UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2012

OR

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

For the transition period from              to             

Commission file number 001-32108

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, 2012 was 35,384,685.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2012

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	13
Item 3—Quantitative and Qualitative Disclosures About Market Risk	33
Item 4—Controls and Procedures	34
PART II—OTHER INFORMATION	34
Item 1—Legal Proceedings	34
Item 1A—Risk Factors	34
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3—Defaults Upon Senior Securities	34
Item 4—Mine Safety Dosclosures	34
Item 5—Other Information	34
Item 6—Exhibits	37
SIGNATURE	40

i

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, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	391,590		$	356,849
Accounts receivable, net of allowance for doubtful accounts of $1,683 and $1,253, respectively		106,907			85,629
Deferred tax assets,net		20,285			3,221
Other current assets		25,075			22,866
Total current assets		543,857			468,565
Property, plant and equipment, net		1,676,510			1,605,785
Deferred charges, net		63,312			47,781
Other assets		13,741			14,215
Total assets	$	2,297,420		$	2,136,346
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	56,823		$	36,708
Accrued interest		13,978			8,955
Accrued payroll and benefits		12,837			12,781
Deferred revenue		3,399			1,774
Other accrued liabilities		11,682			7,131
Total current liabilities		98,719			67,349
Long-term debt, net of original issue discount of $22,619 and $29,352, respectively		852,381			770,648
Deferred tax liabilities, net		251,466			223,678
Other liabilities		1,174			1,683
Total liabilities		1,203,740			1,063,358
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; 35,348 and 35,013 shares issued and outstanding, respectively		353			350
Additional paid-in-capital		652,109			649,644
Retained earnings		441,394			423,073
Accumulated other comprehensive income (loss)		(176	)		(79	)
Total stockholders’ equity		1,093,680			1,072,988
Total liabilities and stockholders’ equity	$	2,297,420		$	2,136,346

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

1

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,
	2012			2011			2012			2011
	(Unaudited)						(Unaudited)
Revenues	$	131,645		$	80,817		$	251,618		$	153,084
Costs and expenses:
Operating expenses		63,456			48,414			122,665			90,036
Depreciation		15,171			15,320			30,253			30,529
Amortization		7,107			4,773			13,024			10,165
General and administrative expenses		12,081			8,497			23,207			18,361
		97,815			77,004			189,149			149,091
Gain (loss) on sale of assets		(11	)		—			(3	)		559
Operating income		33,819			3,813			62,466			4,552
Other income (expense):
Loss on early extinguishment of debt		(855	)		—			(6,048	)		—
Interest income		461			240			1,014			419
Interest expense		(14,342	)		(14,998	)		(28,274	)		(29,914	)
Other income (expense), net		224			81			329			77
		(14,512	)		(14,677	)		(32,979	)		(29,418	)
Income (loss) before income taxes		19,307			(10,864	)		29,487			(24,866	)
Income tax expense (benefit)		7,293			(3,839	)		11,166			(8,805	)
Net income (loss)	$	12,014		$	(7,025	)	$	18,321		$	(16,061	)
Basic earnings (loss) per common share	$	0.34		$	(0.26	)	$	0.52		$	(0.60	)
Diluted earnings (loss) per common share	$	0.33		$	(0.26	)	$	0.51		$	(0.60	)
Weighted average basic shares outstanding		35,308			26,875			35,222			26,799
Weighted average diluted shares outstanding		36,050			26,875			36,029			26,799

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

2

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(Unaudited)						(Unaudited)
Net income (loss)	$	12,014		$	(7,025	)	$	18,321		$	(16,061	)
Other comprehensive income, net of tax:
Foreign currency translation gain (loss)		(477	)		(13	)		(97	)		4
Total comprehensive income (loss)		11,537			(7,038	)		18,224			(16,057	)

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

3

HORNBECK OFFSHORE SERVICES, INC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended June 30,
	2012			2011
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	18,321		$	(16,061	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		30,253			30,529
Amortization		13,024			10,165
Stock-based compensation expense		4,435			3,926
Loss on early extinguishment of debt		6,048			—
Provision for bad debts		430			1,268
Deferred tax expense (benefit)		10,723			(7,575	)
Amortization of deferred financing costs		8,325			8,015
(Gain) loss on sale of assets		3			(559	)
Changes in operating assets and liabilities:
Accounts receivable		(21,128	)		3,096
Other receivables and current assets		(2,241	)		(3,396	)
Deferred drydocking charges		(19,745	)		(10,380	)
Accounts payable		4,749			3,489
Accrued liabilities and other liabilities		1,627			(780	)
Accrued interest		5,023			(4	)
Net cash provided by operating activities		59,847			21,733
CASH FLOWS FROM INVESTING ACTIVITIES:
Costs incurred for OSV newbuild program #5		(81,510	)		—
Net proceeds from sale of assets		1,332			2,055
Vessel capital expenditures		(9,728	)		(12,194	)
Non-vessel capital expenditures		(994	)		(698	)
Net cash used in investing activities		(90,900	)		(10,837	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Tax benefit (shortfall) from share-based payments		(42	)		(1,976	)
Repayment of senior notes		(300,000	)		—
Proceeds from the issuance of senior notes		375,000			—
Redemption premium on the retirement of debt		(3,692	)		—
Payments for public offerings of common stock		(180	)		—
Deferred financing costs		(7,531	)		(490	)
Net cash proceeds from other shares issued		2,336			1,138
Net cash provided by (used in) financing activities		65,891			(1,328	)
Effects of exchange rate changes on cash		(97	)		4
Net increase in cash and cash equivalents		34,741			9,572
Cash and cash equivalents at beginning of period		356,849			126,966
Cash and cash equivalents at end of period	$	391,590		$	136,538
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES:
Cash paid for interest	$	18,377		$	21,848
Cash paid for income taxes	$	729		$	499

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

4

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, 2011. The results of operations for the three months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. Certain reclassifications have been made to prior period results to conform to current year presentation.

The consolidated balance sheet at December 31, 2011 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 (Loss) Per Share

Basic earnings (loss) per common share was calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share was calculated by dividing net income (loss) 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 (loss) per share (in thousands, except for per share data):

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
Net income (loss)	$	12,014	$	(7,025	)	$	18,321	$	(16,061	)
Weighted average number of shares of common stock outstanding		35,308		26,875			35,222		26,799
Add: Net effect of dilutive stock options and unvested restricted stock (1)(2)(3)		742		—			807		—
Adjusted weighted average number of shares of common stock outstanding		36,050		26,875			36,029		26,799
Earnings (loss) per common share:
Basic	$	0.34	$	(0.26	)	$	0.52	$	(0.60	)
Diluted	$	0.33	$	(0.26	)	$	0.51	$	(0.60	)

(1) For the three and six months ended June 30, 2012, the Company had no anti-dilutive stock options. Due to a net loss, the Company excluded, for the calculation of loss per share, the effect of equity awards representing the rights to acquire 1,232 and 1,196 shares of common stock for the three and six months ended June 30, 2011, respectively, because the effect was anti-dilutive. 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.

5

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(2) As of June 30, 2012 and 2011, the 1.625% 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, which is $62.59 per share.

(3) Dilutive restricted stock is 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, 2012		December 31, 2011
6.125% senior notes due 2014, net of original issue discount of $215	$	—	$	299,785
8.000% senior notes due 2017, net of original issue discount of $5,179 and $5,571		244,821		244,429
5.875% senior notes due 2020		375,000		—
1.625% convertible senior notes due 2026, net of original issue discount of $17,440 and $23,566 (1)		232,560		226,434
Revolving credit facility due 2016		—		—
		852,381		770,648
Less current maturities		—		—
	$	852,381	$	770,648

(1) The notes initially bear interest at a fixed rate of 1.625% per year, declining to 1.375% beginning on November 15, 2013.

The Company’s 6.125% senior notes due 2014, or 2014 senior notes, had semi-annual cash interest payments of $9.2 million due and payable each June 1 and December 1, prior to the repurchase and redemption of such notes in March and April 2012, as discussed below. The Company’s 8.000% senior notes due 2017, or 2017 senior notes, have semi-annual cash interest payments of $10.0 million due and payable each March 1 and September 1. The Company’s 1.625% convertible senior notes due 2026, or 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 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. Conversely, the Company may also redeem all or a portion of the convertible senior notes on such dates.

On March 2, 2012, the Company commenced a cash tender offer for all of the outstanding $300.0 million aggregate principal amount of its 6.125% senior notes due 2014. Senior notes totaling approximately $252.2 million, or approximately 84% of the notes outstanding, were validly tendered during the designated tender period and were repurchased on March 16, 2012. The remaining $47.8 million of 2014 senior notes were redeemed at 101.021% of par on April 30, 2012. A loss on early extinguishment of debt for the 2014 senior notes of approximately $5.2 million was recorded during first quarter of 2012 and includes the tender offer costs, an allocable portion of the write-off of unamortized financing costs and

6

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

original issue discount, and a bond redemption premium. A loss on early extinguishment of debt of $0.9 million was recorded during the second quarter of 2012 for those costs allocable to the 2014 senior notes redeemed on April 30, 2012.

On March 2, 2012, the Company issued $375.0 million in aggregate principal amount of 5.875% senior notes due 2020, or 2020 senior notes. The net proceeds to the Company from the offering were approximately $367.4 million, net of estimated transaction costs. The Company used $259.9 million of proceeds on March 16, 2012 to repurchase approximately 84% of the outstanding 2014 senior notes pursuant to its tender offer noted above. The Company used $49.5 million of proceeds on April 30, 2012 to redeem the remaining 16% of the outstanding 2014 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 2020 senior notes mature on April 1, 2020 and require semi-annual interest payments at an annual rate of 5.875% on April 1 and October 1 of each year until maturity. The effective interest rate on the new senior notes is 6.08%. No principal payments are due until maturity. The 2020 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 2020 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 Commission regulations. Hornbeck Offshore Services, Inc., as the parent company issuer of the 2020 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 2020 senior notes from time to time at specified redemption prices and subject to certain conditions required by the indenture governing the 2020 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 amended and restated 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.

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.

7

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of June 30, 2012, there were no amounts drawn under the Company’s $300.0 million revolving credit facility and $1.3 million posted as letters of credit. As of June 30, 2012, 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 uses of proceeds, including working capital, if necessary.

The Company estimates the fair value of its 2014 senior notes, 2017 senior notes, 2020 senior notes and 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 $875.0 million, $852.4 million and $903.4 million, respectively, as of June 30, 2012. 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, 2012, the Company capitalized approximately $2.0 million and $3.5 million respectively, of interest costs related to the construction of vessels. No such interest was capitalized during the same periods in 2011.

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, 2012, the Company granted cash-settled restricted stock units, time-based restricted stock and performance-based restricted stock. Time-based restricted stock was granted to executive officers and directors of the Company. Cash-settled phantom restricted stock units were granted to executive officers and certain shore-side employees of the Company.

Performance-based restricted stock was granted to executive officers of the Company. The shares to be received under the performance-based restricted stock 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, 2012, the Company granted 200,565 time-based restricted stock and performance-based restricted stock and 137,358 cash-settled phantom restricted stock units. The cash-settled phantom

8

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

restricted stock units are re-measured quarterly and classified as a liability, due to the settlement of these awards in cash.

Compensation expense related to 2012 restricted stock grants is recognized over the three-year service period. The fair value of the Company’s performance-based restricted stock, 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 and cash-settled phantom restricted stock, is amortized over a vesting period of up to three years, as applicable, 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. In addition to the restricted stock granted in 2012, the Company granted performance-based and time-based restricted stock in 2009, 2010 and 2011 as well as stock options in 2011. During the six months ended June 30, 2012, the Company issued 334,823 shares, in the aggregate, of stock that vested pursuant to share-based compensation grants from such prior periods or were purchased 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,
	2012		2011		2012		2011
Income before taxes	$	2,185	$	1,725	$	4,435	$	3,926
Net income	$	1,359	$	1,116	$	2,754	$	2,536
Earnings per common share:
Basic	$	0.04	$	0.04	$	0.08	$	0.09
Diluted	$	0.04	$	0.04	$	0.08	$	0.09

In addition, the Company capitalized approximately $0.1 million of stock-based compensation expense that related directly to newbuild construction programs for the three and six months ended June 30, 2012. No such stock-based compensation expense was capitalized during the three and six months ended June 30, 2011.

5. 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

9

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 2012 and 2011, the terms of entry with the P&I Club for the Downstream segment contained an annual aggregate deductible (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, assumptions and consultation with outside counsel. As additional information becomes available, the Company will assess the potential liability related to its pending litigation and revise its estimates. Although revisions to such estimates have historically not been material, changes in estimates of the potential liability could materially impact the Company’s results of operations, financial position or cash flows.

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, 2012. 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 material impact on its interim or annual results of operations.

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 provide 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.

10

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, 2012 and 2011, 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,
	2012			2011			2012			2011
Operating revenues:
Upstream
Domestic	$	84,315		$	35,188		$	141,043		$	67,758
Foreign (1)		37,383			32,774			88,548			61,547
		121,698			67,962			229,591			129,305
Downstream
Domestic		7,584			10,705			17,428			20,304
Foreign (1)(2)		2,363			2,150			4,599			3,475
		9,947			12,855			22,027			23,779
Total	$	131,645		$	80,817		$	251,618		$	153,084
Operating expenses:
Upstream	$	56,201		$	39,924		$	108,328		$	74,138
Downstream		7,255			8,490			14,337			15,898
Total	$	63,456		$	48,414		$	122,665		$	90,036
Depreciation:
Upstream	$	13,045		$	13,198		$	26,005		$	26,290
Downstream		2,126			2,122			4,248			4,239
Total	$	15,171		$	15,320		$	30,253		$	30,529
Amortization:
Upstream	$	5,761		$	3,378		$	9,998		$	7,481
Downstream		1,346			1,395			3,026			2,684
Total	$	7,107		$	4,773		$	13,024		$	10,165
General and administrative expenses:
Upstream	$	11,177		$	7,611		$	21,435		$	16,627
Downstream		904			886			1,772			1,734
Total	$	12,081		$	8,497		$	23,207		$	18,361
Gain (loss) on sale of assets:
Upstream	$	(11	)	$	—		$	(3	)	$	—
Downstream		—			—			—			559
Total	$	(11	)	$	—		$	(3	)	$	559
Operating income (loss):
Upstream	$	35,503		$	3,851		$	63,822		$	4,769
Downstream		(1,684	)		(38	)		(1,356	)		(217	)
Total	$	33,819		$	3,813		$	62,466		$	4,552
Capital expenditures:
Upstream	$	45,864		$	4,645		$	90,400		$	11,593
Downstream		974			89			1,004			847
Corporate		521			203			828			452
Total	$	47,359		$	4,937		$	92,232		$	12,892

11

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	As of June 30, 2012		As of December 31, 2011
Identifiable Assets:
Upstream	$	2,063,342	$	1,915,137
Downstream		206,843		197,876
Corporate		27,235		23,333
Total	$	2,297,420	$	2,136,346
Long-Lived Assets:
Upstream
Domestic	$	1,188,566	$	965,535
Foreign (1)		309,265		460,099
		1,497,831		1,425,634
Downstream
Domestic		144,232		146,027
Foreign (1)(2)		28,579		28,344
		172,811		174,371
Corporate		5,868		5,780
Total	$	1,676,510	$	1,605,785

(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, 2012 and December 31, 2011, 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.

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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, 2011. 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 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 continues to expand globally. 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 71 floating rigs under construction or on order on July 31, 2012 and, as of that date, there were options outstanding to build 26 additional floating rigs and 19 units announced but yet to be contracted with shipyards. In addition, on that date, there were 90 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 34 additional high-spec jack-up rigs and three units announced but not yet contracted with shipyards. Each drilling rig working on deep-well projects typically requires more than one OSV to service it. 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 may be 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, more OSVs are generally 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. Moreover, in Brazil, transit times for a new generation vessel to some

13

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.

GoM. The GoM continues to be considered a world-class basin by exploration and production companies. The EIA estimates that the GoM contains 68 billion barrels of recoverable oil equivalent utilizing existing technologies. According to IHS-Petrodata, the number of floating rigs available in the GoM region is currently 40 and has increased from the pre-Macondo level of 34, because the nine floaters that either left the region or were stacked and the three floaters that have been stacked or are currently being rebuilt, have since been replaced by 18 similar or more advanced rigs. During 2011 and early 2012, a gradual improvement in the number of incremental deepwater well permits issued per month occurred, albeit through surges of activity followed by sharp declines. We anticipate that the pace of permit issuance will be uneven for some time to come. Of the 40 rigs available in the GoM, 29 were actively drilling as of July 31, 2012. For the five pre-Macondo years of 2005 through 2009, the historical average level of floating rigs actively drilling was 29 rigs with a peak of 35 rigs. We expect that floating rig growth in the GoM will continue to be driven by demand in the deepwater and ultra-deepwater, primarily in water depths greater than 3,000 feet.

Improvement in dayrates and utilization for our vessels has continued through the second quarter of 2012. Leading-edge spot market OSV dayrates in the GoM for our 240 and 265 class DP-2 equipment have been in the $30,000 to $36,000 range, which are roughly double the levels experienced in early 2011. Whether these rates can be sustained will depend, among other things, on the future pace of permitting in the GoM. Since February 2011, we have re-activated 13 new generation OSVs that were stacked in response to the drilling moratorium. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs increased about $6,700, or roughly 50%, from $13,915 for the second quarter of 2011 to $20,558 for the second quarter of 2012. During the quarter ended June 30, 2012, we had an average stacked new generation OSV fleet of 3.0 vessels compared to 10.9 vessels for the same period in 2011. As of July 31, 2012, we have only two DP-1 new generation OSVs stacked. Given the continuous improvement in market conditions, our two remaining stacked 200 class new generation OSVs are expected to be re-activated for service in the GoM during the fourth quarter of 2012, provided that we are able to re-crew such vessels and complete any required drydocking activities within that timeframe. The recent recovery in the GoM may 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. We expect that our labor costs, which comprise the highest portion of our operating costs, will increase due to this mariner shortage. To address intense competition for mariners, we increased our Upstream crew wages in April 2012 by roughly $5.0 million per quarter or $10.0 million, in the aggregate, for the last half of 2012. We expect these increased wage levels to continue into 2013 and beyond.

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Brazil. Brazil is experiencing a dramatic 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 $128 billion on exploration and production activities from 2011 through 2015 and has stated that its offshore supply vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Brazilian operators plan to add four new floating rigs by the end of 2013. Since the beginning of 2010, we have increased our presence in Brazil from zero to a high of 14 vessels. As of July 31, 2012, we have nine vessels working in Brazil under long-term contracts for Petrobras. However, one of the remaining nine vessels will mobilize back to the GoM after completing its contract with Petrobras, during the third quarter. We expect to bid on additional contracts in Brazil. However, high operating costs as well as regulatory complexity and bureaucratic inefficiency are impacting our ability to generate operating margins commensurate with those we have historically generated in the GoM. Moreover, Petrobras is the single largest consumer of our services in Brazil and, for 2011, the Company overall. 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 contract 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 growth in that market.

Mexico. The primary customer in the Mexican market is the state-owned oil company, PEMEX. The Cantarell field, which according to the EIA is PEMEX’s largest offshore oilfield, has declined from approximately 2.14 million barrels per day to 500,000 barrels per day. In 2010, 54% of Mexico’s total crude oil production came from the Cantarell field and the Ku-Maloob-Zaap field, both of which are located in the Bay of Campeche. In its July 2011 Outlook, PEMEX highlighted that 60% of its prospective resources, or 29.5 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 carry out the exploration 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 anticipate the outcome of the recent Presidential election in Mexico should result in favorable changes in the offshore exploration and production of oil and natural gas in this region. Currently, there are four floating rigs and 26 jack-up rigs drilling offshore Mexico. PEMEX has announced that there are no plans to add another floating rig for the remainder of 2012, however two more high-spec jack-up rigs will be added. 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.

15

Market conditions. As of July 31, 2012, we had 65% of our new generation OSV vessel-days contracted for the remainder of 2012, with 24 vessels contracted through at least the end of the year. Our forward OSV contract coverage for 2013 currently stands at 34%. Our MPSV contract coverage for the remainder of 2012 has also increased as a result of the improving market conditions in the GoM. On the strength of two long-term contracts awarded to our MPSVs during 2011 and recent spot market activity, MPSV utilization was 91% for the second quarter of 2012 and contract coverage for the remainder of 2012 and 2013 is currently 70% and 40%, 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 rules; 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.

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, 2012, our 48 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:

Operating Areas
Domestic
GoM	25
Other U.S. coastlines (1)	5
	30
Foreign
Brazil (2)	11
Mexico	8
Middle East	2
Other Latin America	1
	22
Total Upstream Vessels (3)	52

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

(2) During the third and fourth quarters of 2012, three of our new generation OSVs will mobilize back to the GoM upon completion of their contracts with Petrobras.

(3) Excluded from this table are three of our new generation OSVs and one conventional OSV that were stacked as of June 30, 2012. One additional new generation OSV was activated in July 2012. We expect the two remaining new generation OSVs that are stacked to be re-activated during the fourth quarter of 2012, provided that we can re-crew such vessels and complete required regulatory drydockings within that timeframe.

Our Downstream Segment

As of June 30, 2012, our Downstream fleet was comprised of nine double-hulled tank barges and 15 ocean-going tugs, six of which are older, lower-horsepower tugs that are stacked. The prolonged weakness in the overall economy, which has impacted our Downstream segment since 2008, continues to adversely impact demand for Downstream equipment. Although Downstream results for the second quarter improved from the prior year,

16

recent dayrate trends are well below the Downstream dayrates that existed from 2006 to 2008. Driven by demand from the Eagle Ford shale, we outfitted three additional vessels with vapor-recovery systems to allow them to work in the trans-Gulf crude oil trade. We feel as if these developments will have a positive impact on our Downstream vessels operating in the GoM during the second half of 2012. With the protracted weak demand for tugs and tank barges coupled with the 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.

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. generally accepted accounting principles, or 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, 2011.

17

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 is 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 new generation MPSVs as such amounts are skewed by highly variable customer-required costs-of-sales associated with ancillary equipment and services, such as ROVs and cranes. These costs-of-sales are typically recovered through higher dayrates charged to the customer. Nevertheless, 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 significant 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,
	2012			2011			2012			2011
Upstream:
New Generation Offshore Supply Vessels:
Average number of new generation OSVs (1)		51.0			51.0			51.0			51.0
Average number of active new generation OSVs (2)		48.0			40.1			47.4			38.4
Average new generation OSV fleet capacity (DWT)		128,190			128,190			128,190			128,190
Average new generation vessel capacity (DWT)		2,514			2,514			2,514			2,514
Average new generation OSV utilization rate (3)		88.1	%		67.9	%		84.6	%		63.5	%
Effective new generation OSV utilization rate (4)		93.6	%		86.3	%		91.1	%		84.4	%
Average new generation OSV dayrate (5)	$	23,335		$	20,493		$	22,896		$	20,732
Effective dayrate (6)	$	20,558		$	13,915		$	19,370		$	13,165
Downstream:
Double-hulled tank barges:
Average number of tank barges (7)		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)		74.6	%		90.6	%		80.0	%		86.5	%
Average dayrate (8)	$	16,284		$	17,333		$	16,811		$	16,880
Effective dayrate (6)	$	12,148		$	15,704		$	13,449		$	14,601

(1) We owned 51 new generation OSVs as of June 30, 2012. 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 12 new generation OSVs as of June 30, 2012. One additional new generation OSV was activated in July 2012. We plan to re-activate our remaining two stacked OSVs during the fourth quarter of 2012, provided that we are able to re-crew such vessels and complete any required drydocking activities within that timeframe. 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) Effective utilization rate is based on a denominator comprised only of vessel-days available for service by the active fleet, which excludes the impact of stacked vessel days.

(5) 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.

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

(7) 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 six older, lower-horsepower tugs, which we consider to be non-core assets and are marketed for sale. We previously owned a fleet of single-hulled tank barges; however, all of those vessels have been sold as they were also considered non-core assets.

(8) 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.

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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, 2012 and 2011, respectively (in thousands).

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Components of EBITDA:
Net income (loss)	$	12,014		$	(7,025	)	$	18,321		$	(16,061	)
Interest expense, net
Debt obligations		14,342			14,998			28,274			29,914
Interest income		(461	)		(240	)		(1,014	)		(419	)
Total interest, net		13,881			14,758			27,260			29,495
Income tax expense (benefit)		7,293			(3,839	)		11,166			(8,805	)
Depreciation		15,171			15,320			30,253			30,529
Amortization		7,107			4,773			13,024			10,165
EBITDA	$	55,466		$	23,987		$	100,024		$	45,323

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The following table reconciles EBITDA to cash flows provided by operating activities for the three and six months ended June 30, 2012 and 2011, respectively (in thousands).

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
EBITDA Reconciliation to GAAP:
EBITDA	$	55,466		$	23,987		$	100,024		$	45,323
Cash paid for deferred drydocking charges		(11,586	)		(5,178	)		(19,745	)		(10,380	)
Cash paid for interest		(3,621	)		(11,531	)		(18,377	)		(21,848	)
Cash paid for taxes		(197	)		(123	)		(729	)		(499	)
Changes in working capital		(10,118	)		(3,910	)		(12,242	)		4,502
Stock-based compensation expense		2,185			1,725			4,435			3,926
Loss on early extinguishment of debt		855			—			6,048			—
Changes in other, net		427			(580	)		433			709
Net cash flows provided by operating activities	$	33,411		$	4,390		$	59,847		$	21,733

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, 2012 and 2011, 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,
	2012		2011		2012		2011
Loss on early extinguishment of debt	$	855	$	—	$	6,048	$	—
Stock-based compensation expense		2,185		1,725		4,435		3,926
Interest income		461		240		1,014		419

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.

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Summarized financial information concerning our reportable segments for the three months ended June 30, 2012 and 2011, respectively, is shown below in the following table (in thousands, except percentage changes):

	Three Months Ended June 30						Increase (Decrease)
	2012			2011			$ Change			% Change
Revenues:
Upstream
Domestic	$	84,315		$	35,188		$	49,127			>100.0	%
Foreign		37,383			32,774			4,609			14.1
		121,698			67,962			53,736			79.1
Downstream
Domestic		7,584			10,705			(3,121	)		(29.2	)
Foreign (1)		2,363			2,150			213			9.9
		9,947			12,855			(2,908	)		(22.6	)
	$	131,645		$	80,817		$	50,828			62.9	%
Operating expenses:
Upstream	$	56,201		$	39,924		$	16,277			40.8	%
Downstream		7,255			8,490			(1,235	)		(14.5	)
	$	63,456		$	48,414		$	15,042			31.1	%
Depreciation and amortization:
Upstream	$	18,806		$	16,576		$	2,230			13.5	%
Downstream		3,472			3,517			(45	)		(1.3	)
	$	22,278		$	20,093		$	2,185			10.9	%
General and administrative expenses:
Upstream	$	11,177		$	7,611		$	3,566			46.9	%
Downstream		904			886			18			2.0
	$	12,081		$	8,497		$	3,584			42.2	%
Gain (loss) on sale of assets:
Upstream	$	(11	)	$	—		$	11			100.0	%
Downstream		—			—			—			—
	$	(11	)	$	—		$	(11	)		(100.0	)%
Operating income (loss):
Upstream	$	35,503		$	3,851		$	31,652			>100.0	%
Downstream		(1,684	)		(38	)		(1,646	)		>(100.0	)
	$	33,819		$	3,813		$	30,006			>100.0	%
Loss on early extinguishment of debt	$	855		$	—		$	855			100.0	%
Interest expense	$	14,342		$	14,998		$	(656	)		(4.4	)%
Interest income	$	461		$	240		$	221			92.1	%
Income tax expense (benefit)	$	7,293		$	(3,839	)	$	11,132			>100.0	%
Net income (loss)	$	12,014		$	(7,025	)	$	19,039			>100.0	%

(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.

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Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Revenues. Revenues for the three months ended June 30, 2012 increased by $50.8 million, or 62.9%, to $131.6 million compared to the same period in 2011 primarily due to improved Upstream market conditions. Our weighted-average active operating fleet for the three months ended June 30, 2012 was 70 vessels compared to 62 during the same period in 2011.

Revenues from our Upstream segment increased by $53.7 million, or 79.0%, to $121.7 million for the three months ended June 30, 2012 compared to $68.0 million for the same period in 2011. Our higher Upstream revenues primarily resulted from increased demand for our MPSVs, improved OSV market conditions which led to our decision to re-activate 12 new generation OSVs that were stacked since April 1, 2011, and to a lesser extent, incremental revenues earned by vessels that were in service during both periods. Our new generation OSV average dayrates were $23,335 for the second quarter of 2012 compared to $20,493 for the same period in 2011, an increase of $2,842, or 13.9%. Our new generation OSV utilization was 88.1% for the second quarter of 2012 compared to 67.9% for the same period in 2011. Our new generation OSV utilization for the second quarter of 2012 was favorably impacted by the increase in the number of our active Upstream vessels. Our vessel count included an average of 3.0 stacked vessels during the three months ended June 30, 2012 compared to an average of 10.9 stacked vessels during the prior-year period. Domestic revenues for our Upstream segment increased $49.1 million from the year-ago quarter due to improved spot market activity in the GoM. Foreign revenues for our Upstream segment increased $4.6 million, or 14.1%, primarily due to an average of two additional vessels deployed to Latin America during the three months ended June 30, 2011 compared to the year-ago quarter. Foreign revenues comprised 30.7% of our total Upstream revenues compared to 48.2% for the year-ago quarter. With three OSVs currently mobilizing from Brazil to the GoM in the third quarter of 2012, the percentage of foreign revenues that comprise our total Upstream revenues is expected to decline during the second half of 2012.

Revenues from our Downstream segment decreased by $2.9 million, or 22.6%, to $9.9 million for the three months ended June 30, 2012 compared to the year-ago quarter. This revenue decrease was largely due to 164 incremental days out-of-service for the installation of vapor-recovery systems on three of our barges and the regulatory drydocking of one barge during the three months ended June 30, 2012. Our double-hulled tank barge average dayrates were $16,284 for the three months ended June 30, 2012, a decrease of $1,049, or 6.1%, from $17,333 for the same period in 2011. Our double-hulled tank barge utilization was 74.6% for the second quarter of 2012 compared to 90.6% for the second quarter of 2011. Effective, or utilization-adjusted, dayates for our double-hulled tank barges were $12,148 for the three months ended June 30, 2012, which was $3,556, or 22.6%, lower than the prior-year quarter effective dayrates. We expect second half 2012 Downstream revenues to be higher than the first half of the year.

Operating expenses. Operating expenses for the three months ended June 30, 2012 increased by $15.0 million, or 31.1%, to $63.5 million. This increase was primarily associated with the increase of our active operating fleet compared to the year-ago quarter, higher operating costs for the additional vessels operating in international regions and higher crew wages.

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Operating expenses for our Upstream segment were $56.2 million, an increase of $16.3 million, or 40.9%, for the second quarter of 2012 compared to $39.9 million for the same period in 2011. Operating expenses for our Upstream segment were driven higher by increased operating expenses for our vessels that have been re-activated since early 2011 and, to a lesser extent, the higher cost structure for our vessels operating in Latin America and higher crew wages. The market-driven mariner wage increases in April 2012 will increase our Upstream operating expenses for the second half of 2012 approximately $9 million to $10 million higher than the first half of 2012.

Operating expenses for our Downstream segment were $7.3 million, a decrease of $1.2 million, or 14.1%, for the three months ended June 30, 2012 compared to $8.5 million for the same period in 2011. The decrease in operating expenses is largely the result of having lower cost of sales expenses due to a greater mix of Downstream vessels operating under time charter agreements instead of COAs and the incremental days out-of-service for regulatory drydockings and capital improvements noted above. Under time charter arrangements, the charterer is usually responsible for fuel costs. Under COA arrangements, the vessel owner typically bears the cost of fuel, which is typically covered through higher dayrates. Our contracts during the second quarter of 2011 were primarily comprised of COA voyages.

Depreciation and Amortization. Depreciation and amortization was $2.2 million higher for the three months ended June 30, 2012 compared to the same period in 2011. This increase is primarily due to higher shipyard costs for vessel regulatory drydockings and incremental amortization expense related to the vessels that were previously stacked and required recertification prior to being re-activated. Depreciation and amortization expense is expected to increase from current levels when the three remaining stacked vessels are recertified and activated and when any newly constructed vessels undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $12.1 million, or 9.2% of revenues, increased by $3.6 million during the three months ended June 30, 2012 compared to same period in 2011. This increase in G&A expenses was primarily attributable to higher shoreside incentive compensation and fleet recruiting and training expenses. Our general and administrative expenses are expected to be in the approximate annual range of $48 million to $52 million for the year ending December 31, 2012.

Operating Income (loss). Operating income increased by $30.0 million to $33.8 million during the three months ended June 30, 2012 compared to the same period in 2011 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 29.2% for the three months ended June 30, 2012 compared to 5.7% for the same period in 2011. Operating loss as a percentage of revenues for our Downstream segment was 16.9% for the three months ended June 30, 2012 compared to an operating loss of 0.3% for the same period in 2011.

Loss on Early Extinguishment of Debt. On April 30, 2012, the remaining $47.8 million of our 6.125% senior notes due 2014 were redeemed. During the second quarter of 2012, we recorded a loss on early extinguishment of debt of $0.9 million ($0.6 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.

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Interest Expense. Interest expense decreased $0.7 million during the three months ended June 30, 2012 compared to the same period in 2011. Higher capitalized interest from having vessels under construction or conversion was the primary reason that our interest expense decreased from the prior-year quarter. During the second quarter of 2012, we capitalized interest of $2.0 million, or roughly 12% of our total interest costs compared to not capitalizing any construction period interest for the year-ago quarter.

Interest Income. Interest income increased $0.2 million during the three months ended June 30, 2012 compared to the same period in 2011. Our average cash balance increased to $413.6 million for the three months ended June 30, 2012 compared to $141.8 million for the same period in 2011. The average interest rate earned on our invested cash balances was 0.5% during each of the three months ended June 30, 2012 and 2011. The year-over-year increase in average cash balance was primarily due to our November 2011 equity offering and our February 2012 bond refinancing, which resulted in incremental net cash proceeds of $230.1 million and $58.0 million, respectively.

Income Tax Expense. Our effective tax rate was 37.8% and 35.3% for the three months ended June 30, 2012 and 2011, respectively. The tax rate for the second quarter of 2012 is higher than the benefit rate for the second quarter of 2011 due to the effect of items not deductible for federal income tax purposes. Our income tax expense primarily consists 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 (Loss). Operating performance increased year-over-year by $19.0 million for reported net income of $12.0 million for the three months ended June 30, 2012. The higher net income for the second quarter of 2012 was primarily due to the increase in operating income based on improved market conditions discussed above and a $0.9 million pre-tax decrease in net interest expense. Net income for the second quarter of 2012 was adversely impacted by a $0.9 million pre-tax loss on early extinguishment of debt.

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Summarized financial information concerning our reportable segments for the six months ended June 30, 2012 and 2011, respectively, is shown below in the following table (in thousands, except percentage changes):

	Six Months Ended June 30						Increase (Decrease)
	2012			2011			$ Change			% Change
Revenues:
Upstream
Domestic	$	141,043		$	67,758		$	73,285			>100.0	%
Foreign		88,548			61,547			27,001			43.9
		229,591			129,305			100,286			77.6
Downstream
Domestic		17,428			20,304			(2,876	)		(14.2	)
Foreign (1)		4,599			3,475			1,124			32.3
		22,027			23,779			(1,752	)		(7.4	)
	$	251,618		$	153,084		$	98,534			64.4	%
Operating expenses:
Upstream	$	108,328		$	74,138		$	34,190			46.1	%
Downstream		14,337			15,898			(1,561	)		(9.8	)
	$	122,665		$	90,036		$	32,629			36.2	%
Depreciation and amortization:
Upstream	$	36,003		$	33,771		$	2,232			6.6	%
Downstream		7,274			6,923			351			5.1
	$	43,277		$	40,694		$	2,583			6.3	%
General and administrative expenses:
Upstream	$	21,435		$	16,627		$	4,808			28.9	%
Downstream		1,772			1,734			38			2.2
	$	23,207		$	18,361		$	4,846			26.4	%
Gain (loss) on sale of assets:
Upstream	$	(3	)	$	—		$	3			100.0	%
Downstream		—			559			(559	)		(100.0	)
	$	(3	)	$	559		$	(562	)		>100.0	%
Operating income (loss):
Upstream	$	63,822		$	4,769		$	59,053			>100.0	%
Downstream		(1,356	)		(217	)		(1,139	)		>(100.0	)
	$	62,466		$	4,552		$	57,914			>100.0	%
Loss on early extinguishment of debt	$	6,048		$	—		$	6,048			100.0	%
Interest expense	$	28,274		$	29,914		$	(1,640	)		(5.5	)%
Interest income	$	1,014		$	419		$	595			>100.0	%
Income tax expense (benefit)	$	11,166		$	(8,805	)	$	19,971			>100.0	%
Net income (loss)	$	18,321		$	(16,061	)	$	34,382			>100.0	%

(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.

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Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Revenues. Revenues for the six months ended June 30, 2012 increased by $98.5 million, or 64.4%, to $251.6 million compared to the same period in 2011 primarily due to improved Upstream market conditions. Our weighted-average active operating fleet for the six months ended June 30, 2012 was 69 vessels compared to 60 during the same period in 2011, entirely due to the reactivation of previously stacked vessels.

Revenues from our Upstream segment increased by $100.3 million, or 77.6%, to $229.6 million for the six months ended June 30, 2012 compared to $129.3 million for the same period in 2011. Our higher Upstream revenues primarily resulted from increased demand for our MPSVs, improved OSV market conditions which led to our decision to re-activate 12 new generation OSVs since April 1, 2011 that had been stacked, and to a lesser extent, incremental revenues earned by vessels that were operating in our fleet during both the six months ended June 30, 2012 and 2011, respectively. Our new generation OSV average dayrates were $22,896 for the first six months of 2012 compared to $20,732 for the same period in 2011, an increase of $2,164, or 10.4%. Our new generation OSV utilization was 84.6% for the first six months of 2012 compared to 63.5% for the same period in 2011. Our new generation OSV utilization for the first half of 2012 was favorably impacted by the re-activation of OSVs that had been stacked. Our vessel count included an average of 3.6 stacked vessels during the six months ended June 30, 2012 compared to an average of 12.6 stacked vessels during the prior-year period. Domestic revenues for our Upstream segment increased $73.3 million during the six months ended June 30, 2012 due to improved spot market activity in the GoM. Foreign revenues for our Upstream segment increased $27.0 million, or 43.9%, primarily due to additional vessels deployed to Latin America since April 1, 2011. Foreign revenues comprised 38.5% of our total Upstream revenues compared to 47.6% for the year-ago period. With three OSVs currently mobilizing from Brazil to the GoM in the third quarter of 2012, the percentage of foreign revenues that comprise our total Upstream revenues is expected to decline during the second half of 2012.

Revenues from our Downstream segment decreased by $1.8 million, or 7.4%, to $22.0 million for the six months ended June 30, 2012 compared to the year-ago period. This revenue decrease was largely due to incremental days out-of-service for the installation of vapor-recovery systems on three of our barges and the regulatory drydocking of one barge during the first half of 2012 compared to the same period in 2011. Our double-hulled tank barge average dayrates were $16,811 for the six months ended June 30, 2012, which was in-line with dayrates for the first half of 2011. Our double-hulled tank barge utilization was 80.0% for the first six months of 2012 compared to 86.5% for the first six months of 2011. We expect second half 2012 Downstream revenues to be higher than the first half of the year.

Operating expenses. Operating expenses for the six months ended June 30, 2012 increased by $32.6 million, or 36.2%, to $122.7 million. This increase was primarily associated with the increase of our active operating fleet compared to the year-ago period, higher operating costs for vessels operating in Latin America and higher crew wages.

Operating expenses for our Upstream segment were $108.3 million, an increase of $34.2 million, or 46.2%, for the first half of 2012 compared to $74.1 million for the same period in 2011. Operating expenses for our Upstream segment were driven higher by increased operating expenses for our vessels that have been re-activated since early 2011 and, to a lesser extent, higher costs for our vessels operating in Latin America and higher crew wages.

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The market-driven mariner wage increases in April 2012 will increase our Upstream operating expenses for the second half of 2012 approximately $9 million to $10 million higher than the first half of 2012.

Operating expenses for our Downstream segment were $14.3 million, a decrease of $1.6 million, or 10.1%, for the six months ended June 30, 2012 compared to $15.9 million for the same period in 2011. The decrease in operating expenses is largely the result of having lower cost of sales expenses due to a greater mix of Downstream vessels operating under time charter agreements instead of COAs and the incremental days out-of-service for regulatory drydockings and capital improvements noted above. Under time charter arrangements, the charterer is usually responsible for fuel costs. Under COA arrangements, the vessel owner typically bears the cost of fuel, which is typically covered through higher dayrates. Our contracts during the first half of 2011 were primarily comprised of COA voyages.

Depreciation and Amortization. Depreciation and amortization was $2.6 million higher for the six months ended June 30, 2012 compared to the same period in 2011. This increase is primarily due to higher shipyard costs for vessel regulatory drydockings and incremental amortization expense related to the vessels that were previously stacked and required recertification prior to being re-activated. Depreciation and amortization expense is expected to increase from current levels when the remaining stacked vessels are recertified and activated and when any newly constructed vessels undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $23.2 million, or 9.2% of revenues, increased by $4.8 million during the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This increase in G&A expense was primarily attributable to higher shoreside incentive compensation and fleet recruiting and training expenses. Our general and administrative expenses are expected to be in the approximate annual range of $48 million to $52 million for the year ending December 31, 2012.

Gain on Sale of Assets. During the first six months of 2011, we sold four single-hulled tank barges for net cash proceeds of $2.1 million, which resulted in aggregate gains of approximately $0.6 million ($0.4 million after-tax or $0.01 per diluted share). No vessels were sold during the first half of 2012.

Operating Income. Operating income increased by $57.9 million to $62.4 million during the six months ended June 30, 2012 compared to the same period in 2011 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 27.8% for the six months ended June 30, 2012 compared to 3.7% for the same period in 2011. Operating loss as a percentage of revenues for our Downstream segment was 6.4% for the six months ended June 30, 2012 compared to an operating loss of 0.8% for the same period in 2011.

Loss on Early Extinguishment of Debt. On March 2, 2012, we commenced a cash tender offer for all of the $300.0 million in aggregate principal amount of our 6.125% senior notes due 2014. Senior notes totaling approximately $252.2 million, or 84% of such notes outstanding, were validly tendered during the designated tender period, which ended on March 29, 2012. The remaining $47.8 million of our 6.125% senior notes were redeemed on April 30, 2012. During the first half of 2012, we recorded a loss on early extinguishment of

27

debt of approximately $6.0 million ($3.7 million or $0.11 per diluted share after-tax), which was comprised of the tender offer costs, the write-off of unamortized financing costs and original issue discount, and a bond redemption premium.

Interest Expense. Interest expense decreased $1.6 million during the six months ended June 30, 2012 compared to the same period in 2011. Higher capitalized interest from having vessels under construction or conversion was the primary reason that our interest expense decreased from the prior-year period. During the first half of 2012, we capitalized interest of $3.5 million, or roughly 11% of our total interest costs compared to not capitalizing any construction period interest for the year-ago period.

Interest Income. Interest income increased $0.6 million during the six months ended June 30, 2012 compared to the same period in 2011. Our average cash balance increased to $393.2 million for the six months ended June 30, 2012 compared to $140.4 million for the same period in 2011. The average interest rate earned on our invested cash balances was 0.5% during each of the six months ended June 30, 2012 and 2011. The year-over-year increase in average cash balance was primarily due to our November 2011 equity offering and our February 2012 bond refinancing, which resulted in incremental net cash proceeds of $230.1 million and $58.0 million, respectively.

Income Tax Expense. Our effective tax rate was 37.9% and 35.4% for the six months ended June 30, 2012 and 2011, respectively. The tax rate for the first six months of 2012 is higher than the benefit rate for the first six months of 2011 due to the effect of items not deductible for federal income tax purposes. Our income tax expense primarily consists 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 (Loss). Operating performance increased year-over-year by $34.4 million for reported net income of $18.3 million for the six months ended June 30, 2012. The higher net income for the first half of 2012 was primarily due to the increase in operating income based on improved market conditions discussed above and a $2.2 million pre-tax decrease in net interest expense. Net income for the first half of 2012 was adversely impacted by a $6.0 million pre-tax loss on early extinguishment of debt.

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 fifth OSV newbuild 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 2012. We will be required to conduct any deferred drydockings prior to such vessels returning to service, which is expected for our two remaining stacked new generation OSVs during the fourth quarter of 2012.

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

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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 recently amended revolving credit facility will be more than sufficient to operate the Company and meet all of our near-term obligations, including milestone construction payments required under our fifth OSV newbuild program.

As of June 30, 2012, we had total cash and cash equivalents of $391.6 million. We also have a $300 million revolving credit facility, expandable up to $500 million, which is undrawn as of July 31, 2012. Excluding any cash requirements for potential new growth opportunities that may arise, our current cash on-hand and our internal cash projections indicate that our $300 million revolving credit facility will remain undrawn for the foreseeable future. As of June 30, 2012, we had posted letters of credit for $1.3 million and had $298.7 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 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 further 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 August 2017, however, we anticipate the early redemption of convertible notes in November 2013. Our currently undrawn revolving credit facility matures in November 2016, provided that we meet certain liquidity conditions required by such facility. See further discussion of these refinancing conditions in the Contractual Obligations section below.

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 to meet our obligations under our fifth OSV newbuild program and we expect to refinance senior debt as market conditions warrant. To the extent we do not refinance such debt, we currently expect to generate sufficient cash to re-pay our long-term debt upon maturity. 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.

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 $59.8 million for the six months ended June 30, 2012 and $21.7 million for the same period in 2011.

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Operating cash flows for the first six months of 2012 were favorably affected by an increase in our weighted-average operating fleet and improved market conditions in our Upstream segment.

Investing Activities. Net cash used in investing activities was $90.9 million for the six months ended June 30, 2012 and $10.8 million for the same period in 2011. Cash utilized during the first six months of 2012 primarily consisted of construction costs incurred for our fifth OSV newbuild program and capital improvements made to our operating fleet. Cash utilized during the first six months of 2011 primarily consisted of capital improvements made to our operating fleet, which were partially offset by approximately $2.1 million in aggregate net cash proceeds from the sale of four single-hulled tank barges.

Financing Activities. Net cash provided by financing activities was $65.9 million for the six months ended June 30, 2012 compared to cash used in financing activities of $1.3 million for the same period in 2011. 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. These cash inflows were partially offset by the repurchase and retirement or redemption of our 6.125% senior notes due 2014. Net cash provided by financing activities for the six months ended June 30, 2011 was comprised of deferred financing costs and net proceeds from common shares issued pursuant to our employee stock-based compensation plans.

On March 2, 2012, we commenced a tender offer and solicitation of consents relating to the repurchase of our existing 6.125% senior notes. The tender offer expired on March 29, 2012. On March 2, 2012, we also completed the private placement of 5.875% senior notes, resulting in offering proceeds of approximately $367.4 million, net of estimated transaction costs. In connection with the tender offer and related consent solicitation, we used $259.9 million of such proceeds to repurchase approximately 84% of our outstanding $300 million aggregate principal amount of 6.125% senior notes. The $47.8 million of remaining 6.125% senior notes were redeemed on April 30, 2012. 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 6.125% senior notes during the first half of 2012, we recorded a pre-tax loss on early extinguishment of debt of approximately $6.0 million ($3.7 million after-tax or $0.11 per diluted share).

Contractual Obligations

Debt

As of June 30, 2012, we had total debt of $852.4 million, net of original issue discount of $22.6 million. Our debt is comprised of $244.8 million of our 8.000% senior notes due 2017, or 2017 senior notes, $375.0 million of our 5.875% senior notes due 2020, or 2020 senior notes, and $232.6 million of our 1.625% convertible senior notes due 2026, or convertible senior notes. We also have a revolving credit facility with a borrowing base of $300.0 million, which includes an accordion feature that allows for the potential expansion of the facility up to an aggregate of $500.0 million. For further information on our debt agreements, see Note 3 to our consolidated financial statements included herein. As of June 30, 2012, we were in compliance with all of our debt covenants.

Under our revolving credit facility, we have 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

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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 our 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.

The credit agreement governing our revolving credit facility and the indentures governing our 2017 senior notes and our 2020 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 quarterly compliance reporting period ended June 30, 2012, 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. In addition, we are permitted to use our revolving credit facility to repay our 1.625% convertible notes, provided that, as of the date of repayment, we have available liquidity of $100 million on a pro forma basis and can demonstrate to the agent under the facility that our business plan is fully funded for the next four fiscal quarters. We continuously review our debt covenants and report our compliance with financial ratios to our lenders 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, 2012 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, 2012		Six Months Ended June 30, 2012		Incurred Since Inception		Estimated Program Totals (1)		Projected Delivery Dates (1)
Growth Capital Expenditures:
OSV newbuild program #5 (2)	$	41.0	$	78.0	$	120.4	$	720.0		2Q2013-4Q2014

(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 limitations, 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 represents estimated cash outlays and does 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 two domestic shipyards to build four 300 class OSVs, four 310 class OSVs, and eight 320 class OSVs. Delivery of the first 16 vessels to be constructed under this program is expected to occur on various dates during 2013 and 2014. We expect to own and operate 56 and 67 new generation OSVs as of December 31, 2013 and 2014, respectively. These vessel additions result in a projected average new generation OSV fleet complement of 52.2 and 62.8 vessels for the fiscal years 2013 and 2014, respectively.

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The following table summarizes the costs incurred, prior to the allocation of construction period interest, for maintenance capital expenditures for the three and six months ended June 30, 2012 and 2011, and a forecast for fiscal 2012 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,
	2012		2011		2012		2011		2012
Maintenance and Other Capital Expenditures:		Actual		Actual		Actual		Actual		Forecast
Maintenance Capital Expenditures
Deferred drydocking charges (1)	$	11.5	$	5.2	$	19.7	$	10.4	$	46.7
Other vessel capital improvements (2)		2.1		2.4		7.3		6.4		11.5
		13.6		7.6		27.0		16.8		58.2
Other Capital Expenditures
Commercial-related vessel improvements (3)		1.8		2.2		2.4		5.8		6.2
Miscellaneous non-vessel additions (4)		0.5		0.3		1.0		0.7		3.2
		2.3		2.5		3.4		6.5		9.4
Total	$	15.9	$	10.1	$	30.4	$	23.3	$	67.6

(1) Deferred drydocking charges for the full-year 2012 include the actual and projected recertification costs for 25 OSVs, two MPSV, three tank barges and four 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) Commercial-related vessel improvements include items, such as cranes, ROVs and other specialized vessel equipment, which costs are typically included in and offset by higher dayrates charged to customers.

(4) Non-vessel capital expenditures are primarily related to information technology and shore-side 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,” or “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 on-time and on-budget, which involves the construction and integration of highly complex vessels and systems; 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

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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; 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; 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; declines in oil and natural gas prices; further increases in operating costs, such as the recent 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 activity in the GoM and other markets; the level of fleet additions by the Company and its competitors that could result in over capacity in markets in which the Company competes; economic and political risks; weather-related risks; the shortage of or 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, including any 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 or pollution incidents 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 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, 2011.

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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, 2012 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, 2011.

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

None.

Item 3—Defaults Upon Senior Securities

None.

Item 4—Mine Safety Dosclosures

None.

Item 5—Other Information

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Glossary of Terms

“AHTS” means anchor-handling towing supply;

“average dayrate” means 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 brokerage arrangements, this calculation excludes that portion of revenue that is equal to the cost of in-chartering third-party equipment paid by customers;

“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;

“CPP” means clean petroleum products;

“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 Gulfmark Offshore, Inc. (NYSE:GLF), SEACOR Holdings Inc. (NYSE:CKH) 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;

“DPP” means dirty petroleum products;

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“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;

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

“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 law known as the Merchant Marine Act of 1920, as amended;

“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;

“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;

“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.;

“ROV” means a remotely operated vehicle;

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“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
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	—	Certificate of Designation of Series A Junior Participating Preferred Stock filed with the Secretary of State of the State of Delaware on June 20, 2003 (incorporated by reference to Exhibit 3.6 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).
3.3	—	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).
3.4	—	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).
4.1	—	Specimen stock certificate for the Company’s common stock, $0.01 par value (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form 8-A dated March 25, 2004, Registration No. 001-32108).
4.2	—	Rights Agreement dated as of June 18, 2003 between the Company and Mellon Investor Services LLC as Rights Agent, which includes as Exhibit A the Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Right Certificate and as Exhibit C the form of Summary of Rights to Purchase Stock (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 3, 2003).
4.3	—	Amendment to Rights Agreement dated as of March 5, 2004 between the Company and Mellon Investor Services LLC as Rights Agent (incorporated by reference to Exhibit 4.13 to the Company’s Form 10-K for the period ended December 31, 2003).
4.4	—	Second Amendment to Rights Agreement dated as of September 3, 2004 by and between the Company and Mellon Investor Services, LLC as Rights Agent (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-A/A filed September 3, 2004, Registration No. 001-32108).
4.5	—	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).

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Exhibit Number		Description of Exhibit
4.6	—	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).
4.7	—	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).
4.8	—	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).
4.9	—	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).
4.10	—	Specimen 8% Series B Senior Note due 2017 (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-4 dated September 29, 2009, Registration No. 333-162197).
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 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed March 21, 2012).
4.12	—	Form of 5.875% Senior Notes due 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed March 21, 2012).
4.13	—	Registration Rights Agreement, dated as of March 16, 2012, among, Hornbeck Offshore Services, Inc., the guarantors party thereto and J.P. Morgan Securities LLC, as representative of the Initial Purchasers (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed March 21, 2012).
4.14	—	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).
4.15	—	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).

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Exhibit Number		Description of Exhibit
*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.

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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.

	Hornbeck Offshore Services, Inc.
Date: August 6, 2012	/S/    JAMES O. HARP, JR.
	James O. Harp, Jr.
	Executive Vice President and Chief Financial Officer

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