation hierarchy.

Capitalized Interest

During the three and six months ended June 30, 2013, the Company capitalized approximately $7.4 million and $13.4 million respectively, of interest costs related to the construction of vessels. During the three and six months ended June 30, 2012, the Company capitalized approximately $2.0 million and $3.5 million respectively, of interest costs related to the construction of vessels.

4. Incentive Compensation

Stock-Based Incentive Compensation Plan

The Company’s stock-based incentive compensation plan covers a maximum of 4.2 million shares of common stock that allows the Company to grant restricted stock awards, restricted stock unit awards, or collectively restricted stock, stock options and stock appreciation rights to employees and directors.

During the six months ended June 30, 2013, the Company granted cash-settled phantom restricted stock units, time-based restricted stock units and performance-based restricted stock units. Time-based restricted stock units were granted to executive officers and directors of the Company. Cash-settled phantom restricted stock units were granted to certain shoreside employees of the Company.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

Performance-based restricted stock units were granted to executive officers of the Company. The shares to be received under the performance-based restricted stock units are calculated based on the Company’s performance compared to three pre-determined criteria, as defined by the restricted stock agreements governing such awards. The actual number of shares that could be received by the award recipients can range from 0% to 100% of the Company’s awards depending on the Company’s performance. During the six months ended June 30, 2013, the Company granted 197,623 time-based restricted stock units and performance-based restricted stock units and 21,490 cash-settled phantom restricted stock units.

Compensation expense related to 2013 restricted stock unit grants is recognized over the three-year service period. The fair value of the Company’s performance-based restricted stock units, which is the stock price on the date of grant, is applied to the total shares that are expected to fully vest and is amortized over the vesting period, which is generally three years, based on the Company’s internal performance measured against the pre-determined criteria, as applicable. The compensation expense related to time-based restricted stock units and cash-settled phantom restricted stock units are amortized over a vesting period of up to three years, as applicable, and is determined based on the market price of the Company’s stock on the date of grant applied to the total shares that are expected to fully vest. The cash-settled phantom restricted stock units are re-measured quarterly and classified as a liability, due to the settlement of these awards in cash. In addition to the restricted stock units granted in 2013, the Company granted performance-based and time-based restricted stock units in 2010, 2011 and 2012. During the six months ended June 30, 2013, the Company issued 536,594 shares, in the aggregate, of stock due to: 1) employees exercising previously vested stock options, 2) vestings pursuant to share-based compensation grants from such prior periods and 3) employee purchases under the Company’s Employee Stock Purchase Plan.

The stock-based compensation expense charges from previously issued equity grants and the financial impact such grants have on the Company’s operating results are reflected in the table below (in thousands, except for per share data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Income before taxes	$	3,122	$	2,185	$	6,444	$	4,435

Net income	$	1,945	$	1,359	$	4,021	$	2,754

Earnings per common share:
Basic	$	0.05	$	0.04	$	0.11	$	0.08

Diluted	$	0.05	$	0.04	$	0.11	$	0.08

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

5. Commitments and Contingencies

Vessel Construction

In November 2011, the Company announced, and has since expanded, its fifth OSV newbuild program. This program consists of vessel construction contracts with three domestic shipyards to build four 300 class OSVs, six 310 class OSVs, ten 320 class OSVs and four 310 class MPSVs. In June 2013, the Company placed in-service the first 300 class OSV under this program, the HOS Red Dawn. The 23 remaining vessels under this 24-vessel domestic newbuild program are expected to be placed in service as follows: four in 2013, 13 in 2014, four in 2015 and two in 2016. Based on current contracts and internal estimates, the aggregate total cost of this program, before construction period interest, is expected to be approximately $1,240.0 million. As of June 30, 2013, the Company had incurred construction costs of approximately $487.5 million, or 39.3%, since the inception of its fifth OSV newbuild program.

200 Class OSV Retrofit Program

In September 2012, the Company awarded a contract for the upgrading and stretching of six of the Company’s Super 200 class DP-1 OSVs, converting them into 240 class DP-2 OSVs. The project costs for these discretionary vessel modifications are expected to be approximately $50.0 million, in the aggregate ($8.3 million each), and the Company expects to incur approximately 799 vessel-days of aggregate commercial downtime for the six vessels (roughly 133 vessel-days each). The first two vessels were re-delivered to the Company in May 2013 and the current schedule projects re-deliveries of two vessels each in September and December of 2013, respectively. As of June 30, 2013, the Company had incurred construction costs of approximately $24.0 million, or 48%, since the inception of its 200 class OSV retrofit program.

Contingencies

In the normal course of its business, the Company becomes involved in various claims and legal proceedings in which monetary damages are sought. It is management’s opinion that the Company’s liability, if any, under such claims or proceedings would not materially affect its financial position, results of operations, or cash flows. The Company insures against losses relating to its vessels, pollution and third party liabilities, including claims by employees under Section 33 of the Merchant Marine Act of 1920, or the Jones Act. Third party liabilities and pollution claims that relate to vessel operations are covered by the Company’s entry in a mutual protection and indemnity association, or P&I Club, as well as by marine liability policies in excess of the P&I Club’s coverage. In February 2013 and 2012, the terms of entry for our Downstream segment contained an annual aggregate deductible, or AAD, for which the Company remains responsible. The P&I Club is responsible for covered amounts that exceed the AAD, after payment by the Company of an additional individual claim deductible. The Company provides reserves for those portions of the AAD and any individual claim deductibles for which the Company remains responsible by using an estimation process that considers Company-specific and industry data, as well as management’s experience,

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

assumptions and consultation with outside counsel. As additional information becomes available, the Company will assess the potential liability related to its pending claims and revise its estimates. Although revisions to such estimates historically have not been material, changes in estimates of the potential liability could materially impact the Company’s results of operations, financial position or cash flows. As of June 30, 2013, the Company’s claims incurred under its P&I Club policies have not exceeded the AAD for the 2013 policy year.

During 2010 and 2011, the Company mobilized 12 vessels, in the aggregate, to Brazil to operate under long-term contracts for Petrobras. These vessels required a significant amount of modifications to comply with requirements of the contracts. The Company has been assessed penalties by Petrobras for late deliveries. In addition, these vessel charters with Petrobras include limitations regarding fuel consumption. Petrobras has asserted claims against the Company relating to excess fuel consumption. The Company’s exposure for these assessments, net of amounts accrued, is in the range of approximately $0.5 million to $8.0 million. The Company disagrees with a majority of these assessments. In addition, the Company also has claims against Petrobras for their contributory actions related to the vessels’ late deliveries. Such claims exceed the maximum exposure noted above. The Company is not able to predict the ultimate outcome of these claims and counterclaims with Petrobras as of June 30, 2013. While the Company cannot currently estimate the amounts or timing of the resolution of these matters, the Company believes that the outcome will not have a material impact on its liquidity or financial position, but the ultimate resolution could have a material impact on its interim or annual results of operations.

During 2012, an Upstream customer, ATP Oil and Gas, Inc., initiated a reorganization proceeding under Chapter 11 of the United States Bankruptcy Code. Pre-petition receivables from ATP were $4.8 million, of which the Company has recorded $0.9 million in reserves. While the Company believes that the net receivables are collectible, it will continue to monitor the proceedings, which may result in actual collections that may differ from the current estimate.

6. Segment Information

The Company provides marine transportation and logistics services through two business segments. The Company primarily operates new generation OSVs and MPSVs in the U.S. Gulf of Mexico, or GoM, other U.S. coastlines, Latin America and the Middle East and operates a shore-base facility in Port Fourchon, Louisiana through its Upstream segment. The OSVs, MPSVs and the shore-base facility principally support complex exploration and production projects by transporting cargo to offshore drilling rigs and production facilities and providing support for oilfield and non-oilfield specialty services, including military applications. The Downstream segment operates ocean-going tugs and tank barges primarily in the northeastern United States, the GoM, the Great Lakes and Puerto Rico. The ocean-going tugs and tank barges provide coastwise transportation of refined and bunker grade petroleum products, as well as non-traditional downstream services, such as support of deepwater well testing and other specialty applications for the Company’s Upstream customers.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

The following table shows reportable segment information for the three and six months ended June 30, 2013 and 2012, reconciled to consolidated totals and prepared on the same basis as the Company’s consolidated financial statements (in thousands).


	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Operating revenues:
Upstream
Domestic	$	107,308	$	84,315		$	200,965	$	141,043
Foreign (1)		30,503		37,383			69,372		88,548

		137,811		121,698			270,337		229,591

Downstream
Domestic		14,819		7,584			27,706		17,428
Foreign (1)(2)		1,693		2,363			3,796		4,599

		16,512		9,947			31,502		22,027

Total	$	154,323	$	131,645		$	301,839	$	251,618

Operating expenses:
Upstream	$	58,701	$	56,201		$	114,995	$	108,328
Downstream		7,198		7,255			14,269		14,337

Total	$	65,899	$	63,456		$	129,264	$	122,665

Depreciation:
Upstream	$	13,448	$	13,045		$	26,644	$	26,005
Downstream		1,965		2,126			4,079		4,248

Total	$	15,413	$	15,171		$	30,723	$	30,253

Amortization:
Upstream	$	7,460	$	5,761		$	13,683	$	9,998
Downstream		1,168		1,346			2,501		3,026

Total	$	8,628	$	7,107		$	16,184	$	13,024

General and administrative expenses:
Upstream	$	12,822	$	11,177		$	25,756	$	21,435
Downstream		997		904			1,942		1,772

Total	$	13,819	$	12,081		$	27,698	$	23,207

Gain (loss) on sale of assets:
Upstream	$	1,569	$	(11	)	$	1,569	$	(3	)
Downstream		30		—			30		—

Total	$	1,599	$	(11	)	$	1,599	$	(3	)

Operating income (loss):
Upstream	$	46,949	$	35,503		$	90,828	$	63,822
Downstream		5,214		(1,684	)		8,741		(1,356	)

Total	$	52,163	$	33,819		$	99,569	$	62,466

Loss on early extinguishment of debt:
Upstream	$	1,457	$	681		$	25,776	$	4,037
Downstream		—		174			—		2,011

Total	$	1,457	$	855		$	25,776	$	6,048

Capital expenditures:
Upstream	$	157,299	$	45,458		$	250,941	$	89,683
Downstream		310		974			598		1,004
Corporate		2,002		521			2,374		828

Total	$	159,611	$	46,953		$	253,913	$	91,515

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)


	As of June 30, 2013		As of December 31, 2012
Identifiable Assets:
Upstream	$	2,678,225	$	2,397,155
Downstream		204,984		203,128
Corporate		37,297		31,448

Total	$	2,920,506	$	2,631,731

Long-Lived Assets:
Upstream
Domestic (3)	$	1,590,567	$	1,244,509
Foreign (1)		256,821		393,318

		1,847,388		1,637,827
Downstream
Domestic		153,980		140,460
Foreign (1)(2)		9,682		28,028

		163,662		168,488
Corporate		7,382		5,795

Total	$	2,018,432	$	1,812,110

(1)

The Company’s vessels conduct operations in international areas from time to time. Vessels will routinely move to and from domestic and international operating areas. As these assets are highly mobile, the long-lived assets reflected above represent the assets that were present in international areas as of June 30, 2013 and December 31, 2012, respectively.

(2)	Included are amounts applicable to the Puerto Rico downstream operations, even though Puerto Rico is considered a possession of the United States and the Jones Act applies to vessels operating in Puerto Rican waters.

(3)	Included in the Company’s Upstream Domestic assets is $479.7 million and $299.6 million of vessel construction-in-progress as of June 30, 2013 and December 31, 2012, respectively.

7. Subsequent Event

On July 22, 2013, the Company entered into a definitive agreement with an affiliate of Genesis Energy, L.P. (NYSE: GEL) to sell its active Downstream fleet and related business for cash consideration of $230 million. Simultaneously with the execution of the definitive agreement, Genesis posted a $23 million deposit. The transaction is subject to customary closing conditions and regulatory clearances, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, and is anticipated to close by the end of the third quarter of 2013. The Company and Genesis also plan to enter into transition service agreements at closing in order to provide for a smooth transition of operations and services for both employees and customers.

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read together with our unaudited consolidated financial statements and notes to unaudited consolidated financial statements in this Quarterly Report on Form 10-Q and our audited financial statements and notes thereto included in our Annual Report on Form 10-K as of and for the year ended December 31, 2012. This discussion contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements. See “Forward Looking Statements” for additional discussion regarding risks associated with forward-looking statements. In this Quarterly Report on Form 10-Q, “company,” “we,” “us,” “our” or like terms refer to Hornbeck Offshore Services, Inc. and its subsidiaries, except as otherwise indicated. Please refer to Item 5—Other Information for a glossary of terms used throughout this Quarterly Report on Form 10-Q.

In this Quarterly Report on Form 10-Q, we rely on and refer to information regarding our industry from the BOEM, EIA and IHS-Petrodata, Inc. These organizations are not affiliated with us and are not aware of and have not consented to being named in this Quarterly Report on Form 10-Q. We believe this information is reliable. In addition, in many cases we have made statements in this Quarterly Report on Form 10-Q regarding our industry and our position in the industry based on our experience in the industry and our own evaluation of market conditions.

General

Our Upstream Segment

The OSV market is expanding globally. Generally, offshore exploration and production activities are increasingly focused on deep wells (as defined by total well depth rather than water depth), whether on the Outer Continental Shelf or in the deepwater or ultra-deepwater. These types of wells require high-specification equipment and have resulted in an on-going newbuild cycle for drilling rigs and for high-spec OSVs. As a result of the projected deepwater drilling activity levels worldwide, there were 99 floating rigs under construction or on order on August 1, 2013 and, as of that date, there were options outstanding to build 36 additional floating rigs. In addition, on that date, there were 114 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 37 additional high-spec jack-up rigs. Each drilling rig working on deep-well projects typically requires more than one OSV to service it, and the number of OSVs required per rig is dependent on many factors, including the type of activity being undertaken and the location of the rig. For example, based on the historical data for the number of floating rigs and OSVs working, we believe that two to four OSVs per rig are required in the GoM and even more OSVs are necessary per rig in Brazil where greater logistical challenges result in longer vessel turnaround times to service drill sites. Typically, during the initial drilling stage, more OSVs are required to supply drilling mud, drill pipe and other materials than at later stages of the drilling cycle. In addition, generally, more OSVs are required the farther a drilling rig is located from shore. Under normal weather conditions, the transit time to deepwater drilling rigs in the GoM and Brazil can typically range from six to 24 hours for a new generation vessel. In Brazil, transit time for a new generation vessel to some of the newer, more logistically remote deepwater drilling rig locations are more

appropriately measured in days, not hours. In addition to drilling rig support, deepwater and ultra-deepwater exploration and production activities will result in the expansion of other specialty-service offerings for our vessels. These markets include subsea construction support, installation, IRM work, and life-of-field services, which include well-stimulation, workovers and decommissioning.

Presently, our oilfield service operations are conducted in three primary geographic regions comprised of the GoM, Brazil and Mexico. Descriptions of these three regions are included below.

Gulf of Mexico

The GoM continues to be considered a world-class basin by exploration and production companies. In its Annual Energy Outlook 2013, the EIA estimated that the GoM contains 45 billion barrels of recoverable oil equivalent. According to IHS-Petrodata as of August 1, 2013, the number of floating rigs available in the GoM region is currently 43, which has increased from the pre-Macondo level of 34, because the 10 floaters that left the region and the four floaters that have been stacked or are currently being rebuilt have since been replaced by 23 vessels arriving in the region. Of the 43 rigs available in the GoM, 35 were actively drilling as of August 1, 2013. We expect at least four additional deepwater drilling units to arrive in the GoM during 2013 and 14 additional units to begin work in 2014. During 2012, the rate of deepwater drilling permit approvals improved significantly over 2011, however, the pace of permitting was still inconsistent compared to pre-Macondo levels. While the period of time required for BSEE to review, approve and issue drilling permits is generally longer than historical norms, our customers have indicated that the permitting process has become more repeatable and predictable.

Improvements in dayrates and utilization for our high-spec Upstream vessels continued through the first half of 2013. Leading-edge spot market OSV dayrates in the GoM for our 240 and 265 class DP-2 equipment were in the $38,000 to $45,000 range. Whether these rates can be sustained will depend on, among other things, the future rig-count and the pace of permitting in the GoM. Market conditions for high-spec DP-2 vessels may also be impacted during 2013 by the anticipated delivery of 21 additional Jones Act-qualified DP-2 vessels from U.S. shipyards, including four being constructed by the Company. This impact is expected to be mitigated with the announced mobilization of new drilling rigs to the GoM in the second half of 2013 and into 2014. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs increased $2,470, or roughly 12%, from $20,558 for the year-ago quarter to $23,028 for the second quarter of 2013. As of June 30, 2013, we had reactivated all of our previously stacked new generation OSVs. We expect that our DP-1 vessels will experience continued volatility as our deepwater customers continue their bias towards using only DP-2 vessels in deepwater operations. Six DP-1 vessels are being converted to 240 class DP-2 vessels under our 200 class OSV retrofit program during 2013, including two vessels that have already returned to service under their new configuration. The Company is considering whether to convert additional DP-1 vessels to DP-2.

The GoM could be adversely affected by an increasing shortage of, and competition for, qualified mariners. This shortage is being exacerbated by customer and regulatory driven requirements that increase the manning levels on many vessels, including drilling units that

operate in the GoM. Mariner shortages have driven up labor costs, which comprise the greatest portion of our operating costs. In the past, intense competition for licensed mariners has required the Company to unexpectedly increase our Upstream crew wages in response to across-the-board raises instituted by competitors. Such an increase usually results in a permanent increase in our annual operating costs. The most recent such increase occurred in April 2012, resulting in a quarterly operating expense increase of $5.0 million based upon the size of our mariner workforce at that time. We will also have incremental expenses due to roughly 100 mariners-in-training that are riding in the fleet and additional shoreside support staff in anticipation of the vessels that will be delivered under our fifth OSV newbuild program.

Brazil

Brazil is experiencing an increase in activity related to its large deepwater and pre-salt oilfield basins. This increase in activity is driven primarily by the state-owned oil company, Petroleo Brasileiro S.A., or Petrobras, and other producers, including BP p.l.c., Chevron Corporation, Exxon Mobil Corporation, OGX Petroleo e Gas Participacoes and Royal Dutch Shell plc. Petrobras has publicly announced plans to spend approximately $148 billion on exploration and production activities from 2013 through 2017 and has stated that its offshore supply vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Brazilian operators do not plan to add any new floating rigs by the end of 2013.

Since 2011, we have decreased our presence in Brazil from as many as 14 vessels to five vessels currently working under long-term contracts for Petrobras. We have remobilized to the GoM nine of our OSVs at the conclusion of their contracts. Current high operating costs as well as regulatory complexity and bureaucratic inefficiency are impacting our ability to generate operating margins in Brazil that are commensurate with those we are and have historically generated in the GoM. Moreover, Petrobras is the single largest consumer of our services in Brazil. As is typical with large state-owned national oil companies, contracts with Petrobras are onerous and contain multiple provisions that allow Petrobras to impose penalties and deduct payments for performance issues even if we disagree with the basis of those penalties or deductions. Petrobras has exercised these kinds of measures in our contracts and we expect that we will continue to confront similar issues with Petrobras going forward. In addition to regulatory complexity and the inherent difficulties associated with the Petrobras contracting regime, there is an acute shortage of mariners in Brazil, which we are required by law to employ on our vessels. This shortage is a significant contributor to escalating costs in Brazil and could present a barrier to our near-term growth in that market. We declined the opportunity to renew, with Petrobras, one of our remaining five 240 class vessels whose charter expires during the summer of 2013. Our long-term view in Brazil is that its preeminence as a deep water drilling region will offer us significant opportunities, particularly as our newbuild vessels are delivered. Those vessels will have the large capacities necessary for remote and ultra-deep water drilling regions, such as the pre-salt Brazilian market. We see Petrobras making significant investments intended to stem the logistical bottlenecks that have hampered its ability to take full advantage of its offshore fleet. As those chokepoints get worked out over the next few years, we believe that the 6,000 DWT vessels in our fifth OSV newbuild program will have a competitive advantage over 3,000 DWT vessels, which dominate Pebrobras’ fleet today.

Mexico

The primary customer in the Mexican market is the state-owned oil company, PEMEX. Production from the Cantarell field, which according to the EIA is PEMEX’s largest offshore oilfield, has declined to 500,000 barrels per day from approximately 2.1 million barrels per day at its peak. In 2011, 75% of Mexico’s total crude oil production came from offshore fields located in the Bay of Campeche, including the Cantarell field and the Ku-Maloob-Zaap field. In its July 2011 Outlook, PEMEX highlighted that 49% of its prospective resources, or 26.6 billion barrels of oil equivalent, are in the deepwater Gulf of Mexico. However, in order to develop this resource, PEMEX will likely need to tap the expertise of non-Mexican international oil companies. Under Article 27 of the Mexican constitution, private persons or companies (other than the state-owned PEMEX) are not allowed to explore for petroleum, and solid, liquid, or gaseous hydrocarbons. As a result, while we believe that Mexico could develop into a large market for deepwater activity, we do not expect this to occur until the Mexican government has found a solution to their constitutional constraints. We believe that this situation may be improved by the election of President Peña Nieto in July 2012, who campaigned on constitutional reform to reinvigorate the Mexican oil industry. Currently, there are five floating rigs and 35 jack-up rigs drilling offshore Mexico. PEMEX has announced plans to add seven more high-spec jack-up rigs during the remainder of 2013. We began working in Mexico in 2002 and currently have seven vessels working there under long-term contracts. We will continue to actively bid additional vessels into Mexico as tenders are issued by PEMEX.

Market conditions. As of August 1, 2013, we had 66% of our new generation OSV vessel-days contracted for the remainder of 2013. Our forward OSV contract coverage for the fiscal year ending December 31, 2014 currently stands at 27%. Included within our new generation contract coverage are five vessels on long-term charters with the United States government in defense capacities. With the $85 billion sequestration that went into effect March 1, 2013, it is possible that these contracts could be impacted. Our MPSV contract coverage has also increased as a result of the improving market conditions in the GoM. On the strength of long-term contracts awarded to two of our MPSVs during 2011 and recent spot market activity, MPSV contract coverage for 2013 and 2014 is currently 65% and 31%, respectively.

A sustained market recovery will depend upon several factors outside of our control including 1) the ability of operators and drilling contractors to comply with the new regulatory requirements; 2) the pace at which regulators approve plans and permit applications required by operators to drill; 3) the content of additional as yet unpromulgated rules that are expected to be issued; 4) the outcome of pending litigation brought by environmental groups challenging recent exploration plans approved by the DOI and 5) general economic conditions. In addition, there are currently 57 high-spec, Jones Act-qualified vessels under construction in U.S. shipyards that will deliver through 2016. Twenty-three of such vessels are being constructed by the Company.

All of our current Upstream vessels are qualified under the Jones Act to engage in U.S. coastwise trade, except for five foreign-flagged new generation OSVs, two foreign-flagged well stimulation vessels and two foreign-flagged MPSVs. As of June 30, 2013, our 50 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:


Operating Areas
Domestic
GoM			34
Other U.S. coastlines (1)			5

			39

Foreign
Brazil			5
Mexico			8
Middle East			2

			15

Total Upstream Vessels (2)			54

(1)	Includes five vessels that are currently supporting the military.

(2)

Excluded from this table is one conventional OSV that was stacked as of June 30, 2013. During the second quarter of 2013, we took delivery of a 300 class OSV, the HOS Red Dawn, we sold two of our six 220 class DP-1 new generation OSVs and activated the remaining stacked 220 class DP-1 new generation OSV.

Our Downstream Segment

As of June 30, 2013, our Downstream fleet was comprised of nine double-hulled tank barges and 12 ocean-going tugs, three of which are older, lower-horsepower tugs that are stacked. Although Downstream results have improved from the prior year, recent dayrates are still below the Downstream dayrates that existed from 2006 to 2008. Downstream vessel demand has increased as a result of transportation needs related to the Eagle Ford and Bakken shale trends and we believe these developments, along with the overall improvement of the U.S. economy, will continue to have a positive impact on our Downstream vessels operating in the GoM and in the Northeast. With the ongoing expansion of our Upstream fleet, we expect our Downstream segment to continue to represent a much smaller portion of our consolidated operating results compared to historical trends. On July 22, 2013 we entered into a definitive agreement to sell our active Downstream vessels.

Critical Accounting Estimates

This Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses our unaudited consolidated financial statements included in this Quarterly Report on Form 10-Q. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP. In other circumstances, we are required to make estimates, judgments and assumptions that we believe are reasonable based on available information. We base our estimates and judgments on historical experience and various other factors that we believe are reasonable based upon the information available. Actual results may differ from these estimates under different assumptions and conditions. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012.

Results of Operations

The tables below set forth, by segment, the average dayrates, utilization rates and effective dayrates for our vessels and the average number and size of vessels owned during the periods indicated. These new generation OSVs and tank barges generate a substantial portion of our revenues and operating profit. Excluded from the OSV information below are the results of operations for our MPSVs, conventional vessels, our shore-base facility, and vessel management services. The Company does not provide average or effective dayrates for its MPSVs. MPSV dayrates are impacted by highly variable customer-required cost-of-sales associated with ancillary equipment and services, such as ROVs, living quarters and cranes, which are typically recovered through higher dayrates charged to the customer. Due to the fact that each of our MPSVs have a workload capacity and significantly higher income generating potential than each of the Company’s new generation OSVs, the utilization and dayrate levels of our MPSVs could have a very large impact on our results of operations. For this reason, our consolidated operating results, on a period-to-period basis, are disproportionately impacted by the level of dayrates and utilization achieved by our four MPSVs.


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Upstream:
New Generation Offshore Supply Vessels:
Average number of new generation OSVs (1)		50.0			51.0			50.5			51.0
Average number of active new generation OSVs (2)		49.4			48.0			49.7			47.4
Average new generation OSV fleet capacity (DWT)		126,870			128,190			127,530			128,190
Average new generation vessel capacity (DWT)		2,538			2,514			2,526			2,514
Average new generation OSV utilization rate (3)		88.3	%		88.1	%		87.5	%		84.6	%
Average new generation OSV dayrate (4)	$	26,079		$	23,335		$	25,611		$	22,896
Effective dayrate (5)	$	23,028		$	20,558		$	22,410		$	19,370
Downstream:
Double-hulled tank barges:
Average number of tank barges (6)		9.0			9.0			9.0			9.0
Average fleet capacity (barrels)		884,621			884,621			884,621			884,621
Average barge capacity (barrels)		98,291			98,291			98,291			98,291
Average utilization rate (3)		100.0	%		74.6	%		97.8	%		80.0	%
Average dayrate (7)	$	20,169		$	16,284		$	19,765		$	16,811
Effective dayrate (5)	$	20,169		$	12,148		$	19,330		$	13,449

(1)

We owned 50 new generation OSVs as of June 30, 2013. For the three and six months ended June 30, 2013, our average number of new generation OSVs above includes the HOS Red Dawn, which is our first newly constructed OSV that was placed in service under our fifth OSV newbuild program in June 2013. Excluded from this data is one stacked conventional OSV that we consider to be a non-core asset. Also excluded from this data are four MPSVs owned and operated by the Company.

(2)

In response to weak market conditions, we elected to stack certain of our new generation OSVs on various dates in 2010 and 2011. Based on improved market conditions, we had re-activated all of our stacked new generation OSVs as of June 30, 2013. Active new generation OSVs represent vessels that are immediately available for service during each respective period.

(3)	Utilization rates are average rates based on a 365-day year. Vessels are considered utilized when they are generating revenues.

(4)	Average dayrates represent average revenue per day, which includes charter hire, crewing services and net brokerage revenues, based on the number of days during the period that the OSVs generated revenue.

(5)	Effective dayrate represents the average dayrate multiplied by the average utilization rate.

(6)

Other operating data for tugs and tank barges reflects our active Downstream fleet of nine double-hulled barges and nine ocean-going tugs. We also own three older, lower-horsepower tugs, which we consider to be non-core assets and are marketed for sale. On July 22, 2013, we entered into a definitive agreement to sell our active Downstream vessels.

(7)

Average dayrates represent average revenue per day, including time charters, brokerage revenue, revenues generated on a per-barrel-transported basis, demurrage, shipdocking and fuel surcharge revenue, based on the number of days during the period that the tank barges generated revenue. For purposes of brokerage arrangements, this calculation excludes that portion of revenue that is equal to the cost paid by customers of in-chartering third-party equipment.

Non-GAAP Financial Measures

We disclose and discuss EBITDA as a non-GAAP financial measure in our public releases, including quarterly earnings releases, investor conference calls and other filings with the Securities and Exchange Commission. We define EBITDA as earnings (net income) before interest, income taxes, depreciation and amortization. Our measure of EBITDA may not be comparable to similarly titled measures presented by other companies. Other companies may calculate EBITDA differently than we do, which may limit its usefulness as comparative measure.

We view EBITDA primarily as a liquidity measure and, as such, we believe that the GAAP financial measure most directly comparable to this measure is cash flows provided by operating activities. Because EBITDA is not a measure of financial performance calculated in accordance with GAAP, it should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.

EBITDA is widely used by investors and other users of our financial statements as a supplemental financial measure that, when viewed with our GAAP results and the accompanying reconciliation, we believe provides additional information that is useful to gain an understanding of the factors and trends affecting our ability to service debt, pay deferred taxes and fund drydocking charges and other maintenance capital expenditures. We also believe the disclosure of EBITDA helps investors meaningfully evaluate and compare our cash flow generating capacity from quarter to quarter and year to year.

EBITDA is also a financial metric used by management (i) as a supplemental internal measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; (ii) as a significant criteria for annual incentive cash compensation paid to our executive officers and bonuses paid to other shore-based employees; (iii) to compare to the EBITDA of other companies when evaluating potential acquisitions; and (iv) to assess our ability to service existing fixed charges and incur additional indebtedness.

The following table provides the detailed components of EBITDA as we define that term for the three and six months ended June 30, 2013 and 2012, respectively (in thousands).


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Components of EBITDA:
Net income	$	23,830		$	12,014		$	29,989		$	18,321
Interest expense, net
Debt obligations		13,242			14,342			26,964			28,274
Interest income		(668	)		(461	)		(1,245	)		(1,014	)

Total interest, net		12,574			13,881			25,719			27,260

Income tax expense		14,395			7,293			18,071			11,166
Depreciation		15,413			15,171			30,723			30,253
Amortization		8,628			7,107			16,184			13,024

EBITDA	$	74,840		$	55,466		$	120,686		$	100,024

The following table reconciles EBITDA to cash flows provided by operating activities for the three and six months ended June 30, 2013 and 2012, respectively (in thousands).


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
EBITDA Reconciliation to GAAP:
EBITDA	$	74,840		$	55,466		$	120,686		$	100,024
Cash paid for deferred drydocking charges		(11,292	)		(11,586	)		(18,726	)		(19,745	)
Cash paid for interest		(13,667	)		(3,621	)		(27,932	)		(18,377	)
Cash paid for taxes		(1,372	)		(197	)		(1,925	)		(729	)
Changes in working capital		19,453			(10,542	)		6,898			(13,001	)
Stock-based compensation expense		3,122			2,185			6,444			4,435
Loss on early extinguishment of debt		1,457			855			25,776			6,048
Changes in other, net		(1,605	)		427			(1,746	)		433

Net cash flows provided by operating activities	$	70,936		$	32,987		$	109,475		$	59,088

In addition, we also make certain adjustments to EBITDA for loss on early extinguishment of debt, stock-based compensation expense and interest income to compute ratios used in certain financial covenants of our revolving credit facility with various lenders. We believe that these ratios are a material component of certain financial covenants in such credit agreements and failure to comply with the financial covenants could result in the acceleration of indebtedness or the imposition of restrictions on our financial flexibility.

The following table provides certain detailed adjustments to EBITDA, as defined in our revolving credit facility, for the three and six months ended June 30, 2013 and 2012, respectively (in thousands).

Adjustments to EBITDA for Computation of Financial Ratios Used in Debt Covenants


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Loss on early extinguishment of debt	$	1,457	$	855	$	25,776	$	6,048
Stock-based compensation expense		3,122		2,185		6,444		4,435
Interest income		668		461		1,245		1,014

Set forth below are the material limitations associated with using EBITDA as a non-GAAP financial measure compared to cash flows provided by operating activities.

•

EBITDA does not reflect the future capital expenditure requirements that may be necessary to replace our existing vessels as a result of normal wear and tear,

•

EBITDA does not reflect the interest, future principal payments and other financing-related charges necessary to service the debt that we have incurred in acquiring and constructing our vessels,

•

EBITDA does not reflect the deferred income taxes that we will eventually have to pay once we are no longer in an overall tax net operating loss carryforward position, as applicable, and

•

EBITDA does not reflect changes in our net working capital position.

Management compensates for the above-described limitations in using EBITDA as a non-GAAP financial measure by only using EBITDA to supplement our GAAP results.

Summarized financial information concerning our reportable segments for the three months ended June 30, 2013 and 2012, respectively, is shown below in the following table (in thousands, except percentage changes):


	Three Months Ended June 30					Increase (Decrease)
	2013		2012			$ Change			% Change
Revenues:
Upstream
Domestic	$	107,308	$	84,315		$	22,993			27.3	%
Foreign		30,503		37,383			(6,880	)		(18.4	)

		137,811		121,698			16,113			13.2

Downstream
Domestic		14,819		7,584			7,235			95.4
Foreign (1)		1,693		2,363			(670	)		(28.4	)

		16,512		9,947			6,565			66.0

	$	154,323	$	131,645		$	22,678			17.2	%

Operating expenses:
Upstream	$	58,701	$	56,201		$	2,500			4.4	%
Downstream		7,198		7,255			(57	)		(0.8	)

	$	65,899	$	63,456		$	2,443			3.8	%

Depreciation and amortization:
Upstream	$	20,908	$	18,806		$	2,102			11.2	%
Downstream		3,133		3,472			(339	)		(9.8	)

	$	24,041	$	22,278		$	1,763			7.9	%

General and administrative expenses:
Upstream	$	12,822	$	11,177		$	1,645			14.7	%
Downstream		997		904			93			10.3

	$	13,819	$	12,081		$	1,738			14.4	%

Gain (loss) on sale of assets:
Upstream	$	1,569	$	(11	)	$	1,580			>100.0	%
Downstream		30		—			30			100.0

	$	1,599	$	(11	)	$	1,610			>100.0	%

Operating income (loss):
Upstream	$	46,949	$	35,503		$	11,446			32.2	%
Downstream		5,214		(1,684	)		6,898			>100.0

	$	52,163	$	33,819		$	18,344			54.2	%

Loss on early extinguishment of debt	$	1,457	$	855		$	602			70.4	%

Interest expense	$	13,242	$	14,342		$	(1,100	)		(7.7	)%

Interest income	$	668	$	461		$	207			44.9	%

Income tax expense	$	14,395	$	7,293		$	7,102			97.4	%

Net income	$	23,830	$	12,014		$	11,816			98.4	%

(1)	Included are the amounts applicable to our Puerto Rico Downstream operations, even though Puerto Rico is considered a possession of the United States and the Jones Act applies to vessels operating in Puerto Rican waters.

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Revenues. Revenues for the three months ended June 30, 2013 increased by $22.7 million, or 17.2%, to $154.3 million compared to the same period in 2012, primarily due to improved Upstream and Downstream market conditions. Our weighted-average active operating fleet for the three months ended June 30, 2013 was 71 vessels compared to 70 during the same period in 2012.

Revenues from our Upstream segment increased by $16.1 million, or 13.2%, to $137.8 million for the three months ended June 30, 2013 compared to $121.7 million for the same period in 2012. Our higher Upstream revenues primarily resulted from improved market conditions for our high-spec OSVs and MPSVs in the GoM. Revenue from our four-vessel MPSV fleet increased by $7.1 million, or 28.4%, compared to the same period in 2012. Our new generation OSV average dayrates were $26,079 for the second quarter of 2013 compared to $23,335 for the same period in 2012, an increase of $2,744, or 11.8%. Our new generation OSV utilization was 88.3% for the second quarter of 2013, which was in-line with the same period in 2012. Domestic revenues for our Upstream segment increased $23.0 million from the year-ago quarter due to improved spot market activity in the GoM. Foreign revenues for our Upstream segment decreased $6.9 million, or 18.4%, primarily due to an average of four fewer vessels deployed to foreign regions during the three months ended June 30, 2013 compared to the year-ago quarter. Foreign revenues, for the second quarter of 2013, comprised 22.1% of our total Upstream revenues compared to 30.7% for the year-ago quarter.

Revenues from our Downstream segment increased by $6.6 million, or 66.0%, to $16.5 million for the three months ended June 30, 2013 compared to the year-ago quarter. This revenue increase was due to improved market conditions in the GoM and in the Northeast and, to a lesser extent, 164 fewer days out-of-service related to the installation of vapor recovery systems on three barges and the regulatory drydocking of a fourth barge that occurred during the three months ended June 30, 2012. Our double-hulled tank barge average dayrates were $20,169 for the three months ended June 30, 2013, an increase of $3,885, or 23.9%, from $16,284 for the same period in 2012. Our double-hulled tank barge utilization was 100.0% for the second quarter of 2013 compared to 74.6% for the second quarter of 2012. Effective, or utilization-adjusted, dayates for our double-hulled tank barges were $20,169 for the three months ended June 30, 2013, which was $8,021, or 66.0%, higher than the prior-year quarter effective dayrates.

Operating expenses. Operating expenses for the three months ended June 30, 2013 increased by $2.4 million, or 3.8%, to $65.9 million. This increase was primarily associated with higher crew wages and the growth of our weighted-average active operating fleet by 1.4 vessels compared to the year-ago quarter.

Operating expenses for our Upstream segment were $58.7 million, an increase of $2.5 million, or 4.4%, for the three months ended June 30, 2013 compared to $56.2 million for the same period in 2012. Operating expenses for our Upstream segment were driven higher by the April 2012 mariner wage increases and by an increase in the number of active vessels in our fleet during the three months ended June 30, 2013. This increase was partially offset by lower operating costs for four vessels that were mobilized to the GoM from Latin America during the second half of 2012. Aggregate cash operating expenses for our Upstream

segment are projected to be in the range of $241.0 million to $246.0 million for the year ending December 31, 2013. Our cash operating expense estimate is exclusive of any additional repositioning expenses we may incur that are not recoverable through charter hire in connection with the potential relocation of more of our vessels to or from international markets; or any customer-required cost-of-sales related to future contract fixtures that are typically recovered through higher dayrates.

Operating expenses for our Downstream segment were $7.2 million for the three months ended June 30, 2013, which was in-line with the same period in 2012.

Depreciation and Amortization. Depreciation and amortization was $1.8 million higher for the three months ended June 30, 2013 compared to the same period in 2012. This increase is primarily due to higher shipyard costs for vessel regulatory drydockings for our Upstream vessels. Depreciation and amortization expense is expected to increase from current levels as the vessels under our current newbuild and conversion programs are placed in-service and when any newly constructed vessels undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative, or G&A, expenses of $13.8 million, or 9.0% of revenues, increased by $1.7 million during the three months ended June 30, 2013 compared to same period in 2012. This increase in G&A expenses was primarily attributable to higher shoreside incentive compensation expense. Our general and administrative expenses are expected to be in the approximate annual range of $54 million to $56 million for the year ending December 31, 2013, commensurate with our pending fleet growth. However, we still expect our G&A expenses as a percentage of revenues, or G&A margin, to remain within the historical range of our domestic public company OSV peer group.

Gain on Sale of Assets. During the second quarter of 2013, we sold certain non-core assets that resulted in an aggregate gain of approximately $1.6 million ($1.0 million after-tax or $0.03 per diluted share). No vessels were sold during the second quarter of 2012.

Operating Income. Operating income increased by $18.3 million, or 54.2%, to $52.2 million during the three months ended June 30, 2013 compared to the same period in 2012 for the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 34.1% for the three months ended June 30, 2013 compared to 29.2% for the same period in 2012. Operating income as a percentage of revenues for our Downstream segment was 31.6% for the three months ended June 30, 2013 compared to an operating loss of 16.9% for the same period in 2012.

Loss on Early Extinguishment of Debt. On May 13, 2013, the remaining $15.3 million of our 8.000% senior notes were redeemed. During the second quarter of 2013, we recorded a loss on early extinguishment of debt of approximately $1.5 million ($0.9 million after-tax or $0.02 per diluted share), which was comprised of the tender offer costs, the write-off of any remaining unamortized financing costs and original issue discount, and a bond redemption premium. During the second quarter of 2012, we recorded a loss on early extinguishment of debt of approximately $0.9 million ($0.6 million after-tax or $0.02 per diluted share) related to the tender offer for our 6.125% senior unsecured notes due 2014, or 2014 senior notes.

Interest Expense. Interest expense decreased $1.1 million during the three months ended June 30, 2013 compared to the same period in 2012. Higher capitalized interest

associated with vessels under construction was the primary reason that our interest expense decreased from the prior-year quarter. During the second quarter of 2013, we capitalized interest of $7.4 million, or roughly 36% of our total interest costs compared to capitalized interest of $2.0 million, or roughly 12% of our total interest costs for the year-ago quarter. This net decrease in interest expense, due to capitalized interest, was primarily offset by the incurrence of an incremental $5.4 million of interest expense (including $2.2 million of incremental original issue discount) related to the issuances of additional convertible senior notes in August 2012 and senior notes in March 2013.

Interest Income. Interest income was $0.7 million during the three months ended June 30, 2013, which was in-line with the same period in 2012. Our average cash balance increased to $678.5 million for the three months ended June 30, 2013 compared to $413.6 million for the same period in 2012. The average interest rate earned on our invested cash balances was 0.4% and 0.5% during the three months ended June 30, 2013 and 2012, respectively. The increase in average cash balance was primarily due to our August 2012 convertible senior note offering, which resulted in net cash proceeds of $266.0 million in the aggregate, and our March 2013 bond refinancing, which resulted in incremental net cash proceeds of $190.5 million in the aggregate, net of the costs of the tender offer and redemption of the 2017 senior notes.

Income Tax Expense. Our effective tax rate was 37.7% and 37.8% for the three months ended June 30, 2013 and 2012, respectively. During the second quarter of 2013, our income tax expense primarily consisted of deferred taxes. Our income tax rate differs from the federal statutory rate primarily due to expected state tax liabilities and items not deductible for federal income tax purposes.

Net Income. Operating performance increased by $11.8 million for reported net income of $23.8 million for the three months ended June 30, 2013. The higher net income for the second quarter of 2013 was primarily due to the increase in operating income based on improved market conditions discussed above and a $1.3 million pre-tax decrease in net interest expense .

Summarized financial information concerning our reportable segments for the six months ended June 30, 2013 and 2012, respectively, is shown below in the following table (in thousands, except percentage changes):


	Six Months Ended June 30					Increase (Decrease)
	2013		2012			$ Change			% Change
Revenues:
Upstream
Domestic	$	200,965	$	141,043		$	59,922			42.5	%
Foreign		69,372		88,548			(19,176	)		(21.7	)

		270,337		229,591			40,746			17.7

Downstream
Domestic		27,706		17,428			10,278			59.0
Foreign (1)		3,796		4,599			(803	)		(17.5	)

		31,502		22,027			9,475			43.0

	$	301,839	$	251,618		$	50,221			20.0	%

Operating expenses:
Upstream	$	114,995	$	108,328		$	6,667			6.2	%
Downstream		14,269		14,337			(68	)		(0.5	)

	$	129,264	$	122,665		$	6,599			5.4	%

Depreciation and amortization:
Upstream	$	40,327	$	36,003		$	4,324			12.0	%
Downstream		6,580		7,274			(694	)		(9.5	)

	$	46,907	$	43,277		$	3,630			8.4	%

General and administrative expenses:
Upstream	$	25,756	$	21,435		$	4,321			20.2	%
Downstream		1,942		1,772			170			9.6

	$	27,698	$	23,207		$	4,491			19.4	%

Gain (loss) on sale of assets:
Upstream	$	1,569	$	(3	)	$	1,572			>100.0	%
Downstream		30		—			30			100.0	%

	$	1,599	$	(3	)	$	1,602			>100.0	%

Operating income (loss):
Upstream	$	90,828	$	63,822		$	27,006			42.3	%
Downstream		8,741		(1,356	)		10,097			>100.0

	$	99,569	$	62,466		$	37,103			59.4	%

Loss on early extinguishment of debt	$	25,776	$	6,048		$	19,728			>100.0	%

Interest expense	$	26,964	$	28,274		$	(1,310	)		(4.6	)%

Interest income	$	1,245	$	1,014		$	231			22.8	%

Income tax expense	$	18,071	$	11,166		$	6,905			61.8	%

Net income	$	29,989	$	18,321		$	11,668			63.7	%

(1)	Included are the amounts applicable to our Puerto Rico Downstream operations, even though Puerto Rico is considered a possession of the United States and the Jones Act applies to vessels operating in Puerto Rican waters.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Revenues. Revenues for the six months ended June 30, 2013 increased by $50.2 million, or 20.0%, to $301.8 million compared to the same period in 2012, primarily due to improved Upstream and Downstream market conditions. Our weighted-average active operating fleet for the six months ended June 30, 2013 increased to 72 vessels compared to 69 during the same period in 2012, due to the reactivation of previously stacked Upstream vessels.

Revenues from our Upstream segment increased by $40.7 million, or 17.7%, to $270.3 million for the six months ended June 30, 2013 compared to $229.6 million for the same period in 2012. Our higher Upstream revenues primarily resulted from increased demand for our MPSVs and high-spec OSVs in the GoM. Revenue from our four-vessel MPSV fleet increased by $16.1 million, or 33.9%, compared to the same period in 2012. Our new generation OSV average dayrates were $25,611 for the first six months of 2013 compared to $22,896 for the same period in 2012, an increase of $2,715, or 11.9%. Our new generation OSV utilization was 87.5% for the first six months of 2013 compared to 84.6% for the same period in 2012. Our new generation OSV utilization for the first six months of 2013 was favorably impacted by an increase in demand for our high-spec OSVs in the GoM. Domestic revenues for our Upstream segment increased $59.9 million during the first six months due to improved spot market activity in the GoM. Foreign revenues for our Upstream segment decreased $19.2 million, or 21.7%, primarily due to an average of four fewer vessels deployed to foreign regions during the six months ended June 30, 2013 compared to the year-ago period. Foreign revenues, for the first six months of 2013, comprised 25.7% of our total Upstream revenues compared to 38.5% for the first six months of 2012.

Revenues from our Downstream segment increased by $9.5 million, or 43.0%, to $31.5 million for the six months ended June 30, 2013 compared to the first six months of 2012. This revenue increase was largely due to improved market conditions in the GoM and the Northeast and fewer days out-of-service for the installation of vapor-recovery systems on three of our barges and the regulatory drydocking of a fourth barge that occurred during the six months ended June 30, 2012. Our double-hulled tank barge average dayrates were $19,765 for the six months ended June 30, 2013, an increase of $2,954, or 17.6%, from $16,811 for the same period in 2012. Our double-hulled tank barge utilization was 97.8% for the first half of 2013 compared to 80.0% for the first half of 2012. Effective, or utilization-adjusted, dayrates for our double-hulled tank barges were $19,330 for the six months ended June 30, 2013, which was $5,881, or 43.7%, higher than the effective dayrates for the same period in 2012.

Operating expenses. Operating expenses for the six months ended June 30, 2013 increased by $6.6 million, or 5.4%, to $129.3 million. This increase was primarily associated with the growth of our weighted-average active operating fleet by 2.3 vessels compared to the year-ago period, and to higher crew wages.

Operating expenses for our Upstream segment were $115.0 million, an increase of $6.7 million, or 6.2%, for the six months ended June 30, 2013 compared to $108.3 million for the same period in 2012. Operating expenses for our Upstream segment were driven higher by the April 2012 mariner wage increases and by an increase in the number of active vessels in our fleet during the six months ended June 30, 2013. This increase was partially offset by lower operating costs for four vessels that were mobilized to the GoM from Latin America during the second half of 2012. Aggregate cash operating expenses for our Upstream

Operating expenses for our Downstream segment were $14.3 million for the six months ended June 30, 2013, which was in-line with the same period in 2012.

Depreciation and Amortization. Depreciation and amortization was $3.6 million higher for the six months ended June 30, 2013 compared to the same period in 2012. This increase is primarily due to higher shipyard costs for vessel regulatory drydockings for our Upstream vessels. Depreciation and amortization expense is expected to increase from current levels as the vessels under our current newbuild and conversion programs are placed in-service and when any newly constructed vessels undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $27.7 million, or 9.2% of revenues, increased by $4.5 million during the six months ended June 30, 2013 compared to same period in 2012. This increase in G&A expenses was primarily attributable to higher shoreside incentive compensation expense. Our general and administrative expenses are expected to be in the approximate annual range of $54 million to $56 million for the year ending December 31, 2013, commensurate with our pending fleet growth. However, we still expect our G&A expenses as a percentage of revenues, or G&A margin, to remain within the historical range of our domestic public company OSV peer group.

Gain on Sale of Assets. During the first six months of 2013, we sold certain non-core assets that resulted in an aggregate gain of approximately $1.6 million ($1.0 million after-tax or $0.03 per diluted share). No vessels were sold during the first half of 2012.

Operating Income. Operating income increased by $37.1 million to $99.6 million during the six months ended June 30, 2013 compared to the same period in 2012 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 33.6% for the six months ended June 30, 2013 compared to 27.8% for the same period in 2012. Operating income as a percentage of revenues for our Downstream segment was 27.7% for the six months ended June 30, 2013 compared to an operating loss of 6.4% for the same period in 2012.

Loss on Early Extinguishment of Debt. On March 14, 2013, we commenced a cash tender offer for all of the $250.0 million in aggregate principal amount of our 8.000% senior notes due 2017. Senior notes totaling approximately $234.7 million, or 94% of such notes outstanding, were validly tendered during the designated tender period, which ended on March 27, 2013. The remaining $15.3 million of our 8.000% senior notes were redeemed on May 13, 2013. During the first half of 2013, we recorded a loss on early extinguishment of debt of approximately $25.8 million ($16.1 million after-tax or $0.44 per diluted share), which was comprised of the tender offer costs, the write-off of unamortized financing costs and original issue discount, and a bond redemption premium. During the first half of 2012, we recorded a loss on early extinguishment of debt of approximately $6.0 million ($3.7 million after-tax or $0.11 per diluted share) related to the tender offer for our 2014 senior notes.

Interest Expense. Interest expense decreased $1.3 million during the six months ended June 30, 2013 compared to the same period in 2012. Higher capitalized interest associated with vessels under construction or conversion was the primary reason that our interest expense decreased from the year-ago period. During the first half of 2013, we capitalized interest of $13.4 million, or roughly 33% of our total interest costs compared to capitalized interest of $3.5 million, or roughly 11% of our total interest costs for the year-ago period. This net decrease in interest expense, due to capitalized interest, was primarily offset by the incurrence of an incremental $10.1 million of interest expense (including $4.5 million of incremental original issue discount) related to the issuances of additional senior notes in March 2012, convertible senior notes in August 2012, and senior notes in March 2013.

Interest Income. Interest income was $1.2 million during the six months ended June 30, 2013, which was in-line with the same period in 2012. Our average cash balance increased to $637.3 million for the six months ended June 30, 2013 compared to $393.2 million for the same period in 2012. The average interest rate earned on our invested cash balances was 0.4% and 0.5% during the six months ended June 30, 2013 and 2012, respectively. The increase in average cash balance was primarily due to our August 2012 convertible senior note offering, which resulted in net cash proceeds of $266.0 million in the aggregate, and our March 2013 bond refinancing, which resulted in incremental net cash proceeds of $190.5 million in the aggregate, net of the costs of the tender offer and redemption of the 2017 senior notes.

Income Tax Expense. Our effective tax rate was 37.6% and 37.9% for the six months ended June 30, 2013 and 2012, respectively. During the first six months of 2013, our income tax expense primarily consisted of deferred taxes. Our income tax rate differs from the federal statutory rate primarily due to expected state tax liabilities and items not deductible for federal income tax purposes.

Net Income. Operating performance increased by $11.7 million for reported net income of $30.0 million for the six months ended June 30, 2013. The higher net income for the first half of 2013 was primarily related to a $25.8 million pre-tax loss on early extinguishment of debt offset substantially by improved operating performance as discussed above.

Liquidity and Capital Resources

Our capital requirements have historically been financed with cash flows from operations, proceeds from issuances of our debt and common equity securities, borrowings under our credit facilities and cash received from the sale of assets. We require capital to fund on-going operations, obligations under our expanded fifth OSV newbuild program and our 200 class OSV retrofit program, vessel recertifications, discretionary capital expenditures and debt service and may require capital to fund potential future vessel construction, retrofit or conversion projects or acquisitions. The nature of our capital requirements and the types of our financing sources are not expected to change significantly for the remainder of 2013.

We have reviewed all of our debt agreements as well as our liquidity position and projected future cash needs. Despite volatility in financial and commodity markets, we remain confident in our current financial position, the strength of our balance sheet and the short- and long-term viability of our business model. To date, our liquidity has not been materially impacted and we do not expect that it will be materially impacted in the near-future due to

such volatility. We believe that our cash on-hand, projected operating cash flow and available borrowing capacity under our revolving credit facility will be more than sufficient to operate the Company and meet all of our near-term obligations, including milestone construction payments for both the contracted or approved vessels under our expanded fifth OSV newbuild program and our 200 class OSV retrofit program.

As of June 30, 2013, we had total cash and cash equivalents of $636.2 million. We also have a $300 million revolving credit facility, expandable up to $500 million, which is undrawn as of July 31, 2013. In addition, we expect to collect an additional $230 million in cash proceeds from the pending sale of our Downstream segment (including the $23 million deposit already received), which is expected to close during the third quarter of 2013. Excluding any cash requirements for potential new growth opportunities that may arise, our current cash on-hand, cash proceeds from the sale of assets and our internal cash flow projections indicate that our $300 million revolving credit facility should be sufficient to meet our liquidity needs for the foreseeable future. As of June 30, 2013, we had posted letters of credit for $0.9 million and had $299.1 million of credit available under our revolving credit facility. The full undrawn credit amount of such facility is available for all uses of proceeds, including working capital, if necessary. However, the intended uses of the facility are the construction or acquisition of assets that generate additional EBITDA and the potential repayment of existing long-term debt, if necessary.

Although we expect to continue generating positive working capital through our operations, events beyond our control, such as renewed regulatory-driven delays in the issuance of drilling plans and permits in the GoM, declines in expenditures for exploration, development and production activity, mild winter conditions or any extended reduction in domestic consumption of refined petroleum products and other reasons discussed under the “Forward Looking Statements” on page ii and the Risk Factors stated in Item 1A of our Annual Report on Form 10-K, may affect our financial condition, results of operations or cash flows. None of our funded debt instruments mature any sooner than November 2013 at which time we expect to retire our 1.625% convertible notes in full with cash on-hand today. Our currently undrawn revolving credit facility matures in November 2016.

Depending on the market demand for our vessels, long-term debt maturities and other growth opportunities that may arise, we may require additional debt or equity financing. We currently expect to generate sufficient cash flows from operations or use our revolving credit facility to meet our obligations under our recently expanded fifth OSV newbuild program, our OSV retrofit program, and scheduled recertifications of vessels. However, it is possible that, due to events beyond our control, including those described in our Risk Factors, should such need for additional financing arise, we may not be able to access the capital markets on attractive terms at that time or otherwise obtain sufficient capital to meet our maturing debt obligations or finance growth opportunities that may arise. We will continue to closely monitor our liquidity position, as well as the state of the global capital and credit markets.

On July 22, 2013, we entered into a definitive agreement with an affiliate of Genesis Energy, L.P. (NYSE: GEL) to sell our active Downstream fleet and related business for cash consideration of $230 million. Simultaneously with the execution of the definitive agreement, Genesis posted a $23 million deposit. The transaction is subject to customary closing conditions and regulatory clearances, including the expiration or termination of the waiting

period under the Hart-Scott-Rodino Act, and is anticipated to close by the end of the third quarter of 2013. We plan to enter into transition service agreements with Genesis, in order to provide for a smooth transition of operations and services for both employees and customers. We expect to use the after-tax proceeds of $224.4 million from this transaction for general corporate purposes, which may include retirement of debt or funding for the acquisition, construction or retrofit of vessels.

Cash Flows

Operating Activities. We rely primarily on cash flows from operations to provide working capital for current and future operations. Cash flows from operating activities were $109.5 million for the six months ended June 30, 2013 and $59.1 million for the same period in 2012. Operating cash flows for the first six months of 2013 were favorably affected by improved market conditions in both our Upstream and Downstream segments and to a lesser extent an increase in our weighted-average operating fleet.

Investing Activities. Net cash used in investing activities was $236.4 million for the six months ended June 30, 2013 and $90.2 million for the same period in 2012. Cash utilized during the first half of 2013 and 2012 primarily consisted of construction costs incurred for our fifth OSV newbuild program.

Financing Activities. Net cash provided by financing activities was $186.7 million for the six months ended June 30, 2013 compared to cash provided by financing activities of $65.9 million for the same period in 2012. Net cash provided by financing activities for the six months ended June 30, 2013 primarily resulted from the issuance of our 5.000% senior notes due 2021, or 2021 senior notes. These cash inflows were partially offset by the repurchase and retirement of our 8.000% senior notes due 2017. Net cash provided by financing activities for the six months ended June 30, 2012 primarily resulted from the issuance of our 5.875% senior notes due 2020 offset in part by the repayment of approximately $252.2 million of our 6.125% senior notes.

On March 14, 2013, we commenced a tender offer and solicitation of consents relating to the repurchase of our existing 2017 senior notes. The tender offer expired on April 10, 2013. On March 28, 2013, we completed the private placement of $450 million of 2021 senior notes, resulting in offering proceeds of approximately $442.4 million, net of estimated transaction costs. In connection with the tender offer and related consent solicitation, we used $252.7 million of such proceeds to repurchase approximately 94% of our outstanding $250.0 million aggregate principal amount of 2017 senior notes. The $15.3 million of remaining 2017 senior notes were redeemed on May 13, 2013. The remaining net proceeds will be used for general corporate purposes, which may include retirement of other debt or funding of the acquisition, construction or retrofit of vessels. As a result of the repurchase of the 2017 senior notes during the first half of 2013, we recorded a pre-tax loss on early extinguishment of debt of approximately $25.8 million ($16.1 million after-tax or $0.44 per diluted share).

Contractual Obligations

Debt

As of June 30, 2013, we had total debt of $1,305.1 million, net of original issue discount of $69.9 million. Our debt, net of original issue discount, is comprised of $375.0 million of our

5.875% senior notes due 2020, or 2020 senior notes, $450.0 million of our 5.000% senior notes due 2021, or 2021 senior notes, $234.6 million of our 1.500% convertible senior notes due 2019, or 2019 convertible senior notes and $245.5 million of our 1.625% convertible senior notes due 2026, or 2026 convertible senior notes. The effective interest rate on the 2020 senior notes is 6.08% with semi-annual cash interest payments of $11.0 million due and payable each April 1 and October 1. The effective interest rate on the 2021 senior notes is 5.21% with semi-annual cash interest payments of $11.3 million due and payable each March 1 and September 1. The $300.0 million, in face amount, of 2019 convertible senior notes bear interest at an annual coupon of 1.500% with semi-annual cash interest payments of $2.3 million due March 1 and September 1, beginning on March 1, 2013. The effective interest rate on such notes is 6.23%. The $250.0 million, in face amount, of 2026 convertible senior notes bear interest at an annual coupon of 1.625% with semi-annual cash interest payments of $2.0 million due May 15 and November 15, declining to 1.375%, or $1.7 million semi-annually, beginning on November 15, 2013. The effective interest rate on such notes is 6.36%. The senior notes do not require any payments of principal prior to their stated maturity dates, but pursuant to the indentures under which the 2020 and 2021 senior notes were issued, we would be required to make offers to purchase such senior notes upon the occurrence of specified events, such as certain asset sales or a change in control. All of the cash interest rates on our four tranches of senior unsecured notes are fixed.

Under our revolving credit facility, we have the option of borrowing at a variable rate of interest equal to either (i) the greater of the Prime Rate or the Federal Funds Effective Rate plus 1/2 of 1% or (ii) the London Interbank Offered Rate, or LIBOR; plus in each case an applicable margin. The applicable margin for each base rate is determined by a pricing grid, which is based on our leverage ratio, as defined in the credit agreement governing the revolving credit facility, as amended. The applicable LIBOR margin for the amended revolving credit facility ranges from 200 to 300 basis points. Unused commitment fees are payable quarterly at the annual rate of 37.5 to 50.0 basis points of the unused portion of the borrowing base of the new revolving credit facility, based on the defined leverage ratio. For additional information with respect to our revolving credit facility, our 2020 senior notes, our 2021 senior notes, our 2026 convertible senior notes, and our 2019 convertible senior notes, please refer to Note 3 of our consolidated financial statements included herein.

The credit agreement governing the revolving credit facility and the indentures governing our 2020 and 2021 senior notes impose certain operating and financial restrictions on us. Such restrictions affect, and in many cases limit or prohibit, among other things, our ability to incur additional indebtedness, make capital expenditures, redeem equity, create liens, sell assets and make dividend or other restricted payments. Based on our financial ratios for the six months ended June 30, 2013, the full amount of the undrawn borrowing base under our revolving credit facility is available to us for all uses of proceeds, including working capital, if necessary. For the six months ended June 30, 2013, we were in compliance with all of our debt covenants. We continuously review our debt covenants and report to our lenders our compliance with financial ratios on a quarterly basis. We also consider such covenants in evaluating transactions that will have an effect on our financial ratios.

Capital Expenditures and Related Commitments

The following table sets forth the amounts incurred for our newbuild and conversion programs, before construction period interest, during the three and six months ended

June 30, 2013 and since each program’s inception, respectively, as well as the estimated total project costs for each of our current expansion programs (in millions):


	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013		Incurred Since Inception		Estimated Program Totals (1)		Projected Delivery Dates (1)
Growth Capital Expenditures:
OSV newbuild program #5 (2)	$	130.4	$	213.0	$	487.5	$	1,240.0		2Q2013-4Q2016

(1)

Estimated Program Totals and Projected Delivery Dates are based on internal estimates and are subject to change due to delays and possible cost overruns inherent in any large construction project, including, without limitation, shortages of equipment, lack of shipyard availability, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, the inability to obtain necessary certifications and approvals and shortages of materials, component equipment or skilled labor. All of the above historical and budgeted capital expenditure project amounts for our newbuild program represent estimated cash outlays and do not include any allocation of capitalized construction period interest. Projected delivery dates correspond to the first and last vessels that are contracted with shipyards for construction and delivery under our currently active program, respectively.

(2)

Our fifth OSV newbuild program consists of vessel construction contracts with three domestic shipyards to build four 300 class OSVs, six 310 class OSVs, ten 320 class OSVs and four 310 class MPSVs. Delivery of the vessels to be constructed under this program is expected to occur on various dates during 2013 through 2016. Our first vessel delivered under this program, the HOS Red Dawn, was placed in service in June 2013. We expect to own and operate 54, 67 and 69 new generation OSVs as of December 31, 2013, 2014, and 2015, respectively. These vessel additions result in a projected average new generation OSV fleet complement of 50.8, 60.9, and 68.9 vessels for the fiscal years 2013, 2014, and 2015, respectively. The Company expects to own and operate four, four, six and eight MPSVs as of December 31, 2013, 2014, 2015 and 2016 respectively. These vessel additions result in a projected average MPSV fleet complement of 4.0, 4.0, 4.4 and 6.8 vessels for the fiscal years 2013, 2014, 2015 and 2016, respectively.

The following table summarizes the costs incurred, prior to the allocation of construction period interest, for maintenance and other capital expenditures for the three and six months ended June 30, 2013 and 2012, and a forecast for fiscal 2013 (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,
	2013		2012		2013		2012		2013
	Actual		Actual		Actual		Actual		Forecast
Maintenance and Other Capital Expenditures:
Maintenance Capital Expenditures
Deferred drydocking charges (1)	$	11.3	$	11.5	$	18.7	$	19.7	$	45.6
Other vessel capital improvements (2)		2.4		2.1		5.0		7.3		11.2

		13.7		13.6		23.7		27.0		56.8

Other Capital Expenditures
200 class OSV retrofit program (3)		17.5		—		21.7		—		47.7
Commercial-related vessel improvements (4)		1.6		1.8		1.7		2.4		19.4
Miscellaneous non-vessel additions (5)		2.5		0.5		3.0		1.0		4.9

		21.6		2.3		26.4		3.4		72.0

Total	$	35.3	$	15.9	$	50.1	$	30.4	$	128.8

(1)	Deferred drydocking charges for 2013 include the projected recertification costs for 19 OSVs, two MPSVs, one tank barge and three tugs.

(2)	Other vessel capital improvements include costs for discretionary vessel enhancements, which are typically incurred during a planned drydocking event to meet customer specifications.

(3)

Our 200 class OSV retrofit program consists of a vessel construction contract with a domestic shipyard to upgrade and stretch six of our Super 200 class DP-1 OSVs converting them into 240 class DP-2 OSVs. The estimated total project costs for such program, which commenced in December 2012 and is expected to be completed in December 2013, is $50.0 million. These vessel improvement costs are expected to result in higher dayrates charged to customers.

(4)	Commercial-related vessel improvements include items, such as cranes, ROVs, living quarters, vapor recovery systems and other specialized vessel equipment which costs are typically included in and offset, in whole or in part, by higher dayrates charged to customers.

(5)	Non-vessel capital expenditures are primarily related to information technology and shoreside support initiatives.

Forward Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements,” as contemplated by the Private Securities Litigation Reform Act of 1995, in which the Company discusses factors it believes may affect its performance in the future. Forward-looking statements are all statements other than historical facts, such as statements regarding assumptions, expectations, beliefs and projections about future events or conditions. You can generally identify forward-looking statements by the appearance in such a statement of words like “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “remain,” “should,” “will” or other comparable words or the negative of such words. The accuracy of the Company’s assumptions, expectations, beliefs and projections depends on events or conditions that change over time and are thus susceptible to change based on actual experience, new developments and known and unknown risks. The Company gives no assurance that the forward-looking statements will prove to be correct and does not undertake any duty to update them. The Company’s actual future results might differ from the forward-looking statements made in this Quarterly Report on Form 10-Q for a variety of reasons, including the effect of inconsistency by the United States government in the pace of issuing drilling permits and plan approvals in the GoM; the Company’s inability to successfully complete its fifth OSV newbuild program and its 200 class OSV retrofit program on-time and on-budget, which involves the construction, conversion and integration of highly complex vessels and systems; delays or inability to close the recently announced sale of the Downstream business segment; the inability to successfully market the vessels that the Company owns, is constructing or might acquire; an oil spill or other significant event in the United States or another offshore drilling region that could have a broad impact on deepwater and other offshore energy exploration and production activities, such as the suspension of activities or significant regulatory responses; the imposition of laws or regulations that result in reduced exploration and production activities or that increase the Company’s operating costs or operating requirements, including any such laws or regulations that may yet arise as a result of the Deepwater Horizon incident or the resulting drilling moratoria and regulatory reforms, as well as the outcome of pending litigation brought by environmental groups challenging exploration plans approved by the Department of Interior; less than anticipated success in marketing and operating the Company’s MPSVs presently owned or under construction; bureaucratic, administrative or operating barriers that delay vessels chartered in foreign markets from going on-hire or result in contractual penalties or deductions imposed by foreign customers; renewed weakening of demand for the Company’s services; unplanned customer suspensions, cancellations, rate reductions or non-renewals of vessel charters or failures to finalize commitments to charter vessels; the impact of planned sequester of federal spending pursuant to the Budget Control Act of 2011; industry risks; reductions in capital spending budgets by customers; a material reduction of Petrobras’ announced plans for or administrative barriers to exploration and production activities in Brazil; sustained declines in oil and natural gas prices; further increases in operating costs, such as mariner wage increases; the inability to accurately predict vessel utilization levels and dayrates; unanticipated difficulty in effectively competing in or operating in international markets; less than anticipated subsea infrastructure demand in the GoM and other markets; the level of fleet additions by the Company and its competitors that could result in over capacity in the markets in which the Company competes; economic and political risks; weather-related risks; the shortage of or the inability to attract and retain qualified personnel, including vessel personnel for active, unstacked and newly constructed vessels; regulatory risks; the repeal or administrative

weakening of the Jones Act or changes in the interpretation of the Jones Act related to the U.S. citizenship qualification; drydocking delays and cost overruns and related risks; vessel accidents, pollution incidents or other events resulting in lost revenue or expenses that are unrecoverable from insurance policies or other third parties; unexpected litigation and insurance expenses; fluctuations in foreign currency valuations compared to the U.S. dollar and risks associated with expanded foreign operations, such as non-compliance with or the unanticipated effect of tax laws, customs laws, immigration laws, or other legislation that result in higher than anticipated tax rates or other costs or the inability to repatriate foreign-sourced earnings and profits. In addition, the Company’s future results may be impacted by adverse economic conditions, such as inflation, deflation, or lack of liquidity in the capital markets, that may negatively affect it or parties with whom it does business resulting in their non-payment or inability to perform obligations owed to the Company, such as the failure of customers to fulfill their contractual obligations or the failure by individual banks to provide funding under the Company’s credit agreement, if required. Should one or more of the foregoing risks or uncertainties materialize in a way that negatively impacts the Company, or should the Company’s underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated in its forward-looking statements, and its business, financial condition and results of operations could be materially and adversely affected. Additional factors that you should consider are set forth in detail in the “Risk Factors” section of our Annual Report on Form 10-K as well as other filings the Company has made and will make with the Securities and Exchange Commission which, after their filing, can be found on the Company’s website, which is www.hornbeckoffshore.com.

Item 3—Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes to the market risk disclosures set forth in Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 4—Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1—Legal Proceedings

None.

Item 1A—Risk Factors

There were no changes to the risk factors previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

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

None.

Item 3—Defaults Upon Senior Securities

None.

Item 4—Mine Safety Disclosures

None.

Item 5—Other Information

Glossary of Terms

Currently used in our SEC Filings

“AHTS” means anchor-handling towing supply;

“ASC” means Financial Accounting Standards Board Accounting Standards Codification;

“average dayrate” means, when referring to OSVs or MPSVs, average revenue per day, which includes charter hire, crewing services and net brokerage revenues, based on the number of days during the period that the OSVs or MPSVs, as applicable, generated revenue; and, when referring to double-hulled tank barges, the average revenue per day, including time charters, brokerage revenue, revenues generated on a per-barrel-transported basis, demurrage, shipdocking and fuel surcharge revenue, based on the number of days during the period that the tank barges generated revenue. For purposes of tank barge brokerage arrangements, this calculation excludes that portion of revenue that is equal to the cost of in-chartering third-party equipment paid by customers;

“cabotage laws” means laws pertaining to the privilege of operating vessels in the navigable waters of a nation;

“coastwise trade” means the transportation of merchandise or passengers by water, or by land and water, between points in the United States, either directly or via a foreign port;

“conventional” means, when referring to OSVs, vessels that are at least 30 years old, are generally less than 200’ in length or carry less than 1,500 deadweight tons of cargo when originally built and primarily operate, when active, on the continental shelf;

“deepwater” means offshore areas, generally 1,000’ to 5,000’ in depth;

“Deepwater Horizon incident” means the subsea blowout and resulting oil spill at the Macondo well site in the GoM in April 2010 and subsequent sinking of the Deepwater Horizon drilling rig;

“deep-well” means a well drilled to a true vertical depth of 15,000’ or greater, regardless of whether the well was drilled in the shallow water of the Outer Continental Shelf or in the deepwater or ultra-deepwater;

“DOI” means U.S. Department of the Interior and all its various sub-agencies, including effective October 1, 2011 the Bureau of Ocean Energy Management (“BOEM”), which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies, and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs; BOEM and BSEE being successor entities to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), which effective June 2010 was the successor entity to the Minerals Management Service;

“domestic public company OSV peer group” includes SEACOR Holdings Inc. (NYSE:CKH), GulfMark Offshore, Inc. (NYSE:GLF) and Tidewater Inc. (NYSE:TDW);

“DP-1,” “DP-2” and “DP-3” mean various classifications of dynamic positioning systems on new generation vessels to automatically maintain a vessel’s position and heading;

“DWT” means deadweight tons;

“effective dayrate” means the average dayrate multiplied by the average utilization rate;

“EIA” means the U.S. Energy Information Administration;

“flotel” means on-vessel accommodations services, such as lodging, meals and office space;

“GAAP” means United States generally accepted accounting principles;

“GoM” means the U.S. Gulf of Mexico;

“high-specification” or “high-spec” means, when referring to new generation OSVs, vessels with cargo-carrying capacity of greater than 2,500 DWT (i.e., 240 class OSV notations or higher), and dynamic-positioning systems with a DP-2 classification or higher; and, when referring to jack-up drilling rigs, rigs capable of working in 400-ft. of water depth or greater, with hook-load capacity of 2,000,000 lbs. or greater, with cantilever reach of 70-ft. or greater; and minimum quarters capacity of 150 berths or more and dynamic-positioning systems with a DP-2 classification or higher;

“IHS-CERA” means the division of IHS Inc. focused on providing knowledge and independent analysis on energy markets, geopolitics, industry trends and strategy;

“IHS-Petrodata” means the division of IHS Inc. focused on providing data, information, and market intelligence to the offshore energy industry;

“IRM” means inspection, repair and maintenance, also known as “IMR,” or inspection, maintenance and repair, depending on regional preference;

“Jones Act” means the U.S. cabotage laws known as the Shipping Act of 1916 and the Merchant Marine Act of 1920, as amended;

“Jones Act-qualified” means, when referring to a vessel, a U.S.-flagged vessel qualified to engage in domestic coastwise trade under the Jones Act;

“long-term contract” means a time charter of one year or longer in duration;

“Macondo” means the well site location in the deepwater GoM where the Deepwater Horizon incident occurred, as well as, where applicable, such incident itself;

“MPSV” means a multi-purpose support vessel;

“MSRC” means the Marine Spill Response Corporation;

“new generation” means, when referring to OSVs, modern, deepwater-capable vessels subject to the regulations promulgated under the International Convention on Tonnage Measurement of Ships, 1969, which was adopted by the United States and made effective for all U.S.-flagged vessels in 1992 and foreign-flagged equivalent vessels;

“OPA 90” means the Oil Pollution Act of 1990;

“OSV” means an offshore supply vessel, also known as a “PSV,” or platform supply vessel, depending on regional preference;

“PEMEX” means Petroleos Mexicanos;

“Petrobras” means Petroleo Brasileiro S.A.;

“public company OSV peer group” means SEACOR Holdings Inc. (NYSE:CKH), GulfMark Offshore, Inc. (NYSE:GLF), Tidewater Inc. (NYSE:TDW), Farstad Shipping (NO:FAR), Solstad Offshore (NO:SOFF), Deep Sea Supply (NO:DESSC), DOF ASA (NO:DOF), Siem Offshore (NO:SIOFF), Groupe Bourbon SA (GBB:FP), Havila Shipping ASA (NO:HAVI), Eidesvik Offshore (NO:EIOF) and Ezra Holdings Ltd (SI:EZRA);

“ROV” means a remotely operated vehicle;

“TTB” means ocean-going tugs and tank barges; and

“ultra-deepwater” means offshore areas, generally more than 5,000’ in depth.

Item 6—Exhibits

Exhibit Index


Exhibit Number		Description of Exhibit
**2.1	—	Asset Purchase Agreement dated as of July 22, 2013, between Hornbeck Offshore Transportation, LLC and Genesis Marine, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 25, 2013).

3.1	—	Second Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 to the Company’s Form 10-Q for the quarter ended March 31, 2005).

3.2	—	Fourth Restated Bylaws of the Company adopted June 30, 2004 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q for the quarter ended June 30, 2004).

3.3	—	Amendment No. 1 to Fourth Restated Bylaws of the Company adopted June 21, 2012 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed June 27, 2012).

3.4	—	Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock filed with the Secretary of State of the State of Delaware on July 2, 2013 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed July 3, 2013).

4.1	—	Specimen stock certificates for the Company’s common stock, $0.01 par value (for U.S. citizens and non-U.S. citizens) (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-A/A filed July 3, 2013, Registration No. 001-32108).

4.2	—	Indenture dated as of November 23, 2004 between the Company, the guarantors named therein and Wells Fargo Bank, National Association (as Trustee), (including form of 6.125% Series B Senior Note due 2014 ) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed November 24, 2004).

4.3	—	Indenture dated as of November 13, 2006 by and among Hornbeck Offshore Services, Inc., the guarantors named therein, and Wells Fargo Bank, National Association, as Trustee (including form of 1.625% Convertible Senior Notes due 2026) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed November 13, 2006).

4.4	—	Confirmation of OTC Convertible Note Hedge dated as of November 7, 2006 by and between Hornbeck Offshore Services, Inc. and Jefferies International Limited (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed November 13, 2006).

4.5	—	Confirmation of OTC Convertible Note Hedge dated as of November 7, 2006 by and between Hornbeck Offshore Services, Inc. and Bear, Stearns International Limited, as supplemented on November 9, 2006 (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed November 13, 2006).


Exhibit Number		Description of Exhibit
4.6	—	Confirmation of OTC Convertible Note Hedge dated as of November 7, 2006 by and between Hornbeck Offshore Services, Inc. and AIG-FP Structured Finance (Cayman) Limited, as supplemented on November 9, 2006 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed November 13, 2006).

4.7	—	Confirmation of OTC Warrant Confirmation dated as of November 7, 2006 by and between Hornbeck Offshore Services, Inc. and Jefferies International Limited (incorporated by reference to Exhibit 4.6 to the Company’s Current Report on Form 8-K filed November 13, 2006).

4.8	—	Confirmation of OTC Warrant Confirmation dated as of November 7, 2006 by and between Hornbeck Offshore Services, Inc. and Bear, Stearns International Limited, as supplemented on November 9, 2006 (incorporated by reference to Exhibit 4.7 to the Company’s Current Report on Form 8-K filed November 13, 2006).

4.9	—	Confirmation of OTC Warrant Confirmation dated as of November 7, 2006 by and between Hornbeck Offshore Services, Inc. and AIG-FP Structured Finance (Cayman) Limited, as supplemented on November 9, 2006 (incorporated by reference to Exhibit 4.8 to the Company’s Current Report on Form 8-K filed November 13, 2006).

4.10	—	Indenture dated as of August 17, 2009 by and among Hornbeck Offshore Services, Inc., the guarantors named therein, and Wells Fargo Bank, National Association, as Trustee (including form of 8% Senior Notes due 2017) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed August 18, 2009).

4.11	—	Indenture, dated March 16, 2012 among Hornbeck Offshore Services, Inc., as issuer, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including form of 5.875% Senior Notes due 2020) (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed March 21, 2012).

4.12	—	First Supplemental Indenture, dated March 30, 2012 among Hornbeck Offshore Services, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (to the indenture governing the 1.625% Convertible Senior Notes due 2026) (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed April 4, 2012).

4.13	—	First Supplemental Indenture, dated March 30, 2012 among Hornbeck Offshore Services, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (to the indenture governing the 8.000% Senior Notes due 2017) (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed April 4, 2012).

4.14	—	Indenture dated as of August 13, 2012 by and among Hornbeck Offshore Services, Inc., the guarantors named therein, and Wells Fargo Bank, National Association, as Trustee (including form of 1.500% Convertible Senior Notes due 2019) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.15	—	Confirmation of Base Call Option Transaction dated as of August 7, 2012 by and between Hornbeck Offshore Services, Inc. and Barclays Bank PLC (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on August 13, 2012).


Exhibit Number		Description of Exhibit
4.16	—	Confirmation of Base Call Option Transaction dated as of August 7, 2012 by and between Hornbeck Offshore Services, Inc. and JPMorgan Chase Bank, National Association, London Branch (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.17	—	Confirmation of Base Call Option Transaction dated as of August 7, 2012 by and between Hornbeck Offshore Services, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.18	—	Confirmation of Additional Base Call Option Transaction dated as of August 8, 2012 by and between Hornbeck Offshore Services, Inc. and Barclays Bank PLC (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.19	—	Confirmation of Additional Base Call Option Transaction dated as of August 8, 2012 by and between Hornbeck Offshore Services, Inc. and JPMorgan Chase Bank, National Association, London Branch (incorporated by reference to Exhibit 4.6 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.20	—	Confirmation of Additional Base Call Option Transaction dated as of August 8, 2012 by and between Hornbeck Offshore Services, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.7 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.21	—	Confirmation of Base Warrant dated as of August 7, 2012 by and between Hornbeck Offshore Services, Inc. and Barclays Bank PLC (incorporated by reference to Exhibit 4.8 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.22	—	Confirmation of Base Warrant dated as of August 7, 2012 by and between Hornbeck Offshore Services, Inc. and JPMorgan Chase Bank, National Association, London Branch (incorporated by reference to Exhibit 4.9 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.23	—	Confirmation of Base Warrant dated as of August 7, 2012 by and between Hornbeck Offshore Services, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.10 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.24	—	Confirmation of Additional Warrants dated as of August 8, 2012 by and between Hornbeck Offshore Services, Inc. and Barclays Bank PLC (incorporated by reference to Exhibit 4.11 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.25	—	Confirmation of Additional Warrants dated as of August 8, 2012 by and between Hornbeck Offshore Services, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.13 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

4.26	—	Confirmation of Additional Warrants dated as of August 8, 2012 by and between Hornbeck Offshore Services, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.13 to the Company’s Current Report on Form 8-K filed on August 13, 2012).


Exhibit Number		Description of Exhibit
4.27	—	Second Supplemental Indenture with respect to the 8.000% Notes Indenture, dated March 27, 2013 among Hornbeck Offshore Services, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on March 28, 2013).

4.28	—	Indenture governing the 5.000% Notes, dated March 28, 2013 among Hornbeck Offshore Services, Inc., as issuer, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including form of 5.000% Senior Notes due 2021) (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on March 28, 2013).

4.29	—	Exchange and Registration Rights Agreement, dated as of March 28, 2013, among Hornbeck Offshore Services, Inc., the guarantors party thereto and Barclays Capital Inc., as representative of the Initial Purchasers (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed on March 28, 2013).

4.30	—	Rights Agreement dated as of July 1, 2013 between Hornbeck Offshore Services, Inc. and Computershare Inc., as Rights Agent, which includes as Exhibit A the Amended and Restated Certificate of Designation of Series A Preferred Stock, as Exhibit B the form of Right Certificate and as Exhibit C the form of Summary of Rights to Purchase Shares (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 3, 2013).

10.1	—	Amendment No. 3 to the Second Amended and Restated Hornbeck Offshore Services, Inc. Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 24, 2013).

*31.1	—	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2	—	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1	—	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2	—	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101	—	Interactive Data File

*	Filed herewith.

**	Schedules and exhibits to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company hereby undertakes to furnish supplementally a copy of any of the omitted schedules or exhibits to the Securities and Exchange Commission upon request.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Quarterly Report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized.