Edgar Filing: HORNBECK OFFSHORE SERVICES INC /LA

Hornbeck Offshore Services, Inc.

Date: November 9, 2012

/S/ JAMES O. HARP, JR.

James O. Harp, Jr.

Executive Vice President and Chief Financial Officer

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

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 October 31, 2012 was 35,408,222.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 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			17
Item 3—Quantitative and Qualitative Disclosures About Market Risk			38
Item 4—Controls and Procedures			40

PART II—OTHER INFORMATION			40
Item 1—Legal Proceedings			40
Item 1A—Risk Factors			40
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 3—Defaults Upon Senior Securities			40
Item 4—Mine Safety Disclosures			40
Item 5—Other Information			40
Item 6—Exhibits			43

SIGNATURE			48

PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	September 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	633,614		$	356,849
Accounts receivable, net of allowance for doubtful accounts of $2,910 and $1,253, respectively		95,316			85,629
Deferred tax assets, net		28,378			3,221
Other current assets		22,351			22,866

Total current assets		779,659			468,565

Property, plant and equipment, net		1,729,484			1,605,785
Deferred charges, net		73,659			47,781
Other assets		13,508			14,215

Total assets	$	2,596,310		$	2,136,346

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	53,119		$	36,708
Accrued interest		16,106			8,955
Accrued payroll and benefits		13,579			12,781
Deferred revenue		4,286			1,774
Other accrued liabilities		9,683			7,131

Total current liabilities		96,773			67,349
Long-term debt, net of original issue discount of $91,893 and $29,352, respectively		1,083,107			770,648
Deferred tax liabilities, net		263,899			223,678
Other liabilities		1,536			1,683

Total liabilities		1,445,315			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; 35,394 and 35,013 shares issued and outstanding, respectively		354			350
Additional paid-in-capital		702,081			649,644
Retained earnings		448,795			423,073
Accumulated other comprehensive loss		(235	)		(79	)

Total stockholders’ equity		1,150,995			1,072,988

Total liabilities and stockholders’ equity	$	2,596,310		$	2,136,346

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(Unaudited)						(Unaudited)
Revenues	$	127,939		$	105,827		$	379,557		$	258,911
Costs and expenses:
Operating expenses		67,159			62,744			189,824			152,780
Depreciation		15,124			15,230			45,377			45,759
Amortization		6,688			5,155			19,712			15,320
General and administrative expenses		12,943			9,045			36,150			27,406

		101,914			92,174			291,063			241,265

Gain on sale of assets		267			976			264			1,535

Operating income		26,292			14,629			88,758			19,181
Other income (expense):
Loss on early extinguishment of debt		—			—			(6,048	)		—
Interest income		524			156			1,538			575
Interest expense		(14,697	)		(15,062	)		(42,971	)		(44,976	)
Other income (expense), net		(5	)		(19	)		324			58

		(14,178	)		(14,925	)		(47,157	)		(44,343	)

Income (loss) before income taxes		12,114			(296	)		41,601			(25,162	)
Income tax expense (benefit)		4,713			445			15,879			(8,360	)

Net income (loss)	$	7,401		$	(741	)	$	25,722		$	(16,802	)

Basic earnings (loss) per common share	$	0.21		$	(0.03	)	$	0.73		$	(0.63	)

Diluted earnings (loss) per common share	$	0.20		$	(0.03	)	$	0.71		$	(0.63	)

Weighted average basic shares outstanding		35,384			26,919			35,276			26,839

Weighted average diluted shares outstanding		36,130			26,919			36,063			26,839

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(Unaudited)						(Unaudited)
Net income (loss)	$	7,401		$	(741	)	$	25,722		$	(16,802	)
Other comprehensive income, net of tax:
Foreign currency translation gain loss		(59	)		(309	)		(156	)		(305	)

Total comprehensive income (loss)		7,342			(1,050	)		25,566			(17,107	)

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

HORNBECK OFFSHORE SERVICES, INC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Nine Months Ended September 30,
	2012			2011
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	25,722		$	(16,802	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		45,377			45,759
Amortization		19,712			15,320
Stock-based compensation expense		8,164			5,654
Loss on early extinguishment of debt		6,048			—
Provision for bad debts		1,657			1,504
Deferred tax expense (benefit)		15,519			(7,597	)
Amortization of deferred financing costs		13,348			11,803
Gain on sale of assets		(264	)		(1,535	)
Changes in operating assets and liabilities:
Accounts receivable		(10,765	)		(19,663	)
Other receivables and current assets		472			(3,530	)
Deferred drydocking charges		(32,445	)		(16,478	)
Accounts payable		8,853			6,007
Accrued liabilities and other liabilities		1,318			(1,636	)
Accrued interest		7,151			292

Net cash provided by operating activities		109,867			19,098
CASH FLOWS FROM INVESTING ACTIVITIES:
Costs incurred for OSV newbuild program #5		(151,011	)		—
Net proceeds from sale of assets		4,322			11,335
Vessel capital expenditures		(16,072	)		(22,586	)
Non-vessel capital expenditures		(2,601	)		(1,382	)

Net cash used in investing activities		(165,362	)		(12,633	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Tax shortfall from share-based payments		(45	)		(1,922	)
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	)		—
Purchase of hedge on convertible senior notes		(73,032	)		—
Sale of common stock warrants		48,237			—
Proceeds from the issuance of convertible senior notes		300,000			—
Deferred financing costs		(16,451	)		(490	)
Net cash proceeds from other shares issued		2,579			1,205

Net cash provided by (used in) financing activities		332,416			(1,207	)

Effects of exchange rate changes on cash		(156	)		(305	)

Net increase in cash and cash equivalents		276,765			4,953
Cash and cash equivalents at beginning of period		356,849			126,966

Cash and cash equivalents at end of period	$	633,614		$	131,919

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES:
Cash paid for interest	$	28,755		$	32,481

Cash paid for income taxes	$	964		$	833

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

The accompanying unaudited consolidated financial statements do not include certain information and footnote disclosures required by United States generally accepted accounting principles, or GAAP. The interim financial statements and notes are presented as permitted by instructions to the Quarterly Report on Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, all adjustments necessary for a fair presentation of the interim financial statements have been included and consist only of normal recurring items. The unaudited quarterly financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Annual Report on Form 10-K of Hornbeck Offshore Services, Inc. (together with its subsidiaries, the “Company”) for the year ended December 31, 2011. The results of operations for the three months ended September 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 September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Net income (loss)	$	7,401	$	(741	)	$	25,722	$	(16,802	)

Weighted average number of shares of common stock outstanding		35,384		26,919			35,276		26,839
Add: Net effect of dilutive stock options and unvested restricted stock (1)(2)(3)		746		—			787		—

Adjusted weighted average number of shares of common stock outstanding		36,130		26,919			36,063		26,839

Earnings (loss) per common share:
Basic	$	0.21	$	(0.03	)	$	0.73	$	(0.63	)

Diluted	$	0.20	$	(0.03	)	$	0.71	$	(0.63	)

(1)

For the three and nine months ended September 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 1,209 and 1,201 shares of common stock for the three and nine months ended September 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.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(2)

As of September 30, 2012 and 2011 and for the periods then ended, the 2019 convertible senior notes and 2026 convertible senior notes were not dilutive, as the average price of the Company’s stock was less than the effective conversion price of such notes, which is $68.53 and $62.59 per share, respectively.

(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):


	September 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 $4,977 and $5,571		245,023		244,429
5.875% senior notes due 2020		375,000		—
1.500% convertible senior notes due 2019, net of original issue discount of $72,621		227,379		—
1.625% convertible senior notes due 2026, net of original issue discount of $14,295 and $23,566 (1)		235,705		226,434
Revolving credit facility due 2016		—		—

		1,083,107		770,648
Less current maturities		—		—

	$	1,083,107	$	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 2026 convertible senior notes, have semi-annual cash interest payments of $2.0 million due May 15 and November 15, declining to 1.375%, or $1.7 million semi-annually, beginning on November 15, 2013. Subject to certain conversion and redemption features of the 2026 convertible senior notes, holders of such notes may require the Company to purchase all or a portion of their notes on each of November 15, 2013, November 15, 2016 and November 15, 2021. The Company will also be entitled to redeem all or a portion of the 2026 convertible senior notes at par on or after November 15, 2013 and it intends to do so.

On March 2, 2012, the Company commenced a cash tender offer for all of the outstanding $300.0 million aggregate principal amount of its 2014 senior notes. Senior notes totaling approximately $252.2 million, or approximately 84% of the 2014 senior 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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

$5.2 million was recorded during the first quarter of 2012 and includes the tender offer costs, an allocable portion of the write-off of unamortized financing costs and original issue discount, and a bond redemption premium. A loss on early extinguishment of debt of $0.9 million was recorded during the second quarter of 2012 for those costs allocable to the remaining 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%, or $11.0 million semi-annually, on April 1 and October 1 of each year until maturity. The effective interest rate on the 2020 senior notes is 6.08%. No principal payments are due until maturity. Pursuant to a registered exchange offer, the 2020 senior notes issued in March 2012 that were initially sold pursuant to private placements were exchanged by the holders for 2020 senior notes with substantially the same terms, except that the issuance of the 2020 senior notes in the exchange offer was registered under the Securities Act of 1933, as amended, or the Securities Act. The original 2020 senior notes and the similar notes exchanged were issued under and are entitled to the benefits of the same 2012 indenture.

The Company may, at its option, redeem all or part of the 2017 senior notes or the 2020 senior notes from time to time at specified redemption prices and subject to certain conditions required by the indentures governing such senior notes. The Company is permitted under the terms of these indentures to incur additional indebtedness in the future, provided that certain financial conditions set forth in the indentures are satisfied by the Company.

On August 13, 2012, the Company issued $300.0 million of convertible senior notes due 2019, or the 2019 convertible senior notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The 2019 convertible senior notes bear interest at a fixed rate of 1.500% per annum, or $2.3 million semi-annually, accruing from August 13, 2012, and payable semi-annually on March 1 and September 1 of each year, with the first interest payment on March 1, 2013. The 2019 convertible senior notes mature on September 1, 2019.

Because the 2019 convertible senior notes are considered to be cash convertible debt, the Company has separately accounted for the liability and equity components of the 2019 convertible senior notes by allocating the $300.0 million in proceeds from the issuance between the liability component and the embedded conversion option, or the equity component. The allocation was conducted by estimating an interest rate at the time of issuance of the 2019 convertible senior notes for similar debt instruments that do not include the embedded conversion feature. A non-convertible interest rate of 5.75% was used to compute the initial fair value of the liability component of $226.7 million. For purposes of the fair value measurement, the Company determined that the valuation of the 2019 convertible

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

senior notes falls under Level 2 of the fair value hierarchy. The excess of the $300.0 million of proceeds from the issuance of the 2019 convertible senior notes over the $226.7 million initial amount allocated to the liability component, or $73.3 million, was allocated to the embedded conversion option, or equity component. This excess was treated as a debt discount and is being amortized through interest expense, using the effective interest method, over the seven-year term of the 2019 convertible senior notes, which runs through September 1, 2019. The effective interest rate for these notes is 6.23%.

The initial conversion rate of the 2019 convertible senior notes is 18.5718 shares per $1,000 principal amount of notes, which corresponds to a conversion price of approximately $53.85 per share. The conversion rate was based on the last reported sale price of the Company’s common shares on The New York Stock Exchange of $39.16 on August 7, 2012. The conversion rate will be subject to adjustment in some events but will not be adjusted for accrued interest. In addition, following certain corporate transactions that constitute “fundamental changes” (as defined in the indenture for the 2019 convertible senior notes), the conversion rate will be increased for holders who elect to convert notes in connection with such corporate transactions in certain circumstances.

The 2019 convertible senior notes are convertible based on the applicable conversion rate only under the following circumstances:

•

prior to June 1, 2019, during any fiscal quarter (and only during that fiscal quarter) commencing after December 31, 2012, if the last reported sale price of the Company’s common stock is greater than or equal to 135% of the conversion price for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter; or

•

prior to June 1, 2019, during the five business-day period after any 10 consecutive trading-day period (the “measurement period”) in which the trading price per $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of the Company’s common stock and the conversion rate on such trading day; or

•

upon the occurrence of specified corporate transactions, as defined in the indenture governing the 2019 convertible senior notes; or

•

beginning on June 1, 2019 until the close of business on the second scheduled trading day preceding the maturity date.

Upon conversion, the Company will satisfy its conversion obligation by paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at the Company’s election.

If the holders of the 2019 convertible senior notes exercise the conversion provisions of the 2019 convertible senior notes and the Company elects to settle such conversions partially in cash (which it presently intends to do at least up to the principal amount of the notes), the Company will need to remit such cash amount to the converting holders. For that reason, in any period during which the 2019 convertible senior notes are convertible as provided above,

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the Company would classify the entire principal amount of the outstanding 2019 convertible senior notes as a current liability in the respective quarter. This evaluation of the classification of amounts outstanding associated with the 2019 convertible senior notes will occur every calendar quarter.

The 2019 convertible senior notes are not redeemable at the option of the Company prior to their maturity. No sinking fund is provided for the 2019 convertible senior notes and the 2019 convertible senior notes are not subject to legal defeasance.

If the Company experiences specified types of corporate transactions, including certain change of control events or a de-listing of the Company’s common stock, holders of the 2019 convertible senior notes may require the Company to purchase all or a portion of their 2019 convertible senior notes. Any repurchase of the convertible senior notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date.

In connection with the sale of the 2019 convertible senior notes, the Company entered into convertible senior note hedge transactions with respect to its common stock with affiliates of the initial purchasers of the notes, Barclays, Inc., JP Morgan Chase and Wells Fargo Bank, or the counterparties. Each of the 2019 convertible senior note hedge transactions is a privately-negotiated transaction that is economically equivalent to the purchase of call options on the Company’s common stock with strike prices equal to the conversion price of the 2019 convertible senior notes, and is intended to mitigate dilution to the Company’s stockholders and/or offset cash payment due upon the potential future conversion of the 2019 convertible senior notes. Under the 2019 convertible senior note hedge transactions, subject to customary anti-dilution provisions, the counterparties are required to deliver to the Company the approximate number of shares of the Company’s common stock and/or an amount of cash that the Company is obligated to deliver to the holders of the 2019 convertible senior notes assuming the conversion of such notes.

The Company also entered into separate privately-negotiated warrant transactions, whereby the Company sold to each of the counterparties call options to acquire approximately the same number of shares of its common stock underlying the convertible senior note hedge transactions, subject to customary anti-dilution adjustments, at a strike price of $68.53 per share of common stock, which represented a 75.0% premium over the closing price of the Company’s shares of common stock on August 7, 2012. Upon the exercise of the warrants, if the market price of the common stock exceeds the strike price of the warrants on any day within the valuation period, the Company will be required to deliver the corresponding value to the counterparties, at its option in cash or shares of its common stock. The 2019 convertible senior note hedge and warrant transactions are separate and legally distinct instruments that bind the Company and the counterparties and have no binding effect on the holders of the 2019 convertible senior notes.

For income tax reporting purposes, the Company has elected to integrate the 2019 convertible senior notes and the note hedge transactions. Integration of the 2019 convertible senior note hedge with the 2019 convertible senior notes creates an in-substance original

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

issue debt discount for income tax reporting purposes and, therefore, the cost of the 2019 convertible senior note hedge is accounted for as interest expense over the term of the 2019 convertible senior notes for income tax reporting purposes. The associated income tax deductions will be recognized in the period that the deduction is taken for income tax reporting purposes. The Company has also treated the proceeds from the sale of warrants as a non-taxable increase in additional paid-in capital in stockholders’ equity.

The Company used a portion of the $290.8 million in net proceeds of the 2019 convertible senior notes offering, along with a portion of the $48.2 million in proceeds from the sale of warrants, to fund the $73.0 million cost of convertible senior note hedge transactions. The Company intends to use the remaining net proceeds of approximately $266.0 million from the sale of the 2019 convertible senior notes and the sale of the warrants, along with other available sources of cash, to retire its 2026 convertible senior notes, which are first subject to repurchase by the Company at the option of holders of such 2026 convertible senior notes, on November 15, 2013, and subject to redemption at the Company’s option on or after November 15, 2013, in each case at par plus accrued and unpaid interest, or for general corporate purposes, which may include retirement of other debt or funding for the acquisition, construction or retrofit of vessels.

The Company incurred $9.1 million of fees and other costs related to the issuance of the 2019 convertible senior notes. These fees and other origination costs have been allocated to the liability and equity components of the 2019 convertible senior notes in proportion to their allocated values. Approximately $2.2 million of these fees and other origination costs were recorded as a reduction in additional paid-in capital. The remaining $6.9 million of fees and other costs are being amortized as interest expense over the seven-year term of the 2019 convertible senior notes, which runs through September 1, 2019.

The 2019 convertible senior notes and 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 2019 convertible senior notes and 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 2019 convertible senior notes and the 2020 senior notes are general unsecured, senior obligations of the Company, ranking equally in right of payment with all of its existing and future senior indebtedness, including its outstanding 2017 senior notes and its 2026 senior convertible notes.

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

As of September 30, 2012, there were no amounts drawn under the Company’s $300.0 million revolving credit facility and $0.9 million posted as letters of credit. As of September 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 2017 senior notes, 2020 senior notes, 2019 convertible senior notes and 2026 convertible senior notes by primarily using quoted market prices. The fair value of the Company’s revolving credit facility, when there are outstanding balances, approximates its carrying value. The face value, carrying value and fair value of the Company’s total debt was $1,175.0 million, $1,083.1 million and $1,209.1 million, respectively, as of September 30, 2012. Given the observable nature 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 nine months ended September 30, 2012, the Company capitalized approximately $2.9 million and $6.4 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 nine months ended September 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 shoreside 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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

depending on the Company’s performance. During the nine months ended September 30, 2012, the Company granted 237,368 time-based restricted stock and performance-based restricted stock and 137,358 cash-settled phantom restricted stock units. The cash-settled phantom restricted stock units are re-measured quarterly and classified as a liability, due to the settlement of these awards in cash.

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, and is determined based on the market price of the Company’s stock on the date of grant applied to the total shares that are expected to fully vest. 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 nine months ended September 30, 2012, the Company issued 381,284 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 financial impact of the stock-based compensation expense related to the Company’s incentive compensation plan on its operating results are reflected in the table below (in thousands, except for per share data):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Income before taxes	$	3,729	$	1,728	$	8,164	$	5,654

Net income	$	2,278	$	280	$	5,045	$	3,777

Earnings per common share:
Basic	$	0.06	$	0.01	$	0.14	$	0.14

Diluted	$	0.06	$	0.01	$	0.14	$	0.14

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 nine months ended September 30, 2012. No such stock-based compensation expense was capitalized during the three and nine months ended September 30, 2011.

5. Commitments and Contingencies

Vessel Construction

In November 2011, the Company announced, and has since expanded, its fifth OSV newbuild program. This program consists of vessel construction contracts with two domestic shipyards to build four 300 class OSVs, six 310 class OSVs, and ten 320 class OSVs. The 20

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

vessels are expected to be placed in service as follows: five in 2013, 13 in 2014 and two in 2015. Based on current contracts and internal estimates, the aggregate total cost of this program, before construction period interest, is expected to be approximately $900.0 million. As of September 30, 2012, the Company had incurred construction costs of approximately $187.0 million, or 20.8%, since the inception of its fifth OSV newbuild program.

200 Class OSV Retrofit Program

In September 2012, the Company awarded a contract to Bollinger Shipyards for the upgrading and stretching of six of the Company’s Super 200 class DP-1 OSVs, converting them into 240 class DP-2 OSVs. The project costs for these discretionary vessel modifications are expected to be approximately $50.0 million, in the aggregate ($8.3 million each), and the Company expects to incur approximately 762 vessel-days of aggregate commercial downtime for the six vessels (127 vessel-days each). The current schedule projects the first two vessels to arrive at the shipyard in December 2012 with re-deliveries of two vessels each in May, August and December of 2013. As of September 30, 2012, the Company had incurred approximately $2.3 million, or 4.6%, since the inception of its 200 class OSV retrofit program.

Contingencies

In the normal course of its business, the Company becomes involved in various claims and legal proceedings in which monetary damages are sought. It is management’s opinion that the Company’s liability, if any, under such claims or proceedings would not materially affect its financial position, results of operations, or cash flows.

The Company insures against losses relating to its vessels, pollution and third party liabilities, including claims by employees under Section 33 of the Merchant Marine Act of 1920, or the Jones Act. Third-party liabilities and pollution claims that relate to vessel operations are covered by the Company’s entry in a mutual protection and indemnity association, or P&I Club, as well as by marine liability policies in excess of the P&I Club’s coverage. In February 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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 September 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 a material impact on its interim or annual results of operations.

On August 17, 2012, a customer, ATP Oil and Gas, Inc., initiated a reorganization proceeding under Chapter 11 of the United States Bankruptcy Code. Pre-petition receivables from ATP were $4.7 million and the Company has recorded $0.9 million in reserves. While the Company believes that the net receivables are collectible, it will continue to monitor the proceedings, which may result in actual collections that may differ from the current estimate.

6. Deferred Charges

Deferred charges include the following (in thousands):


	September 30, 2012		December 31, 2011
Deferred drydocking costs, net of accumulated amortization of $25,588 and $22,772, respectively	$	45,191	$	28,722
Deferred financing costs, net of accumulated amortization of $9,140 and $11,634 respectively		23,052		13,488
Prepaid lease expense, net of amortization of $1,028 and $909, respectively		3,361		3,479
Other deferred charges		2,055		2,092

Total	$	73,659	$	47,781

7. Segment Information

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

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table shows reportable segment information for the three and nine months ended September 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 September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Operating revenues:
Upstream
Domestic	$	81,963		$	51,057	$	223,006		$	118,815
Foreign (1)		33,124			40,896		121,672			102,443

		115,087			91,953		344,678			221,258

Downstream
Domestic		10,252			11,628		27,680			31,932
Foreign (1)(2)		2,600			2,246		7,199			5,721

		12,852			13,874		34,879			37,653

Total	$	127,939		$	105,827	$	379,557		$	258,911

Operating expenses:
Upstream	$	59,922		$	53,733	$	168,250		$	127,871
Downstream		7,237			9,011		21,574			24,909

Total	$	67,159		$	62,744	$	189,824		$	152,780

Depreciation:
Upstream	$	13,000		$	13,086	$	39,005		$	39,376
Downstream		2,124			2,144		6,372			6,383

Total	$	15,124		$	15,230	$	45,377		$	45,759

Amortization:
Upstream	$	5,289		$	3,953	$	15,287		$	11,434
Downstream		1,399			1,202		4,425			3,886

Total	$	6,688		$	5,155	$	19,712		$	15,320

General and administrative expenses:
Upstream	$	12,031		$	8,364	$	33,466		$	24,991
Downstream		912			681		2,684			2,415

Total	$	12,943		$	9,045	$	36,150		$	27,406

Gain (loss) on sale of assets:
Upstream	$	(357	)	$	976	$	(360	)	$	976
Downstream		624			—		624			559

Total	$	267		$	976	$	264		$	1,535

Operating income:
Upstream	$	24,488		$	13,793	$	88,310		$	18,562
Downstream		1,804			836		448			619

Total	$	26,292		$	14,629	$	88,758		$	19,181

Capital expenditures:
Upstream	$	73,856		$	10,008	$	164,256		$	21,601
Downstream		2,014			530		3,018			1,377
Corporate		1,582			538		2,410			990

Total	$	77,452		$	11,076	$	169,684		$	23,968

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


	As of September 30, 2012		As of December 31, 2011
Identifiable Assets:
Upstream	$	2,356,170	$	1,915,137
Downstream		206,976		197,876
Corporate		33,164		23,333

Total	$	2,596,310	$	2,136,346

Long-Lived Assets:
Upstream
Domestic	$	1,289,263	$	965,535
Foreign (1)		263,884		460,099

		1,553,147		1,425,634
Downstream
Domestic		142,164		146,027
Foreign (1)(2)		28,292		28,344

		170,456		174,371
Corporate		5,881		5,780

Total	$	1,729,484	$	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 September 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.

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 84 floating rigs under construction or on order on October 31, 2012 and, as of that date, there were options outstanding to build 31 additional floating rigs and 10 units announced but yet to be contracted with shipyards. In addition, on that date, there were 89 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 32 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

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 data compiled by IHS-Petrodata, the number of floating rigs available in the GoM region is currently 43, which has increased from the pre-Macondo level of 34, because the eight 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 20 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. This sporadic permitting activity has continued throughout 2012 and we anticipate that the pace of permit issuance will be uneven for some time to come. Of the 43 rigs available in the GoM, 32 were actively drilling as of October 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 high-spec vessels has continued through the third quarter of 2012. Leading-edge spot market OSV dayrates in the GoM for our 240 and 265 class DP-2 equipment remain in the $30,000 to $36,000 range. Whether these rates can be sustained will depend, among other things, on the future pace of permitting in the GoM. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs increased about $3,300, or roughly 21%, from $15,772 for the third quarter of 2011 to $19,072 for the third quarter of 2012. During the quarter ended September 30, 2012, we had an average stacked new generation OSV fleet of 2.1 vessels compared to 6.3 vessels for the same period in 2011. As of October 31, 2012, we had two DP-1 new generation OSVs stacked. We have elected to keep these vessels out-of-service due to the uneven demand for this equipment. During the third quarter we mobilized four DP-1 vessels from Brazil to the GoM. We determined not to renew contracts for these vessels with Petrobras due to high operating costs in Brazil and dayrates that were not commensurate with alternative markets for such vessels. Since their return to the GoM, these vessels have experienced low utilization due to planned drydockings and soft market conditions for DP-1 vessels in the GoM. The Company has selected these vessels to be converted into 240 class DP-2 vessels, which we believe will enable them to compete more effectively in the GoM, where DP-2 vessels are emerging as the industry standard for deepwater operations. We expect that these DP-1 vessels will experience additional softness prior to their shipyard periods which will commence on various dates in December 2012. The shipyard conversion period for each vessel is expected to last approximately 127 days, per vessel. Similar commercial downtime

has been experienced in the GoM by previously stacked DP-1 vessels that have been reactivated during 2012. The Company is considering whether these vessels are candidates for conversion to DP-2.

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. Mariner shortages have driven up labor costs, which comprise the greatest portion of our operating costs. To address intense competition for mariners, we increased our Upstream crew wages in April 2012 by roughly $5.0 million per quarter. We expect these increased wage levels to continue into 2013 and beyond. We will also have incremental expenses due to the expansion of our fleet personnel and shoreside support staff in anticipation of the vessels that will be delivered under our OSV newbuild program #5.

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 three 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 October 31, 2012, we had eight vessels working in Brazil under long-term contracts for Petrobras. 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. Production from 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 believe that this situation may be improved by the recent election of President Peña Nieto, who campaigned on constitutional reform to reinvigorate the Mexican oil industry. Currently, there are four floating rigs and 32 jack-up rigs drilling offshore Mexico. PEMEX has announced plans to add another floating rig and three more high-spec jack-up rigs during the remainder of 2012. We began working in Mexico in 2002 and currently have seven vessels working there under long-term contracts. We will continue to actively bid additional vessels into Mexico as tenders are issued by PEMEX.

Market conditions. As of October 31, 2012, we had 72% of our new generation OSV vessel-days contracted for the fourth quarter of 2012, with 30 vessels contracted beyond the end of the year. Our forward OSV contract coverage for 2013 currently stands at 35%. Our MPSV contract coverage for the fourth quarter 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 contract coverage for the remainder of 2012 and 2013 is currently 85% 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 September 30, 2012, our 49 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:


Operating Areas
Domestic
GoM			30
Other U.S. coastlines (1)			5

			35

Foreign
Brazil			8
Mexico			8
Middle East			2

			18

Total Upstream Vessels (2)			53

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

(2)	Excluded from this table are two of our new generation OSVs and one conventional OSV that were stacked as of September 30, 2012. The remaining stacked new generation OSVs are expected to remain inactive until there is sustainable demand for these vessels.

Our Downstream Segment

As of September 30, 2012, our Downstream fleet was comprised of nine double-hulled tank barges and 14 ocean-going tugs, five 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 to some extent. Although Downstream results for the third quarter have improved from the prior year, recent dayrate trends are well below the Downstream dayrates that existed from 2006 to 2008. Driven by demand in the GoM resulting from the Eagle Ford shale trend, we outfitted three additional vessels with vapor-recovery systems during the second quarter of 2012 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 fourth quarter of 2012 and first half of 2013. 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.

Results of Operations

The tables below set forth, by segment, the average dayrates, utilization rates and effective dayrates for our vessels and the average number and size of vessels owned during the periods indicated. These new generation OSVs and tank barges generate a substantial portion of our revenues and operating profit. Excluded from the OSV information below are the results of operations for our MPSVs, conventional vessels, our shore-base facility, and vessel management services. The Company does not provide average or effective dayrates for its 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 September 30,						Nine Months Ended September 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)		48.9			44.7			47.9			40.5
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)		79.5	%		75.3	%		82.9	%		67.5	%
Effective new generation OSV utilization rate (4)		82.9	%		85.9	%		88.3	%		84.9	%
Average new generation OSV dayrate (5)	$	23,990		$	20,945		$	23,248		$	20,812
Effective dayrate (6)	$	19,072		$	15,772		$	19,273		$	14,048
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)		93.4	%		92.0	%		84.5	%		88.3	%
Average dayrate (8)	$	16,626		$	18,222		$	16,742		$	17,351
Effective dayrate (6)	$	15,529		$	16,764		$	14,147		$	15,321

(1)	We owned 51 new generation OSVs as of September 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 2009 and 2010. Based on improved market conditions, we had re-activated 13 new generation OSVs as of September 30, 2012. The two remaining stacked new generation OSVs are expected to remain inactive until there is sustainable demand for these vessels. 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 five 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.

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 nine months ended September 30, 2012 and 2011, respectively (in thousands).


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Components of EBITDA:
Net income (loss)	$	7,401		$	(741	)	$	25,722		$	(16,802	)
Interest expense, net
Debt obligations		14,697			15,062			42,971			44,976
Interest income		(524	)		(156	)		(1,538	)		(575	)

Total interest, net		14,173			14,906			41,433			44,401

Income tax expense (benefit)		4,713			445			15,879			(8,360	)
Depreciation		15,124			15,230			45,377			45,759
Amortization		6,688			5,155			19,712			15,320

EBITDA	$	48,099		$	34,995		$	148,123		$	80,318

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
EBITDA Reconciliation to GAAP:
EBITDA	$	48,099		$	34,995		$	148,123		$	80,318
Cash paid for deferred drydocking charges		(12,700	)		(6,098	)		(32,445	)		(16,478	)
Cash paid for interest		(10,378	)		(10,633	)		(28,755	)		(32,481	)
Cash paid for income taxes		(235	)		(334	)		(964	)		(833	)
Changes in working capital		20,545			(21,553	)		8,303			(17,051	)
Stock-based compensation expense		3,729			1,728			8,164			5,654
Loss on early extinguishment of debt		—			—			6,048			—
Changes in other, net		960			(740	)		1,393			(31	)

Net cash flows provided by operating activities	$	50,020		$	(2,635	)	$	109,867		$	19,098

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 nine months ended September 30, 2012 and 2011, respectively (in thousands).

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Loss on early extinguishment of debt	$	—	$	—	$	6,048	$	—
Stock-based compensation expense		3,729		1,728		8,164		5,654
Interest income		524		156		1,538		575

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

•

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

•

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

•

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

•

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

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

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


	Three Months Ended September 30						Increase (Decrease)
	2012			2011			$ Change			% Change
Revenues:
Upstream
Domestic	$	81,963		$	51,057		$	30,906			60.5	%
Foreign		33,124			40,896			(7,772	)		(19.0	)

		115,087			91,953			23,134			25.2

Downstream
Domestic		10,252			11,628			(1,376	)		(11.8	)
Foreign (1)		2,600			2,246			354			15.8

		12,852			13,874			(1,022	)		(7.4	)

	$	127,939		$	105,827		$	22,112			20.9	%

Operating expenses:
Upstream	$	59,922		$	53,733		$	6,189			11.5	%
Downstream		7,237			9,011			(1,774	)		(19.7	)

	$	67,159		$	62,744		$	4,415			7.0	%

Depreciation and amortization:
Upstream	$	18,289		$	17,039		$	1,250			7.3	%
Downstream		3,523			3,346			177			5.3

	$	21,812		$	20,385		$	1,427			7.0	%

General and administrative expenses:
Upstream	$	12,031		$	8,364		$	3,667			43.8	%
Downstream		912			681			231			33.9

	$	12,943		$	9,045		$	3,898			43.1	%

Gain (loss) on sale of assets:
Upstream	$	(357	)	$	976		$	(1,333	)		>(100.0)	%
Downstream		624			—			624			100.0

	$	267		$	976		$	(709	)		(72.6	)%

Operating income:
Upstream	$	24,488		$	13,793		$	10,695			77.5	%
Downstream		1,804			836			968			>100.0

	$	26,292		$	14,629		$	11,663			>79.7	%

Interest expense	$	14,697		$	15,062		$	(365	)		(2.4	)%

Interest income	$	524		$	156		$	368			>100.0	%

Income tax expense	$	4,713		$	445		$	4,268			>100.0	%

Net income (loss)	$	7,401		$	(741	)	$	8,142			>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.

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

Revenues. Revenues for the three months ended September 30, 2012 increased by $22.1 million, or 20.9%, to $127.9 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 September 30, 2012 was 71 vessels compared to 67 during the same period in 2011, entirely due to the reactivation of previously stacked vessels.

Revenues from our Upstream segment increased by $23.1 million, or 25.1%, to $115.1 million for the three months ended September 30, 2012 compared to $92.0 million for the same period in 2011. Higher Upstream revenues for the third quarter of 2012 compared to the same period in 2011 primarily resulted from increased demand for our high-spec OSVs and MPSVs, and, to a lesser extent, the re-activation of 200 class new generation OSVs that were previously stacked. Our new generation OSV average dayrates were $23,990 for the third quarter of 2012 compared to $20,945 for the same period in 2011, an increase of $3,045, or 14.5%. Our new generation OSV utilization was 79.5% for the third quarter of 2012 compared to 75.3% for the same period in 2011. Our new generation OSV utilization for the third quarter of 2012 was favorably impacted by the increase in the number of our active Upstream vessels. Our vessel count included an average of 2.1 stacked vessels during the three months ended September 30, 2012 compared to an average of 6.3 stacked vessels during the prior-year period. Domestic revenues for our Upstream segment increased $30.9 million from the year-ago quarter due to improved spot market activity in the GoM. Foreign revenues for our Upstream segment decreased $7.8 million, or 19.0%, primarily due to an average of six fewer vessels deployed to Latin America during the three months ended September 30, 2012 compared to the year-ago quarter. Foreign revenues comprised 28.8% of our total Upstream revenues compared to 44.5% for the year-ago quarter

Revenues from our Downstream segment decreased by $1.0 million, or 7.4%, to $12.9 million for the three months ended September 30, 2012 compared to the year-ago quarter. This revenue decrease was largely due to a higher concentration of our vessels operating under time charter contracts instead of COAs. Our double-hulled tank barge average dayrates were $16,626 for the three months ended September 30, 2012, a decrease of $1,596, or 8.8%, from $18,222 for the same period in 2011. Our double-hulled tank barge utilization was 93.4% for the third quarter of 2012 compared to 92.0% for the third quarter of 2011. Effective, or utilization-adjusted, dayates for our double-hulled tank barges were $15,529 for the three months ended September 30, 2012, which was $1,235, or 7.4%, lower than the prior-year quarter effective dayrates.

Operating expenses. Operating expenses for the three months ended September 30, 2012 increased by $4.4 million, or 7.0%, to $67.2 million. This increase was primarily associated with the increase of our active operating fleet compared to the year-ago quarter and higher crew wages.

Operating expenses for our Upstream segment were $59.9 million, an increase of $6.2 million, or 11.5%, for the third quarter of 2012 compared to $53.7 million for the same period in 2011. Higher operating expenses for our Upstream segment were driven by a decrease in the number of stacked vessels and higher crew wages. These expenses were partially offset by lower expenses related to mobilizing four vessels to Latin America during the three months ended September 30, 2011.

Operating expenses for our Downstream segment were $7.2 million, a decrease of $1.8 million, or 20.0%, for the three months ended September 30, 2012 compared to $9.0 million for the same period in 2011. The decrease in operating expenses is largely the result of having lower fuel expense due to a greater mix of Downstream vessels operating under time charter agreements instead of COAs. Under COA arrangements, the vessel owner bears the cost of fuel, which is typically covered through higher dayrates. Our contracts during the first three months of 2011 were primarily comprised of COA voyages.

Depreciation and Amortization. Depreciation and amortization was $1.4 million higher for the three months ended September 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 are delivered or undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $12.9 million, or 10.1% of revenues, increased by $3.9 million during the three months ended September 30, 2012 compared to same period in 2011. This increase in G&A expenses was primarily attributable to higher shoreside incentive compensation, fleet recruiting and training expenses, and bad debt reserves. Our general and administrative expenses are expected to be in the approximate annual range of $48 million to $50 million for the year ending December 31, 2012.

Gain on Sale of Assets. During the third quarter of 2012, we sold one older, lower-horsepower tug and certain shoreside assets for net cash proceeds of $3.0 million, which resulted in aggregate gains of approximately $0.3 million ($0.2 million after-tax or $0.01 per diluted share). During the third quarter of 2011, we sold two ROVs for aggregate net cash proceeds of $9.3 million. This sale resulted in a pre-tax gain of approximately $1.0 million ($0.6 million after tax or $0.02 per diluted share).

Operating Income. Operating income increased by $11.7 million to $26.3 million during the three months ended September 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 21.3% for the three months ended September 30, 2012 compared to 15.0% for the same period in 2011. Operating income as a percentage of revenues for our Downstream segment was 14.0% for the three months ended September 30, 2012 compared to 5.8% for the same period in 2011.

Interest Expense. Interest expense decreased $0.4 million during the three months ended September 30, 2012 compared to the same period in 2011. Higher capitalized interest associated with vessels under construction was the primary reason that our interest expense decreased from the prior-year quarter. During the third quarter of 2012, we capitalized interest of $2.9 million, or roughly 16% of our total interest costs compared to not capitalizing any construction period interest for the year-ago quarter. This net decrease in interest expense was partially offset by the incurrence of an incremental $1.4 million of interest expense related to the issuance of $300.0 million of aggregate principal amount of new convertible senior notes on August 13, 2012.

Interest Income. Interest income increased $0.4 million during the three months ended September 30, 2012 compared to the same period in 2011. Our average cash balance increased to $541.2 million for the three months ended September 30, 2012 compared to $136.1 million for the same period in 2011. The average interest rate earned on our invested cash balances was 0.4% and 0.5% during the three months ended September 30, 2012 and 2011, respectively. The increase in average cash balance was primarily due to our November 2011 equity offering, February 2012 bond refinancing and our August 2012 convertible senior notes offering, which resulted in net cash proceeds of $554.1 million in the aggregate.

Income Tax Expense. Our effective income tax rate was 38.9% for the three months ended September 30, 2012. 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. During the third quarter of 2011, we revised our expected effective tax rate for the year ending December 31, 2011 from 35% to 33% based on changes to our expected full-year operating results. This resulted in a reduction to our expected tax benefit for the year ending December 31, 2011 of approximately $0.5 million. Accordingly, for the quarter ended September 30, 2011, we recorded tax expense instead of the tax benefit, which is normally recorded for pre-tax loss results.

Net Income (Loss). Operating performance increased by $8.1 million for reported net income of $7.4 million for the three months ended September 30, 2012 compared to a net loss of $0.7 million for the three months ended September 30, 2011. The higher net income for the third quarter of 2012 was primarily due to the increase in operating income based on improved market conditions discussed above and a $0.7 million pre-tax decrease in net interest expense.

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


	Nine Months Ended September 30						Increase (Decrease)
	2012			2011			$ Change			% Change
Revenues:
Upstream
Domestic	$	223,006		$	118,815		$	104,191			87.7	%
Foreign		121,672			102,443			19,229			18.8

		344,678			221,258			123,420			55.8

Downstream
Domestic		27,680			31,932			(4,252	)		(13.3	)
Foreign (1)		7,199			5,721			1,478			25.8

		34,879			37,653			(2,774	)		(7.4	)

	$	379,557		$	258,911		$	120,646			46.6	%

Operating expenses:
Upstream	$	168,250		$	127,871		$	40,379			31.6	%
Downstream		21,574			24,909			(3,335	)		(13.4	)

	$	189,824		$	152,780		$	37,044			24.2	%

Depreciation and amortization:
Upstream	$	54,292		$	50,810		$	3,482			6.9	%
Downstream		10,797			10,269			528			5.1

	$	65,089		$	61,079		$	4,010			6.6	%

General and administrative expenses:
Upstream	$	33,466		$	24,991		$	8,475			33.9	%
Downstream		2,684			2,415			269			11.1

	$	36,150		$	27,406		$	8,744			31.9	%

Gain (loss) on sale of assets:
Upstream	$	(360	)	$	976		$	(1,336	)		>(100.0	)%
Downstream		624			559			65			11.6

	$	264		$	1,535		$	(1,271	)		(82.8	)%

Operating income:
Upstream	$	88,310		$	18,562		$	69,748			>100.0	%
Downstream		448			619			(171	)		>(100.0	)

	$	88,758		$	19,181		$	69,577			>100.0	%

Loss on early extinguishment of debt	$	6,048		$	—		$	6,048			100.0	%

Interest expense	$	42,971		$	44,976		$	(2,005	)		(4.5	)%

Interest income	$	1,538		$	575		$	963			>100.0	%

Income tax expense (benefit)	$	15,879		$	(8,360	)	$	24,239			>100.0	%

Net income (loss)	$	25,722		$	(16,802	)	$	42,524			>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.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Revenues. Revenues for the nine months ended September 30, 2012 increased by $120.6 million, or 46.6%, to $379.6 million compared to the same period in 2011 primarily due to improved Upstream market conditions. Our weighted-average active operating fleet for the nine months ended September 30, 2012 was 70 vessels compared to 63 during the same period in 2011, entirely due to the reactivation of previously stacked vessels.

Revenues from our Upstream segment increased by $123.4 million, or 55.8%, to $344.7 million for the nine months ended September 30, 2012 compared to $221.3 million for the same period in 2011. Our Upstream revenues were driven higher primarily due to increased demand for our high-spec OSVs and MPSVs, and the re-activation of 13 new generation OSVs that had been previously stacked. Our new generation OSV average dayrates were $23,248 for the first nine months of 2012 compared to $20,812 for the same period in 2011, an increase of $2,436, or 11.7%. Our new generation OSV utilization was 82.9% for the first nine months of 2012 compared to 67.5% for the same period in 2011. Our new generation OSV utilization for the first nine months of 2012 was favorably impacted by the re-activation of OSVs that had been stacked. Our vessel count included an average of 3.1 stacked vessels during the nine months ended September 30, 2012 compared to an average of 10.5 stacked vessels during the prior-year period. Domestic revenues for our Upstream segment increased $104.2 million during the nine months ended September 30, 2012 due to improved spot market activity for our OSVs and MPSVs in the GoM. Foreign revenues for our Upstream segment increased $19.2 million, or 18.8%, primarily due to additional vessels deployed to Latin America since early 2011. Foreign revenues comprised 35.3% of our total Upstream revenues compared to 46.3% for the year-ago period.

Revenues from our Downstream segment decreased by $2.8 million, or 7.4%, to $34.9 million for the nine months ended September 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 nine months of 2012 compared to the same period in 2011. Our double-hulled tank barge average dayrates were $16,742 for the nine months ended September 30, 2012 compared to $17,351 for the same period in 2011, a decrease of $609 or 3.5%. Our double-hulled tank barge utilization was 84.5% for the first nine months of 2012 compared to 88.3% for the first nine months of 2011.

Operating expenses. Operating expenses for the nine months ended September 30, 2012 increased by $37.0 million, or 24.2%, to $189.8 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 $168.3 million, an increase of $40.4 million, or 31.6%, for the first nine months of 2012 compared to $127.9 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, higher costs for our vessels operating in Latin America and higher crew wages. Market-driven mariner wage increases that commenced in April 2012 increased our Upstream operating expenses for 2012 by approximately $5 million per quarter.

Operating expenses for our Downstream segment were $21.6 million, a decrease of $3.3 million, or 13.3%, for the nine months ended September 30, 2012 compared to $24.9 million for the same period in 2011. The decrease in operating expenses is largely the result of having lower fuel expense 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 bears the cost of fuel, which is typically covered through higher dayrates. Our contracts during the first nine months of 2011 were primarily comprised of COA voyages.

Depreciation and Amortization. Depreciation and amortization was $4.0 million higher for the nine months ended September 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 are delivered or undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $36.2 million, or 9.5% of revenues, increased by $8.7 million during the nine months ended September 30, 2012 compared to the same period in 2011. This increase in G&A expense was primarily attributable to higher shoreside incentive compensation, fleet recruiting and training expenses and bad debt reserves. Our general and administrative expenses are expected to be in the approximate annual range of $48 million to $50 million for the year ending December 31, 2012.

Gain on Sale of Assets. During the first nine months of 2012, we sold one older, lower-horsepower tug, and certain shoreside assets for net cash proceeds of $4.3 million, which resulted in aggregate gains of approximately $0.3 million ($0.2 million after-tax or $0.01 per diluted share). During the first nine months of 2011, we sold four single-hulled tank barges and two ROVs for net cash proceeds of $11.3 million, which resulted in aggregate gains of approximately $1.5 million ($1.0 million after-tax or $0.04 per diluted share).

Operating Income. Operating income increased by $69.6 million, or 362.5%, to $88.8 million during the nine months ended September 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 25.6% for the nine months ended September 30, 2012 compared to 8.4% for the same period in 2011. Operating income as a percentage of revenues for our Downstream segment was 1.3% for the nine months ended September 30, 2012 compared to 1.6% 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 nine months of 2012, we recorded a loss on early extinguishment of 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. No debt was retired in 2011.

Interest Expense. Interest expense decreased $2.0 million during the nine months ended September 30, 2012 compared to the same period in 2011. Higher capitalized interest from having vessels under construction was the primary reason that our interest expense decreased from the prior-year period. During the first nine months of 2012, we capitalized interest of $6.4 million, or roughly 13% of our total interest costs compared to not capitalizing any construction period interest for the year-ago period.

Interest Income. Interest income increased $1.0 million during the nine months ended September 30, 2012 compared to the same period in 2011. Our average cash balance increased to $452.4 million for the nine months ended September 30, 2012 compared to $139.0 million for the same period in 2011. The average interest rate earned on our invested cash balances was 0.4% and 0.5% during the nine months ended September 30, 2012 and 2011, respectively. The year-over-year increase in average cash balance was primarily due to our November 2011 equity offering, February 2012 bond refinancing and our August 2012 convertible senior notes offering, which resulted in net cash proceeds of $554.1 million in the aggregate.

Income Tax Expense. Our effective tax rate was 38.2% and 33.2% for the nine months ended September 30, 2012 and 2011, respectively. The tax rate for the first nine months of 2012 is higher than the benefit rate for the first nine 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 $42.5 million for reported net income of $25.7 million for the nine months ended September 30, 2012. The higher net income for the first nine months of 2012 was primarily due to the increase in operating income based on improved market conditions discussed above and a $3.0 million pre-tax decrease in net interest expense. Net income for the first nine months 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, our fifth OSV newbuild program, our OSV retrofit program, reactivation of stacked vessels, vessel recertifications, discretionary capital expenditures and debt service and may require capital to fund potential future vessel construction, retrofit or conversion projects or acquisitions. The nature of our capital requirements and the types of our financing sources are not expected to change significantly for the remainder of 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 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 amended and restated 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 and our OSV retrofit program.

As of September 30, 2012, we had total cash and cash equivalents of $633.6 million. We also have a $300 million revolving credit facility, expandable up to $500 million, which is undrawn as of October 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 be sufficient to meet our liquidity needs for the foreseeable future. As of September 30, 2012, we had posted letters of credit for $0.9 million and had $299.1 million of credit available under our revolving credit facility. The full undrawn credit amount of such facility is available for all uses of proceeds, including working capital, if necessary. However, the intended uses of the facility are the 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 our 2026 convertible senior notes in November 2013. Our currently undrawn revolving credit facility matures in November 2016.

Depending on the market demand for our vessels, long-term debt maturities and other growth opportunities that may arise, we may require additional debt or equity financing. We currently expect to generate sufficient cash to meet our obligations under our fifth OSV newbuild program and OSV retrofit 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 $109.9 million for the nine months ended September 30, 2012 and $19.1 million for the same period

in 2011. Operating cash flows for the first nine months of 2012 were favorably affected by an increase in our weighted-average operating fleet and improved market conditions in both our Upstream and Downstream segments.

Investing Activities. Net cash used in investing activities was $165.4 million for the nine months ended September 30, 2012 and $12.6 million for the same period in 2011. Cash utilized during the first nine months of 2012 primarily consisted of construction costs incurred for our fifth OSV newbuild program and capital improvements made to our operating fleet, which were partially offset by approximately $4.3 million in aggregate net cash proceeds from the sale of one older, lower-horsepower tug, and shoreside assets. Cash utilized during the first nine months of 2011 primarily consisted of capital improvements made to our operating fleet, which were partially offset by approximately $11.3 million in aggregate net cash proceeds from the sale of four single-hulled tank barges and two ROVs.

Financing Activities. Net cash provided by financing activities was $332.4 million for the nine months ended September 30, 2012 compared to cash used in financing activities of $1.2 million for the same period in 2011. Net cash provided by financing activities for the nine months ended September 30, 2012 primarily resulted from the issuance of our 5.875% senior notes due 2020, or 2020 senior notes and the issuance of our 1.500% convertible senior notes due 2019, or the 2019 convertible senior notes. These cash inflows were partially offset by the repurchase and retirement or redemption of our 6.125% senior notes due 2014. Net cash used in financing activities for the nine months ended September 30, 2011 was comprised of cash outflows related to the tax effects on share-based payments and deferred financing costs partially offset by 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 2014 senior notes. The tender offer expired on March 29, 2012. On March 2, 2012, we also completed the private placement of 2020 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 2014 senior notes. The $47.8 million of remaining 2014 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 2014 senior notes during the first nine months 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).

On August 13, 2012, we completed the private placement of $300.0 million in aggregate principal amount of 2019 convertible senior notes, which generated net cash proceeds of $266.0 million. These 2019 convertible senior notes have a cash coupon of 1.500% and a conversion of price 37.5% higher than closing stock price on August 7, 2012 of $39.16. In conjunction with this offering, we also entered into separate convertible senior note hedge transactions that increased the conversion price to $68.53. After funding the 2019 convertible senior note hedge transactions, the remaining proceeds, along with other available sources of cash, will be used to retire the outstanding 2026 convertible senior notes that are callable by the Company in November 2013.

Contractual Obligations

Debt

As of September 30, 2012, we had total debt of $1,083.1 million, net of original issue discount of $91.9 million. Our debt is comprised of $245.0 million of our 8.000% senior notes due 2017, $375.0 million of our 5.875% senior notes due 2020, $227.4 million of our 1.500% convertible senior notes due 2019, and $235.7 million of our 1.625% convertible senior notes due 2026. 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 September 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 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 September 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. 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 nine months ended September 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 September 30, 2012		Nine Months Ended September 30, 2012		Incurred Since Inception		Estimated Program Totals(1)		Projected Delivery Dates(1)
Growth Capital Expenditures:
OSV newbuild program #5 (2)	$	66.6	$	144.6	$	187.0	$	900.0		2Q2013-1Q2015

(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 now consists of vessel construction contracts with two domestic shipyards to build four 300 class OSVs, six 310 class OSVs, and ten 320 class OSVs. Delivery of the vessels to be constructed under this program is expected to occur on various dates during 2013 and 2015. We expect to own and operate 56, 69, and 71 new generation OSVs as of December 31, 2013, 2014, and 2015, respectively. These vessel additions result in a projected average new generation OSV fleet complement of 52.2, 63.0, and 70.9 vessels for the fiscal years 2013, 2014, and 2015, respectively.

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


	Three Months Ended September 30,				Nine Months Ended September 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)	$	12.7	$	6.1	$	32.4	$	16.5	$	45.5
Other vessel capital improvements (2)		1.2		1.8		8.5		8.1		11.5

		13.9		7.9		40.9		24.6		57.0

Other Capital Expenditures
Commercial-related vessel improvements (3)		5.2		8.6		7.6		14.4		13.8
Miscellaneous non-vessel additions (4)		1.6		0.7		2.6		1.4		4.3

		6.8		9.3		10.2		15.8		18.1

Total	$	20.7	$	17.2	$	51.1	$	40.4	$	75.1

(1)	Deferred drydocking charges for the full-year 2012 include the actual and projected recertification costs for 23 OSVs, two MPSV, three tank barges and three tugs.

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

(3)

Commercial-related vessel improvements include items, such as cranes, ROVs and other specialized vessel equipment, as well as costs related to our 200 class OSV retrofit program, which consists of a vessel construction contract with a domestic shipyard to upgrade and stretch six of our Super 200 class DP-1 OSVs converting them into 240 class DP-2 OSVs. The estimated total project costs for such program, which is expected to commence in December 2012 and be completed in December 2013, is $50.0 million. During the three and nine months ended September 30, 2012 we incurred $2.3 million related to our 200 class OSV retrofit program. These commercial-related vessel improvement costs are expected to result in higher dayrates charged to customers.

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

Forward Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements,” as contemplated by the Private Securities Litigation Reform Act of 1995, in which the Company discusses factors it believes may affect its performance in the future. Forward-looking statements are all statements other than historical facts, such as statements regarding assumptions, expectations, beliefs and projections about future events or conditions. You can generally identify forward-looking statements by the appearance in such a statement of words like “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “remain,” “should,” 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 and its 200 class OSV retrofit program on-time and on-budget, which involves the construction, conversion and integration of highly complex vessels and systems; the inability to successfully market the vessels that the Company owns, is constructing or might acquire; an oil spill or other significant event in the United States or another offshore drilling region that could have a broad impact on deepwater and other offshore energy exploration and production activities, such as the suspension of activities or significant regulatory responses; the imposition of laws or regulations that result in reduced exploration and production activities or that increase the Company’s operating costs or operating requirements, including any such laws or regulations that may yet arise as a result of the Deepwater Horizon incident or the resulting drilling moratoria and regulatory reforms, as well as the outcome of pending litigation brought by environmental groups challenging exploration plans approved by the Department of Interior; less than anticipated success in marketing and operating the Company’s MPSVs; 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; 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

We have not entered into any derivative financial instrument transactions to manage or reduce market risk or for speculative purposes, other than the convertible note hedge and warrant transactions entered into concurrently with our convertible note offerings in November 2006 and August 2012. Such transactions were entered into to mitigate the potential dilutive effect of the conversion feature of the convertible notes on our common stock. A hypothetical 25% change from our closing share price of $36.65 as of September 28, 2012, the last trading day of the third quarter, would not have had an impact on such transactions.

Changes in interest rates may result in changes in the fair market value of our financial instruments, interest income and interest expense. Our financial instruments that are exposed to interest rate risk are cash equivalents and long-term borrowings. Due to the short duration and conservative nature of our cash equivalent investment portfolio, we do not expect any material loss with respect to our investments. The book value for cash equivalents is considered to be representative of its fair value. A hypothetical 10% change in interest rates as of September 30, 2012 would have had no material impact on such investments, interest income or interest expense.

Changes in interest rates would not impact the interest expense for our long-term fixed interest rate 8.000% senior notes, 5.875% senior notes, 1.625% convertible senior notes and 1.500% convertible senior notes. However, changes in interest rates would impact the fair market value of such notes. In general, the fair market value of debt with a fixed interest rate will increase as interest rates fall. Conversely, the fair market value of debt will decrease as interest rates rise. The currently outstanding 8.000% senior notes accrue interest at a rate of 8.000% per annum and mature on September 1, 2017 and the effective interest rate on such notes is 8.63%. The currently outstanding 5.875% senior notes accrue interest at the rate of 5.875% per annum and mature on April 1, 2020 and the effective interest rate on such notes is 6.08%. Our outstanding 1.625% convertible senior notes accrue interest at the rate of

1.625%, which will decline to 1.375% beginning on November 15, 2013, and mature on November 15, 2026. The effective interest rate, after taking into account the accretion of original issue discount, on such notes is 6.36%. Our outstanding 1.500% convertible senior notes accrue interest at the rate of 1.500% and mature on September 1, 2019. The effective interest rate on such notes, after taking into account the accretion of original issue discount, is 5.33%.

In connection with both our series of convertible notes, we are a party to convertible note hedge transactions with respect to our common stock. With respect to the convertible note hedge transactions associated with our 1.625% convertible senior notes, the counterparties to such transactions are Jefferies & Company, Inc., Bear Stearns International Limited and AIG-FP Structured Finance (Cayman) Limited. As a result of the financial markets crisis during the third quarter of 2008, the Bear Stearns International Limited position has been assumed by JPMorgan Chase in its acquisition of Bear Stearns and AIG-FP Structured Finance (Cayman) Limited’s parent company, or AIG, was re-capitalized by the U.S. Government. With respect to the convertible note hedge transactions associated with our 1.500% convertible senior notes, the counterparties to such transactions are Barclays Bank PLC; JPMorgan Chase Bank, National Association, London Branch; and Wells Fargo Bank, National Association. We are not currently aware of any collection issues with regard to any of these counterparties

We estimate the fair value of our 8.000% senior notes due 2017, 5.875% senior notes due 2020, our 1.625% convertible senior notes due 2026 and our 1.500% convertible senior notes due 2019, all of which are publicly traded, by using quoted market prices. The fair value of our undrawn revolving credit facility, when there are outstanding balances, approximates its carrying value. The face value, carrying value and fair value of our total debt was $1,175.0 million, $1,083.1 million and $1,209.1 million, respectively, as of September 30, 2012.

As of September 30, 2012, we had no amounts outstanding under our variable interest rate revolving credit facility. Therefore it is not subject to interest rate risk.

We have operations in international markets, which include two of our primary geographic regions of Brazil and Mexico. We currently have time charters for 18 of our Upstream vessels working in foreign markets. Although most of our time charter contracts are denominated U.S. Dollars, we do collect time charter payments and value added tax, or VAT, payments in local currencies for seven vessels, which creates an exchange risk related to currency fluctuations. We also frequently acquire other vessel equipment for our active vessels that are denominated in foreign currencies, which creates an exchange risk to foreign currency fluctuations related to the payment terms of such commitments or purchases. To date, we have not hedged against any foreign currency rate fluctuations associated with foreign currency VAT payments or other foreign currency denominated transactions arising in the normal course of business. We continually monitor the currency exchange risks associated with conducting international operations. To date, gains or losses associated with such fluctuations have not been material. However, should we further expand our operations in international markets, we may become exposed to certain risks typically associated with foreign currency fluctuation.

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 September 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 Disclosures

None.

Item 5—Other Information

Glossary of Terms

“AHTS” means anchor-handling towing supply;

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

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

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

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

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

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

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

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

“domestic public company OSV peer group” includes 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;

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

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

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

“Jones Act” means the U.S. cabotage 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.;

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

“ROV” means a remotely operated vehicle;

“spot contract” means a time charter of less than one year in duration;

“stacked vessel” means a vessel that has been removed from service to reduce operating costs due to a lack of adequate marketing opportunities, whereby its crew is removed and limited maintenance is performed on the vessel;

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

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

“U.S. citizen” means persons who are “citizens of the United States” as defined under the Jones Act.

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).


Exhibit Number		Description of Exhibit
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).

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).


Exhibit Number		Description of Exhibit
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).

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

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

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

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

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


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

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

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

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

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

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

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

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

10.1		Purchase Agreement dated August 7, 2013 by and among Hornbeck Offshore Services, Inc., the guarantors named therein, and Barclays Capital Inc., J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers named in Schedule I thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 13, 2012).

*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.


Exhibit Number		Description of Exhibit
*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.

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.