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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

 

x

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

For the quarterly period ended September 30, 2011

OR

 

¨

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

For the transition period from                      to                     

Commission file number 001-32108

 

 

Hornbeck Offshore Services, Inc.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

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

103 NORTHPARK BOULEVARD, SUITE 300

COVINGTON, LA 70433

(Address of Principal Executive Offices) (Zip Code)

(985) 727-2000

(Registrant’s Telephone Number, Including Area Code)

 

 

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

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

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

 

Large accelerated filer  ¨		Non-accelerated filer  ¨
Accelerated filer  x		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, 2011 was 26,926,899.

 

 

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS

 

PART I—FINANCIAL INFORMATION			1
Item 1—Financial Statements			1
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations			12
Item 3—Quantitative and Qualitative Disclosures About Market Risk			33
Item 4—Controls and Procedures			33
PART II—OTHER INFORMATION			33
Item 1—Legal Proceedings			33
Item 1A—Risk Factors			33
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds			38
Item 3—Defaults Upon Senior Securities			38
Item 4—Removed and Reserved			38
Item 5—Other Information			38
Item 6—Exhibits			40
SIGNATURE			43

 

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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,				December 31,
		2011				2010
ASSETS			(Unaudited)
Current assets:
Cash and cash equivalents		$	131,919			$	126,966
Accounts receivable, net of allowance for doubtful accounts of $2,238 and $734, respectively			90,985				71,777
Other current assets			21,856				17,598
Total current assets			244,760				216,341
Property, plant and equipment, net			1,573,692				1,606,121
Deferred charges, net			44,104				41,058
Other assets			14,450				14,905
Total assets		$	1,877,006			$	1,878,425
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	31,680			$	25,100
Accrued interest			9,315				9,024
Accrued payroll and benefits			10,206				13,413
Deferred revenue			2,777				2,197
Other accrued liabilities			8,397				4,451
Total current liabilities			62,375				54,185
Long-term debt, net of original issue discount of $32,539 and $41,767, respectively			767,461				758,233
Deferred tax liabilities, net			216,564				222,413
Other liabilities			1,347				1,717
Total liabilities			1,047,747				1,036,548
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; 26,927 and 26,584 shares issued and outstanding, respectively			270				266
Additional paid-in-capital			420,158				415,673
Retained earnings			408,832				425,634
Accumulated other comprehensive income (loss)			(1	)			304
Total stockholders’ equity			829,259				841,877
Total liabilities and stockholders’ equity		$	1,877,006			$	1,878,425

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

 

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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,
		2011				2010				2011				2010
		(Unaudited)								(Unaudited)
Revenues		$	105,827			$	125,351			$	258,911			$	323,482
Costs and expenses:
Operating expenses			62,744				53,241				152,780				146,080
Depreciation			15,230				15,012				45,759				43,275
Amortization			5,155				4,775				15,320				13,671
General and administrative expenses			9,045				9,733				27,406				28,294
			92,174				82,761				241,265				231,320
Gain on sale of assets			976				725				1,535				1,344
Operating income			14,629				43,315				19,181				93,506
Other income (expense):
Interest income			156				104				575				353
Interest expense			(15,062	)			(14,422	)			(44,976	)			(40,353	)
Other income (expense), net			(19	)			22				58				257
			(14,925	)			(14,296	)			(44,343	)			(39,743	)
Income (loss) before income taxes			(296	)			29,019				(25,162	)			53,763
Income tax (expense) benefit			(445	)			(10,816	)			8,360				(19,962	)
Net income (loss)		$	(741	)		$	18,203			$	(16,802	)		$	33,801
Basic earnings (loss) per common share		$	(0.03	)		$	0.69			$	(0.63	)		$	1.28
Diluted earnings (loss) per common share		$	(0.03	)		$	0.67			$	(0.63	)		$	1.24
Weighted average basic shares outstanding			26,919				26,446				26,839				26,365
Weighted average diluted shares outstanding			26,919				27,192				26,839				27,157

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

 

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HORNBECK OFFSHORE SERVICES, INC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

		Nine Months Ended September 30,
		2011				2010
		(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(16,802	)		$	33,801
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation			45,759				43,275
Amortization			15,320				13,671
Stock-based compensation expense			5,654				6,835
Provision for bad debts			1,504				(98	)
Deferred tax expense (benefit)			(9,519	)			19,471
Amortization of deferred financing costs			11,803				11,317
Gain on sale of assets			(1,535	)			(1,344	)
Equity in loss from investment			—				6
Changes in operating assets and liabilities:
Accounts receivable			(19,663	)			(12,850	)
Other receivables and current assets			(3,530	)			8,136
Deferred drydocking charges			(16,478	)			(15,661	)
Accounts payable			6,007				1,722
Accrued liabilities and other liabilities			(1,636	)			(6,608	)
Accrued interest			292				(154	)
Net cash provided by operating activities			17,176				101,519
CASH FLOWS FROM INVESTING ACTIVITIES:
Costs incurred for MPSV program			—				(8,533	)
Costs incurred for OSV newbuild program #4			—				(26,984	)
Net proceeds from sale of assets			11,335				2,799
Vessel capital expenditures			(22,586	)			(22,134	)
Non-vessel capital expenditures			(1,382	)			(1,497	)
Net cash used in investing activities			(12,633	)			(56,349	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs			(490	)			(65	)
Net cash proceeds from other shares issued			1,205				743
Net cash provided by financing activities			715				678
Effects of exchange rate changes on cash			(305	)			100
Net increase in cash and cash equivalents			4,953				45,948
Cash and cash equivalents at beginning of period			126,966				51,019
Cash and cash equivalents at end of period		$	131,919			$	96,967
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES:
Cash paid for interest		$	32,481			$	32,640
Cash paid for income taxes		$	833			$	2,599

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

 

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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, 2010. The results of operations for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

The consolidated balance sheet at December 31, 2010 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.

Recent Accounting Pronouncements

In September 2011, the Financial Accounting Standards Board, or FASB, issued guidance that simplified how entities test for goodwill impairment. This guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform a two-step goodwill impairment test. This guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, and early adoption is permitted. We plan to early adopt this guidance for our annual goodwill impairment test that will be conducted as of November 30, 2011. This guidance is not expected to have a material effect on our financial condition or results of operations.

In June 2011, the FASB amended the rules relating to the presentation of comprehensive income. The amendments give the Company the option to present the total comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. The Company has not determined which method of presentation it will elect.

Management does not expect other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies to have a material impact on the Company’s financial position, results of operations or cash flows.

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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,
		2011				2010				2011				2010
Net income (loss)		$	(741	)		$	18,203			$	(16,802	)		$	33,801
Weighted average number of shares of common stock outstanding			26,919				26,446				26,839				26,365
Add: Net effect of dilutive stock options and unvested restricted stock (1)(2)			—				746				—				792
Adjusted weighted average number of shares of common stock outstanding (3)			26,919				27,192				26,839				27,157
Earnings (loss) per common share:
Basic		$	(0.03	)		$	0.69			$	(0.63	)		$	1.28
Diluted		$	(0.03	)		$	0.67			$	(0.63	)		$	1.24

 

(1)

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 representing the rights to acquire 401 and 402 shares of common stock for the three and nine months ended September 30, 2010, respectively, were excluded from the calculation of diluted earnings per share, because the effect was anti-dilutive after considering the exercise price of the options in comparison to the average market price, proceeds from exercise, taxes, and related unamortized compensation expense.

(2)	As of September 30, 2011 and 2010, the 1.625% convertible senior notes were not dilutive, as the average price of the Company’s stock was less than the effective conversion price of such notes, which is $62.59 per share.

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

3. Long-Term Debt

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

 

		September 30, 2011				December 31, 2010
6.125% senior notes due 2014, net of original issue discount of $231 and $279		$	299,769			$	299,721
8.000% senior notes due 2017, net of original issue discount of $5,760 and $6,305			244,240				243,695
1.625% convertible senior notes due 2026, net of original issue discount of $26,548 and $35,183 (1)			223,452				214,817
Revolving credit facility due 2013			—				—
			767,461				758,233
Less current maturities			—				—
		$	767,461			$	758,233

 

(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, have semi-annual cash interest payments of $9.2 million due and payable each June 1 and December 1. The Company’s 8.000% senior notes due 2017, or 2017 senior notes, have semi-annual cash interest payments of

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

$10.0 million due and payable each March 1 and September 1. The Company’s 1.625% convertible senior notes due 2026, or convertible senior notes, have semi-annual cash interest payments of $2.0 million due May 15 and November 15, declining to 1.375%, or $1.7 million semi-annually, beginning on November 15, 2013. Subject to certain conversion and redemption features of the convertible senior notes, holders of such notes may require the Company to purchase all or a portion of their notes on each of November 15, 2013, November 15, 2016 and November 15, 2021.

On November 2, 2011, the Company amended and restated its revolving credit facility, which increased its borrowing base to $300.0 million and included an accordion feature that allows for the potential expansion of the facility up to an aggregate of $500.0 million. The key changes to the Company’s revolving credit facility were as follows:

 

•

The amended facility extends the maturity from March 2013 to November 2016, unless the Company’s 6.125% senior notes remain outstanding on June 1, 2014, in which case the facility would mature on such date.

 

•

The minimum interest coverage ratio will be 2.00 to 1.00 for the quarters ending December 31, 2011 to September 30, 2012, 2.50 to 1.00 for the quarters ending December 31, 2012 and March 31, 2013 and 3.00 to 1.00 for the quarters ending June 30, 2013 and thereafter.

 

•

The annual interest rate under the amended facility will be reduced by an amount ranging from 50 basis points to 100 basis points as determined by a leverage ratio pricing grid, as defined.

 

•

The maximum total debt to capitalization ratio, as defined, will be replaced by a maximum total funded net debt to EBITDA ratio, as defined, of 4.00 beginning with the quarter ending December 31, 2012.

 

•

The Company is increasing the vessels pledged as collateral from 19 to 23 new generation OSVs commensurate with the higher borrowing base.

 

•

If the Company’s 1.625% convertible notes remain outstanding on April 30, 2013, the Company is required to maintain, as of the end of such calendar month and each calendar month-end thereafter, available liquidity, as defined, of $350 million until the refinancing of the 1.625% convertible notes to a date that is 91 days beyond the scheduled maturity of the facility or the redemption of the 1.625% convertible notes, provided that such redemption complies with the other provisions of the facility.

 

•

The Company is permitted to repay its 1.625% convertible notes and its 6.125% senior notes, provided that the Company has available liquidity, as defined, of $100 million on a pro forma basis and can demonstrate to the agent under the facility that its business plan is fully funded for the next four fiscal quarters, provided, however, that in the event that the Company seeks to repay the 6.125% senior notes prior to repaying the 1.625% convertible notes, it must have available liquidity of $350 million on a pro forma basis.

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Other than these key changes, all other definitions and substantive terms in the Company’s credit agreement governing its revolving credit facility were unchanged from the March 2011 amendment and remain in effect through the remaining life of the facility.

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

As of September 30, 2011, there were no amounts drawn under the Company’s revolving credit facility and $0.9 million posted as a letter of credit. As of September 30, 2011, the Company was in compliance with all financial covenants required by its revolving credit facility and the full amount of the undrawn borrowing base under the facility was available to the Company for all uses of proceeds, including working capital, if necessary.

The Company estimates the fair value of its 2014 senior notes, its 2017 senior notes and its convertible senior notes by 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 $800.0 million, $767.5 million and $780.7 million, respectively, as of September 30, 2011.

Capitalized Interest

During the three and nine months ended September 30, 2010, the Company capitalized approximately $0.3 million and $3.7 million of interest costs related to the construction or conversion 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, 2011, the Company granted stock options, time-based restricted stock and performance-based restricted stock. Time-based restricted stock was granted to directors, executive officers and certain shore-side employees of the Company.

Stock options and performance-based restricted stock were granted to executive officers of the Company. The shares to be received under the performance-based restricted stock are

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

calculated based on the Company’s stock price performance relative to a peer group, as defined by the restricted stock agreements governing such awards. Performance is measured by the change in the Company’s stock price measured against the peer group during a measurement period. The actual number of shares that could be received by the award recipients can range from 0% to 200% of the Company’s base share awards depending on the Company’s performance ranking relative to the peer group. During the nine months ended September 30, 2011, the Company granted stock options, time-based restricted stock and performance-based restricted stock representing 490,587 shares, in the aggregate.

Compensation expense related to performance-based restricted stock is recognized over the service period, which is from three to five years. The fair value of the Company’s performance-based restricted stock, which is determined using a Monte Carlo simulation, is applied to the total shares that are expected to fully vest and is amortized over the vesting period based on the Company’s internal performance measured against pre-determined criteria or relative performance compared to peers, as applicable. The compensation expense related to time-based restricted stock, which is amortized over a vesting period from one to three years, 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. Compensation expense for stock options is determined using the Black-Scholes pricing model and is amortized over the vesting period of three years. In addition to the restricted stock granted in 2011, the Company granted performance-based and time-based restricted stock in 2008, 2009 and 2010. The performance-based restricted stock grants issued in 2008 were eligible for vesting in February 2011. Based on the Company’s performance, 100% of such restricted stock did not meet the performance criteria and were cancelled. During the nine months ended September 30, 2011, the Company issued 342,484 shares, in the aggregate, of stock under its existing share-based compensation programs.

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Income before taxes		$	1,728			$	2,223			$	5,654			$	6,835
Net income		$	280			$	1,394			$	3,777			$	4,299
Earnings per common share:
Basic		$	0.01			$	0.05			$	0.14			$	0.16
Diluted		$	0.01			$	0.05			$	0.14			$	0.16

In addition, the Company capitalized approximately $0.1 million and $0.4 million of stock-based compensation expense that related directly to newbuild construction programs and general corporate capital projects for the three and nine months ended September 30, 2010, respectively. No such stock-based compensation expense was capitalized during the three and nine months ended September 30, 2011.

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

5. Contingencies

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

The Company insures against losses relating to its vessels, pollution and third party liabilities, including claims by employees under Section 33 of the Merchant Marine Act of 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 2010 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 historically revisions to such estimates have not been material, changes in estimates of the potential liability could materially impact the Company’s results of operations, financial position or cash flows.

6. Segment Information

The Company provides marine transportation and logistics services through two business segments. The Company primarily operates new generation offshore supply vessels, or OSVs, and multi-purpose support vessels, or MPSVs, in the U.S. Gulf of Mexico, or GoM, other U.S. coastlines, Latin America and the Middle East and operates a shore-base facility in Port Fourchon, Louisiana through its Upstream segment. The OSVs, MPSVs and the shore-base facility principally support complex exploration and production projects by transporting cargo to offshore drilling rigs and production facilities and provide support for oilfield and non-oilfield specialty services, including military applications. The Downstream segment primarily operates ocean-going tugs and tank barges in the northeastern United States, GoM, 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.

 

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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, 2011 and 2010, 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,
		2011				2010				2011				2010
Operating revenues:
Upstream
Domestic (1)		$	51,057			$	91,929			$	118,815			$	241,358
Foreign (2)			40,896				20,067				102,443				47,734
			91,953				111,996				221,258				289,092
Downstream
Domestic			11,628				12,351				31,932				31,979
Foreign (2)(3)			2,246				1,004				5,721				2,411
			13,874				13,355				37,653				34,390
Total		$	105,827			$	125,351			$	258,911			$	323,482
Operating expenses:
Upstream		$	53,733			$	46,249			$	127,871			$	122,973
Downstream			9,011				6,992				24,909				23,107
Total		$	62,744			$	53,241			$	152,780			$	146,080
Depreciation:
Upstream		$	13,086			$	12,897			$	39,376			$	36,883
Downstream			2,144				2,115				6,383				6,392
Total		$	15,230			$	15,012			$	45,759			$	43,275
Amortization:
Upstream		$	3,953			$	3,711			$	11,434			$	10,871
Downstream			1,202				1,064				3,886				2,800
Total		$	5,155			$	4,775			$	15,320			$	13,671
General and administrative expenses:
Upstream		$	8,364			$	9,059			$	24,991			$	26,189
Downstream			681				674				2,415				2,105
Total		$	9,045			$	9,733			$	27,406			$	28,294
Gain on sale of assets:
Upstream		$	976			$	—			$	976			$	615
Downstream			—				725				559				729
Total		$	976			$	725			$	1,535			$	1,344
Operating income:
Upstream		$	13,793			$	40,080			$	18,562			$	92,791
Downstream			836				3,235				619				715
Total		$	14,629			$	43,315			$	19,181			$	93,506
Capital expenditures:
Upstream		$	10,008			$	5,560			$	21,601			$	56,441
Downstream			530				119				1,377				1,210
Corporate			538				153				990				1,497
Total		$	11,076			$	5,832			$	23,968			$	59,148

 

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HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

		As of September 30, 2011				As of December 31, 2010
Identifiable Assets:
Upstream		$	1,650,992			$	1,647,561
Downstream			204,178				205,782
Corporate			21,836				25,082
Total		$	1,877,006			$	1,878,425
Long-Lived Assets:
Upstream
Domestic		$	979,391			$	1,203,136
Foreign (2)			411,954				211,488
			1,391,345				1,414,624
Downstream
Domestic			147,860				166,673
Foreign (2)(3)			28,661				18,297
			176,521				184,970
Corporate			5,826				6,527
Total		$	1,573,692			$	1,606,121

 

(1)	During the nine months ended September 30, 2010, the Company’s Upstream segment recorded $10.5 million of non-recurring revenues for one of its specialty service vessels unrelated to the oil spill relief efforts in the U.S. Gulf of Mexico.

(2)

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, 2011 and December 31, 2010, respectively. As of September 30, 2011, the majority of long-lived Upstream assets in foreign locations were operating in Latin America.

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

 

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read together with our unaudited consolidated financial statements and notes to unaudited consolidated financial statements in this Quarterly Report on Form 10-Q and our audited financial statements and notes thereto included in our Annual Report on Form 10-K as of and for the year ended December 31, 2010. 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 ODS-Petrodata, Inc. These organizations are not affiliated with us and are not aware of and have not consented to being named in this Quarterly Report on Form 10-Q. We believe this information is reliable. In addition, in many cases we have made statements in this Quarterly Report on Form 10-Q regarding our industry and our position in the industry based on our experience in the industry and our own evaluation of market conditions.

General

Our Upstream Segment

The OSV market is expanding globally. Generally, offshore exploration and production activities are increasingly focused on deep wells (as defined by total well depth rather than water depth), whether on the Outer Continental Shelf or in the deepwater or ultra-deepwater. These types of wells require high-specification equipment and have resulted in an on-going newbuild cycle for drilling rigs and for OSVs. As a result of the projected deepwater drilling activity levels worldwide, there were 73 floating rigs under construction or on order on November 1, 2011 and, as of that date, there were options outstanding to build 27 additional floating rigs. In addition, on that date, there were 77 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 26 additional high-spec jack-up rigs. Each drilling rig working on deep-well projects typically requires more than one OSV to service it, and the number of OSVs required is dependent on many factors, including the type of activity being undertaken and the location of the rig. For example, based on the historical data for the number of floating rigs and OSVs working, we believe that two to four OSVs per rig are required in the GoM and even more OSVs are necessary per rig in Brazil where greater logistical challenges result in longer vessel turnaround times to service drill sites. Typically, during the initial drilling stage, more OSVs are required to supply drilling mud, drill pipe and other materials than at later stages of the drilling cycle. In addition, generally more OSVs are required the farther a drilling rig is located from shore. Under normal weather conditions, the transit time to deepwater drilling rigs in the GoM and Brazil can typically range from six to 24 hours for a new generation vessel. Moreover, in Brazil, they measure transit time for a new generation vessel to some of the newer, more logistically remote deepwater

 

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drilling rig locations 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 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 Deepwater Horizon incident, which occurred at the Macondo well in April 2010, and the Obama Administration’s subsequent domestic drilling moratorium and de facto regulatory moratorium contributed to a reduction in drilling activity in the GoM. However, 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. Despite the drilling moratorium and the subsequent period of permitting uncertainty, according to ODS Petrodata, the number of floating rigs available in the GoM region is currently 33 and remains relatively unchanged from the pre-Macondo level of 34 rigs, because the 10 floaters that left the region have since been replaced by nine similar or more advanced rigs. Since early 2011, there has been a gradual improvement in the number of incremental deepwater well permits issued per month, which has increased from two in January 2011 to a high of 17 in October 2011. A significant backlog of permit applications and requests for approval of drilling plans indicate a strong desire by our customers to continue exploration and production activities in the GoM, notwithstanding the slowdown in the pace of plan and permit approvals. Of the 33 rigs available in the GoM, the number of floating rigs actively drilling has also increased to 20 on November 1, 2011 from six a year ago. 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 believe that floating rig activity should return to pre-2010 levels by the end of 2013 with approximately 30 floating rigs expected to be drilling in the GoM, up approximately 50% from the 20 rigs drilling as of November 1, 2011. Floating rig growth in the GoM is projected to be driven by demand in the deepwater and ultra-deepwater, primarily in water depths greater than 3,000 feet.

Despite the continued interest in the hydrocarbon reserves of the GoM, the Company and other OSV operators experienced reduced utilization and dayrates over the post-Macondo period from April 2010 until late in the third quarter of 2011. In response, we and our competitors stacked vessels, furloughed or layed-off employees, and moved vessels to new markets. According to ODS Petrodata, 48 new generation Jones Act qualified vessels, or approximately 28% of the active pre-Macondo fleet, have left the GoM since Macondo and are working under term contracts in international markets. Some of these vessels have been re-flagged as foreign and are not legally entitled to return to U.S. coastwise trade under the Jones Act. With the recent increase in permitting and drilling rig activity in the GoM, we believe that we are in a strong competitive position to benefit from the recovery currently underway. We have 15 active new generation OSVs and four MPSVs currently operating in the GoM, the most operating leverage to improving market conditions in the GoM of any of our domestic public OSV peers.

 

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Brazil. Brazil is experiencing a dramatic increase in activity related to its large pre-salt oilfield basins. This increase in activity is driven primarily by 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 vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Brazilian operators plan to add 15 new floating rigs by the end of 2012. Since the beginning of 2010, we have increased our presence in Brazil from zero to 14 vessels, including 12 working under long-term contracts for Petrobras and two working on spot charters for another operator. We continue to actively bid additional vessels into Brazil. We recently acquired a Brazilian navigation company (EBN) and have increased our physical presence there with additional shoreside support personnel in Macae and Rio de Janeiro.

Mexico. The primary customer in the Mexican market is the state-owned oil company, Petróleos Mexicanos, or PEMEX. The Cantarell field, which according to the EIA is PEMEX’s largest offshore oil field, 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, 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 exploitation of 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. Currently, there are four floating rigs and 29 jack-up rigs drilling offshore Mexico, and PEMEX has announced plans to add another floating rig and five more high-spec jack-up rigs. 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. We established our own Mexican navigation company (Naviera) in 2008 and have increased our physical presence there with additional shore-side support personnel in Ciudad del Carmen and Dos Bocas.

Due to a limited supply of high-spec U.S.-flagged vessels in the GoM and the recent increase in the pace and predictability of permitting, we have recently seen improvement in dayrates and utilization for our vessels commencing late in the third quarter of 2011. Some customers are now observing that, although still historically slow, the pace of drilling plan and permit activity is more repeatable and predictable, which enables them to better plan future projects in the GoM. Leading-edge spot market OSV dayrates for our 240 class equipment has recently been in the $28,000 to $32,000 range, which is roughly double the levels experienced in early 2011. Whether these rates can be sustained will depend on the future pace of permitting in the GoM. We believe that our 240 class vessels are a good indicator of the general strength of the market for high-spec vessels because they represent the largest and most popular class of new generation OSVs in the market and thus, currently have the most transaction volume. We have reactivated 10 new generation OSVs since February 2011, six of which have begun work in the GoM and four of which were mobilized to Latin America. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs increased about $1,800, or 13%, from the second quarter of 2011 to $15,772 for the

 

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third quarter of 2011. During the third quarter of 2011, we had an average stacked new generation OSV fleet of 6.3 vessels compared to 10.9 vessels in the second quarter of 2011 and 5.1 vessels in the same period in 2010. With the re-activation of the 220 class HOS Explorer in October 2011, we now have only five DP-1 new generation OSVs stacked, which is the same number of stacked vessels that we had immediately prior to Macondo and down from a high of 15 stacked vessels during the first quarter of 2011. Given the recent improvement in market conditions, our five stacked vessels are expected to be re-activated for service in the GoM by the end of the first quarter of 2012, after re-crewing and any required drydocking activities. With the re-activation of stacked vessels, our crewing requirements increased throughout the third quarter of 2011. We have re-hired some of our previously laid-off or furloughed crewmembers as well as hired new employees. As the global applicant pool of qualified mariners remains tight, we expect to encounter stiff competition for crewmembers, which could negatively impact our operating costs.

We currently have nearly 73% of our new generation OSV vessel-days contracted for the remainder of 2011, with 34 vessels contracted through at least the end of the year. Our forward OSV contract coverage for 2012 and 2013 currently stands at 46% and 34%, respectively. Our MPSV contract coverage for the remainder of 2011 has also strengthened as a result of the improving market conditions in the GoM. In July, we were awarded a three-year charter with an international oilfield service company for our 430 class MPSV, the HOS Iron Horse, which began during September 2011. In addition, our 370 class MPSV, the HOS Centerline, recently commenced a long-term contract with a major oil and gas company in the GoM. On the strength of the these long-term contracts and recent spot market activity, MPSV utilization increased from 12% for the second quarter of 2011 to 76% for the third quarter of 2011, and contract coverage for the fourth quarter of 2011 is currently 78%.

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 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. These factors adversely affected our operating results during the first nine months of 2011.

As of September 30, 2011, our 45 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:

 

Operating Areas
Domestic
GoM			17
Other U.S. coastlines (1)			5
			22
Foreign
Brazil			14
Mexico			9
Other Latin America			2
Middle East			2
			27
Total Upstream Vessels (2)			49

 

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

(2)	Excluded from this table are six of our new generation OSVs and one conventional OSV that were stacked as of September 30, 2011. Subsequently, we have unstacked one of our new generation OSVs to work in the GoM, and as a result, we now have 50 Upstream vessels in service.

Our Downstream Segment

As of September 30, 2011, our Downstream fleet was comprised of nine double-hulled tank barges and 15 ocean-going tugs, six of which are older, lower-horsepower tugs that were stacked. The prolonged weakness in the overall economy, which has impacted our Downstream segment since 2008, continues to adversely impact demand for Downstream equipment. Although Downstream results for the third quarter improved from the prior year, recent dayrate trends are well below the Downstream dayrates that existed from 2006 to 2008. We anticipate that the current market conditions for our Downstream vessels will continue throughout 2011. 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, 2010.

Impairment Assessment

Our operating results for the quarter ended September 30, 2011 were consistent with or exceeded our expectations given the pace of drilling permits issued in the GoM and our mobilization of Upstream vessels to foreign markets. No new triggering events occurred during the first nine months of 2011. We again considered whether the curtailed level of drilling activity in the GoM represented an indicator of impairment for any of our asset groups and concluded it did not. Some factors that the Company considered were the anticipated temporary nature of the reduced drilling activity in the GoM, projected operating results over the remaining useful lives of our assets, the significant remaining operating useful lives of such assets and the mobility and flexibility of our vessels. We will continue to monitor market conditions and other trends that could be considered potential triggering events.

 

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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. Excluded from the operating data below are the results of operations for our MPSVs, conventional vessel, our shore-base facility and vessel management services.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Upstream:
New Generation Offshore Supply Vessels:
Average number of new generation OSVs (1)			51.0				50.3				51.0				49.5
Average number of active new generation OSVs (2)			44.7				45.2				40.5				42.6
Average new generation OSV fleet capacity (deadweight)			128,190				126,323				128,190				123,890
Average new generation vessel capacity (deadweight)			2,514				2,510				2,514				2,504
Average new generation OSV utilization rate (3)			75.3	%			75.7	%			67.5	%			73.5	%
Effective new generation OSV utilization rate (4)			85.9	%			84.2	%			84.9	%			85.3	%
Average new generation OSV dayrate (5)		$	20,945			$	21,628			$	20,812			$	21,833
Effective dayrate (6)		$	15,772			$	16,372			$	14,048			$	16,047
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)			92.0	%			86.9	%			88.3	%			78.8	%
Average dayrate (8)		$	18,222			$	18,615			$	17,351			$	17,765
Effective dayrate (6)		$	16,764			$	16,176			$	15,321			$	13,999

 

(1)

We owned 51 new generation OSVs as of September 30, 2011. Our average number of new generation OSVs for the three and nine months ended September 30, 2010 reflect the deliveries of several vessels under our fourth OSV newbuild program. Excluded from this data are four multi-purpose support vessels that we own and were placed in service under our MPSV program on various dates from October 2008 to March 2010. Also excluded from this data is one stacked conventional OSV that we consider to be a non-core asset.

(2)	Active new generation OSVs represent vessels that are fully crewed and 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)	The operating data presented above reflects only the results from our nine double-hulled tank barges. Excluded from this data are 15 ocean-going tugs owned by the Company, six of which are currently stacked.

(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.

 

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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, 2011 and 2010, respectively (in thousands).

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Components of EBITDA:
Net income (loss)		$	(741	)		$	18,203			$	(16,802	)		$	33,801
Interest expense, net
Debt obligations			15,062				14,422				44,976				40,353
Interest income			(156	)			(104	)			(575	)			(353	)
Total interest, net			14,906				14,318				44,401				40,000
Income tax expense (benefit)			445				10,816				(8,360	)			19,962
Depreciation			15,230				15,012				45,759				43,275
Amortization			5,155				4,775				15,320				13,671
EBITDA		$	34,995			$	63,124			$	80,318			$	150,709

 

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The following table reconciles EBITDA to cash flows provided by operating activities for the three and nine months ended September 30, 2011 and 2010, respectively (in thousands).

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
EBITDA Reconciliation to GAAP:
EBITDA		$	34,995			$	63,124			$	80,318			$	150,709
Cash paid for deferred drydocking charges			(6,098	)			(3,553	)			(16,478	)			(15,661	)
Cash paid for interest			(10,633	)			(10,323	)			(32,481	)			(32,639	)
Cash paid for taxes			(334	)			(245	)			(833	)			(2,599	)
Changes in working capital			(21,499	)			(929	)			(18,973	)			(3,690	)
Stock-based compensation expense			1,728				2,223				5,654				6,835
Changes in other, net			(740	)			(666	)			(31	)			(1,436	)
Net cash flows provided by operating activities		$	(2,581	)		$	49,631			$	17,176			$	101,519

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, 2011 and 2010, respectively (in thousands).

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

 

			00000				00000				00000				00000
		Three Months Ended September 30,								Nine Months Ended  September  30,
		2011				2010				2011				2010
Stock-based compensation expense		$	1,728			$	2,223			$	5,654			$	6,835
Interest income			156				104				575				353

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

 

•

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

 

•

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

 

•

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

 

•

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

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

 

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Summarized financial information concerning our reportable segments for the three months ended September 30, 2011 and 2010, respectively, is shown below in the following table (in thousands, except percentage changes):

 

		Three Months Ended September 30,								Increase (Decrease)
		2011				2010				$ Change				% Change
Revenues:
Upstream
Domestic		$	51,057			$	91,929			$	(40,872	)			(44.5	)%
Foreign			40,896				20,067				20,829				>100.0
			91,953				111,996				(20,043	)			(17.9	)
Downstream
Domestic			11,628				12,351				(723	)			(5.9	)
Foreign (1)			2,246				1,004				1,242				>100.0
			13,874				13,355				519				3.9
		$	105,827			$	125,351			$	(19,524	)			(15.6	)%
Operating expenses:
Upstream		$	53,733			$	46,249			$	7,484				16.2	%
Downstream			9,011				6,992				2,019				28.9
		$	62,744			$	53,241			$	9,503				17.8	%
Depreciation and amortization:
Upstream		$	17,039			$	16,608			$	431				2.6	%
Downstream			3,346				3,179				167				5.3
		$	20,385			$	19,787			$	598				3.0	%
General and administrative expenses:
Upstream		$	8,364			$	9,059			$	(695	)			(7.7	)%
Downstream			681				674				7				1.0
		$	9,045			$	9,733			$	(688	)			(7.1	)%
Gain on sale of assets:
Upstream		$	976			$	—			$	976				100.0	%
Downstream			—				725				(725	)			(100.0	)
		$	976			$	725			$	251				34.6	%
Operating income:
Upstream		$	13,793			$	40,080			$	(26,287	)			(65.6	)%
Downstream			836				3,235				(2,399	)			(74.2	)
		$	14,629			$	43,315			$	(28,686	)			(66.2	)%
Interest expense		$	15,062			$	14,422			$	640				4.4	%
Interest income		$	156			$	104			$	52				50.0	%
Income tax expense		$	445			$	10,816			$	(10,371	)			(95.9	)%
Net income (loss)		$	(741	)		$	18,203			$	(18,944	)			>(100.0	)%

 

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

 

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Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Revenues. Revenues for the three months ended September 30, 2011 decreased by $19.5 million, or 15.6%, to $105.8 million compared to the same period in 2010 primarily due to the lack of drilling activity in the GoM. In addition, oil spill response activities during the prior-year quarter favorably impacted each of our business segments. Our weighted-average active operating fleet for the three months ended September 30, 2011 was 67 vessels, which was in-line with the same period in 2010.

Revenues from our Upstream segment decreased by $20.0 million, or 17.9%, to $92.0 million for the three months ended September 30, 2011 compared to $112.0 million for the same period in 2010. Our lower Upstream revenues primarily resulted from regulatory driven declines in drilling permit activity. These market conditions led to decline in demand for our MPSVs and, to a lesser extent, lower revenue earned from new generation OSVs that were in-service during each of the quarters ended September 30, 2011 and 2010. These lower revenues were partially offset by incremental revenues earned by vessels operating in Latin America. Our new generation OSV average dayrates were $20,945 for the third quarter of 2011 compared to $21,628 for the same period in 2010, a decrease of $683, or 3.2%. Our new generation OSV utilization was 75.3% for the third quarter of 2011 compared to 75.7% for the same period in 2010. Our new generation OSV utilization for the third quarter of 2010 was favorably impacted by vessels participating in the oil spill relief efforts that concluded in fourth quarter 2010. Our vessel count included an average of 6.3 stacked vessels during the three months ended September 30, 2011 compared to an average of 5.1 stacked vessels during the prior-year period. Domestic revenues for our Upstream segment decreased $40.9 million during the three months ended September 30, 2011 due to reduced drilling activity in the GoM. Foreign revenues for our Upstream segment increased $20.8 million, or 103.5%, primarily due to an average of 14 additional vessels deployed to Latin America since September 30, 2010. Foreign revenues comprised 44.5% of our total Upstream revenues compared to 17.9% for the year-ago quarter. This trend of higher foreign revenues is expected to continue throughout the fourth quarter of 2011, particularly in recognition of the mobilization of eight vessels to Latin America on various dates during 2011.

Revenues from our Downstream segment increased by $0.5 million, or 3.9%, to $13.9 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. This revenue increase was largely due to improved market conditions in the Northeast and in the GoM along with fewer days out-of-service for regulatory drydocking in the three months ended September 30, 2011 compared to the prior-year quarter. Our double-hulled tank barge average dayrates were $18,222 for the three months ended September 30, 2011, a decrease of $393, or 2.1%, from $18,615 for the same period in 2010. Tank barge dayrates for the prior-year quarter were favorably impacted by well-test services performed for an Upstream customer. Excluding the impact of this well-test project, dayrates would have been $16,430, for the prior-year quarter. Our double-hulled tank barge utilization was 92.0% for the third quarter of 2011 compared to 86.9% for the third quarter of 2010. Effective, or utilization-adjusted, dayates for our double-hulled tank barges were $16,764 for the three months ended September 30, 2011, which was $2,486, or 17.4%, higher than the prior-year quarter effective dayrates, as adjusted to exclude the 2010 well-test project. Foreign revenues for our Downstream segment increased $1.2 million, or 120.0% compared to the prior-year quarter due to an additional vessel deployed to Puerto Rico during the three months ended September 30, 2011.

 

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Operating expenses. Operating expenses for the three months ended September 30, 2011 increased by $9.5 million, or 17.8%, to $62.7 million. This increase was primarily associated with approximately $6.5 million of incremental costs to mobilize eight vessels to Latin America.

Operating expenses for our Upstream segment were $53.7 million, a increase of $7.5 million, or 16.2%, for the third quarter of 2011 compared to $46.2 million for the same period in 2010. Operating expenses for our Upstream segment were driven higher by increased operating expenses for our vessels working in Latin America and costs incurred to pre-position additional vessels that mobilized to Latin America during the second and third quarters of 2011.

Operating expenses for our Downstream segment were $9.0 million, an increase of $2.0 million, or 28.9%, for the three months ended September 30, 2011 compared to $7.0 million for the same period in 2010. The increase in operating expenses is largely the result of having a greater mix of Downstream vessels operating under COA agreements instead of time charters. Under COA arrangements, the vessel owner typically bears the cost of fuel, which is typically covered through higher dayrates. Our contracts during the third quarter of 2010 were primarily comprised of time charters in connection with oil spill response efforts. Under time charter arrangements, the charterer is usually responsible for fuel costs.

Depreciation and Amortization. Depreciation and amortization was $0.6 million higher for the three months ended September 30, 2011 compared to the same period in 2010 primarily due to incremental depreciation and amortization expense related to vessels placed in service under our fourth OSV newbuild program and our MPSV program. Depreciation and amortization expense is expected to increase further when these and any other recently acquired and newly constructed vessels undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $9.0 million, or 8.5% of revenues, decreased by $0.7 million during the three months ended September 30, 2011 compared to the three months ended September 30, 2010. This decrease in G&A expenses was primarily attributable to lower shoreside compensation expenses. Our general and administrative expenses are expected to remain in the approximate annual range of $36 million to $38 million for the year ending December 31, 2011.

Gain on Sale of Assets. 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). During the third quarter of 2010, we sold an older, lower-horsepower tug, for cash proceeds of $1.3 million, which resulted in a pre-tax gain of approximately $0.7 million ($0.4 million after tax or $0.01 per diluted share).

Operating Income. Operating income decreased by $28.7 million to $14.6 million during the three months ended September 30, 2011 compared to the same period in 2010 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 15.0% for the three months ended September 30, 2011 compared to 35.8% for the same period in 2010. Excluding roughly $6.5 million of incremental operating costs as a

 

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result of mobilizing vessels to Brazil, our operating income as a percentage of revenues for our Upstream segment would have been 22.1% for the third quarter of 2011. Operating income as a percentage of revenues for our Downstream segment was 5.8% for the three months ended September 30, 2011 compared to 23.9% for the same period in 2010.

Interest Expense. Interest expense increased $0.6 million during the three months ended September 30, 2011 compared to the same period in 2010. Lower capitalized interest from having fewer vessels under construction or conversion was the primary reason that our interest expense increased from the prior-year quarter. During the third quarter of 2011, we did not capitalize any construction period interest compared to capitalized interest of $0.3 million, or roughly 2% of our total interest costs, for the year-ago quarter.

Interest Income. Interest income increased $0.1 million during the three months ended September 30, 2011 compared to the same period in 2010. Our average cash balance increased to $136.1 million for the three months ended September 30, 2011 compared to $72.8 million for the same period in 2010. The average interest rate earned on our invested cash balances during the three months ended September 30, 2011 was approximately 0.5% compared to 0.6% for the same period in 2010.

Income Tax Expense. 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 decreased year-over-year by $18.9 million for a reported net loss of $0.7 million for the three months ended September 30, 2011. The net loss incurred for the third quarter of 2011 was primarily due to the decrease in operating income discussed above and a $0.6 million pre-tax increase in net interest expense.

 

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Summarized financial information concerning our reportable segments for the nine months ended September 30, 2011 and 2010, respectively, is shown below in the following table (in thousands, except percentage changes):

 

		Nine Months Ended September 30,								Increase (Decrease)
		2011				2010				$ Change				% Change
Revenues:
Upstream
Domestic		$	118,815			$	241,358			$	(122,543	)			(50.8	)%
Foreign			102,443				47,734				54,709				>100.0
			221,258				289,092				(67,834	)			(23.5	)
Downstream
Domestic			31,932				31,979				(47	)			(0.1	)
Foreign (1)			5,721				2,411				3,310				>100.0
			37,653				34,390				3,263				9.5
		$	258,911			$	323,482			$	(64,571	)			(20.0	)%
Operating expenses:
Upstream		$	127,871			$	122,973			$	4,898				4.0	%
Downstream			24,909				23,107				1,802				7.8
		$	152,780			$	146,080			$	6,700				4.6	%
Depreciation and amortization:
Upstream		$	50,810			$	47,754			$	3,056				6.4	%
Downstream			10,269				9,192				1,077				11.7
		$	61,079			$	56,946			$	4,133				7.3	%
General and administrative expenses:
Upstream		$	24,991			$	26,189			$	(1,198	)			(4.6	)%
Downstream			2,415				2,105				310				14.7
		$	27,406			$	28,294			$	(888	)			(3.1	)%
Gain on sale of assets:
Upstream		$	976			$	615			$	361				58.7	%
Downstream			559				729				(170	)			(23.3	)
		$	1,535			$	1,344			$	191				14.2	%
Operating income:
Upstream		$	18,562			$	92,791			$	(74,229	)			(80.0	)%
Downstream			619				715				(96	)			(13.4	)
		$	19,181			$	93,506			$	(74,325	)			(79.5	)%
Interest expense		$	44,976			$	40,353			$	4,623				11.5	%
Interest income		$	575			$	353			$	222				62.9	%
Income tax expense (benefit)		$	(8,360	)		$	19,962			$	(28,322	)			>(100.0	)%
Net income (loss)		$	(16,802	)		$	33,801			$	(50,603	)			>(100.0	)%

 

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

 

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Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Revenues. Revenues for the nine months ended September 30, 2011 decreased by $64.6 million, or 20.0%, to $258.9 million compared to the same period in 2010 primarily due to substantially reduced drilling activity in the GoM, which led to our decision to stack certain new generation OSVs. Our weighted-average active operating fleet for the nine months ended September 30, 2011 was approximately 63 vessels compared to 65 vessels for the same period in 2010.

Revenues from our Upstream segment decreased by $67.8 million, or 23.5%, to $221.3 million for the nine months ended September 30, 2011 compared to $289.1 million for the same period in 2010. These lower revenues primarily resulted from a decline in activity from our MPSVs, lower revenue from new generation OSVs that were in-service during each of the periods ended September 30, 2011 and 2010 and, to a lesser extent, the stacking of certain new generation OSVs in response to regulatory-driven demand weakness in the GoM. These lower revenues were partially offset by incremental revenues related to vessels operating in Latin America. Our new generation OSV average dayrates were $20,812 for the first nine months of 2011 compared to $21,833 for the same period in 2010, a decrease of $1,021, or 4.7%. Our new generation OSV dayrates for the first nine months of 2010 were favorably impacted by non-recurring revenues for one of our specialty service vessels unrelated to the oil spill relief efforts in the GoM. Excluding these revenues, our 2010 new generation OSV dayrates would have been $19,171, or 8.6% lower than the first nine months ended September 30, 2011. Our new generation OSV utilization was 67.5% for the first nine months of 2011 compared to 73.5% for the same period in 2010. The decrease in utilization was largely due to having an average of 10.5 vessels stacked during the nine months ended September 30, 2011 compared to an average of 6.9 stacked vessels during the prior-year period. Domestic revenues for our Upstream segment decreased $122.5 million during the nine months ended September 30, 2011 due to reduced drilling activity in the GoM. Foreign revenues for our Upstream segment increased $54.7 million primarily due to an average of 11 additional vessels deployed to Latin America since September 30, 2010. Foreign revenues comprised 46.3% of our total Upstream revenues compared to 16.5% for the first nine months of 2010. This trend of higher foreign revenues is expected to continue throughout the fourth quarter of 2011, particularly in recognition of the eight vessels that were awarded contracts in Latin America commencing during 2011.

Revenues from our Downstream segment increased by $3.3 million, or 9.5%, to $37.7 million for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. This revenue increase was due to higher demand for our clean and dirty petroleum product barges in the Northeast during the first nine months of 2011 compared to the same period in 2010. Our double-hulled tank barge average dayrates were $17,351 for the nine months ended September 30, 2011, a decrease of $414, or 2.3%, from $17,765 for the same period in 2010. However, our double-hulled tank barge utilization was 88.3% for the first nine months of 2011 compared to 78.8% for the first nine months of 2010. Foreign revenues for our Downstream segment increased $3.3 million, or 137.5%, due to an additional vessel deployed to Puerto Rico during the nine months ended September 30, 2011 compared to the prior-year quarter.

 

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Operating expenses. Operating expenses for the nine months ended September 30, 2011 increased by $6.7 million, or 4.6%, to $152.8 million. This increase was primarily associated with higher costs for vessels operating in international regions partially offset by cost savings from stacking Upstream vessels during the first nine months of 2011.

Operating expenses for our Upstream segment were $127.9 million, a increase of $4.9 million, or 4.0%, for the nine months ended September 30, 2011 compared to $123.0 million for the same period in 2010. Operating expenses for our Upstream segment were driven higher by operating expenses for our vessels working in Latin America and costs incurred to pre-position additional vessels that mobilized for long-term contracts in Latin America, which commenced during the second half of 2011. This variance was partially offset by lower costs associated with a smaller active new generation OSV fleet. For the nine months ended September 30, 2011, we had an average active new generation OSV fleet of 40.5 vessels compared to 42.6 vessels for the same period in 2010.

Operating expenses for our Downstream segment were $24.9 million, a increase of $1.8 million, or 7.8%, for the nine months ended September 30, 2011 compared to $23.1 million for the same period in 2010. The increase in operating expenses for the Downstream segment is attributable to higher fuel expense resulting from a greater number of contracts of affreightment charters during the nine months ended September 30, 2011.

Depreciation and Amortization. Depreciation and amortization was $4.1 million higher for the nine months ended September 30, 2011 compared to the same period in 2010. This increase is primarily due to incremental depreciation expense related to vessels placed in service under our fourth OSV newbuild program and our MPSV program during 2010. In addition, amortization expense was higher during the first nine months of 2011 due to vessels undergoing their initial recertifications that have been placed in-service on various dates since 2008. Depreciation and amortization expense is expected to increase further as these and any other recently acquired and newly constructed vessels undergo their initial 30-month and 60-month recertifications.

General and Administrative Expense. General and administrative expenses of $27.4 million, or 10.6% of revenues, decreased by $0.9 million during the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. This decrease in G&A expenses were primarily the result of lower shoreside personnel expense. Our general and administrative expenses are expected to remain in the approximate annual range of $36 million to $38 million for the year ending December 31, 2011.

Gain on Sale of Assets. 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). During the first nine months of 2010, we sold one conventional OSV and one older, lower-horsepower tug for aggregate net cash proceeds of $2.6 million, which resulted in an aggregate gain of approximately $1.2 million ($0.8 million after tax and $0.03 per diluted share).

Operating Income. Operating income decreased by $74.3 million to $19.2 million during the nine months ended September 30, 2011 compared to the same period in 2010 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream

 

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segment was 8.4% for the nine months ended September 30, 2011 compared to 32.1% for the same period in 2010. Excluding roughly $7.7 million of incremental operating costs as a result of mobilizing vessels to Brazil, our operating income as a percentage of revenues for our Upstream segment would have been 11.9% for the nine months ended September 30, 2011. Operating income as a percentage of revenues for our Downstream segment was 1.6% for the nine months ended September 30, 2011 compared to 2.0% for the same period in 2010.

Interest Expense. Interest expense increased $4.6 million during the nine months ended September 30, 2011 compared to the same period in 2010. Lower capitalized interest from having fewer vessels under construction or conversion was the primary reason that our interest expense increased from the same period in 2010. During the first nine months of 2011, we did not capitalize any construction period interest compared to capitalized interest of $3.7 million, or roughly 6% of our total interest costs, for the year-ago period.

Interest Income. Interest income increased $0.2 million during the nine months ended September 30, 2011 compared to the same period in 2010. Our average cash balance increased to $139.0 million for the nine months ended September 30, 2011 compared to $60.4 million for the same period in 2010. The average interest rate earned on our invested cash balances during the nine months ended September 30, 2011 was approximately 0.5% compared to 0.7% for the same period in 2010.

Income Tax Expense (Benefit). Our effective tax rate was 33.2% and 37.1% for the nine months ended September 30, 2011 and 2010, respectively. The benefit rate for the first nine months of 2011 is less than the tax rate for the first nine months of 2010 due to the larger effect of our permanent book tax differences on the relatively smaller pre-tax book income (loss) for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. Our income tax rate is different 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 decreased year-over-year by $50.6 million for a reported net loss of $16.8 million for the nine months ended September 30, 2011. The net loss incurred for the first nine months of 2011 was primarily due to a decrease in operating income discussed above and a $4.4 million pre-tax increase in net interest expense.

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, 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 2011. While we have postponed required drydockings for some of our stacked vessels, we will be required to conduct any deferred drydockings prior to such vessels returning to service. The drydocking funds required to recertify currently stacked vessels will be dependent upon vessel class, certification requirements and the timing and sustainability of any market recovery.

 

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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 recently amended revolving credit facility will be more than sufficient to operate the Company, while we reposition vessels to alternative markets.

As of September 30, 2011, we had total cash and cash equivalents of $131.9 million. On November 2, 2011, we amended and restated the credit agreement governing our revolving credit facility to extend the maturity date, increase the borrowing base, , lower the interest rate and adjust certain financial ratios and maintenance covenants. The revolving credit facility as of November 7, 2011 remains undrawn. Excluding any potential cash requirements for growth opportunities that may arise, our current cash on-hand and our internal cash projections indicate that our $300 million revolving credit facility will remain undrawn for the foreseeable future beyond 2011. As of September 30, 2011, we had a posted letter of credit for $0.9 million and had $249.1 million of credit available under our revolving credit facility, for all uses of proceeds, including working capital, if necessary. The increased borrowing base of the facility will automatically be effective upon the perfecting of the security interest in the additional vessels pledged as collateral.

Although we expect to continue generating positive working capital through our operations, events beyond our control, such as an extended delay in returning to normal operating conditions following the de facto regulatory moratorium 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 in the Risk Factors in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K or under the “Forward Looking Statements” discussed in this Quarterly Report on Form 10-Q, may affect our financial condition, results of operations or cash flows. None of our funded debt instruments mature any sooner than November 2013. Our currently undrawn revolving credit facility now matures in November 2016, provided that we meet certain liquidity and/or bond refinancing conditions required by such facility. See further discussion of such refinancing conditions in the Contractual Obligations section below. Depending on the market demand for our vessels, long-term debt maturities and other growth opportunities that may arise, we may require additional debt or equity financing. We currently expect to generate sufficient cash to 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 $17.2 million for the nine months ended September 30, 2011 and $101.5 million for the nine months

 

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ended September 30, 2010. Operating cash flows for the first nine months of 2011 were unfavorably affected by a decline in our weighted-average operating fleet and a decrease in demand for our Upstream equipment primarily due to regulatory-driven market weakness in the GoM.

Investing Activities. Net cash used in investing activities was $12.6 million for the nine months ended September 30, 2011 and $56.3 million for the nine months ended September 30, 2010. 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. Cash utilized during the first nine months of 2010 primarily consisted of construction costs incurred for our newbuild and conversion programs, which were partially offset by approximately $2.8 million in aggregate net cash proceeds from the sale of one conventional OSV, one older, lower-horsepower tug, and other non-revenue generating equipment. Our fourth new generation OSV program and our MPSV program were completed during 2010.

Financing Activities. Net cash provided by financing activities was $0.7 million for the nine months ended September 30, 2011 and $0.7 million for the nine months ended September 30, 2010. Net cash provided by financing activities for the nine months ended September 30, 2010 and 2011 was comprised of deferred financing costs and net proceeds from common shares issued pursuant to our employee stock-based compensation plans.

Contractual Obligations

Debt

As of September 30, 2011, we had total debt of $767.5 million, net of original issue discount of $32.5 million. Our debt is comprised of $299.8 million of our 6.125% senior notes due 2014, or 2014 senior notes, $244.2 million of our 8.000% senior notes due 2017, or 2017 senior notes, and $223.5 million of our 1.625% convertible senior notes due 2026, or convertible senior notes. On March 14, 2011, we amended the credit agreement governing our $250 million revolving credit facility to adjust certain financial ratios and provide for additional new maintenance covenants. The changes to our revolving credit facility were effective commencing with the fiscal quarter ended December 31, 2010. Other than these changes, all other definitions and substantive terms in our credit agreement governing our revolving credit facility were unchanged. For further information on our debt agreements, see Note 3 to our consolidated financial statements included herein. As of September 30, 2011, we were in compliance with all of our debt covenants.

On November 2, 2011, we amended and restated our revolving credit facility, which increased our borrowing base to $300.0 million and included an accordion feature that allows for the potential expansion of the facility up to an aggregate of $500.0 million. The key changes to our revolving credit facility were as follows:

 

•

The amended facility extends the maturity from March 2013 to November 2016, unless our 6.125% senior notes remain outstanding on June 1, 2014, in which case, the facility would mature on such date.

 

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•

The minimum interest coverage ratio will be 2.00 to 1.00 for the quarters ending December 31, 2011 to September 30, 2012, 2.50 to 1.00 for the quarters ending December 31, 2012 and March 31, 2013 and 3.00 to 1.00 for the quarters ending June 30, 2013 and thereafter.

 

•

The annual interest rate under the amended facility was reduced by an amount ranging from 50 basis points to 100 basis points as determined by a leverage ratio pricing grid, as defined.

 

•

The maximum total debt to capitalization ratio, as defined, was replaced by a maximum total funded net debt to EBITDA ratio, as defined, of 4.00 beginning with the quarter ending December 31, 2012.

 

•

We are increasing the vessels pledged as collateral from 19 to 23 new generation OSVs commensurate with the higher borrowing base.

 

•

If our 1.625% convertible notes remain outstanding on April 30, 2013, we are required to maintain, as of the end of such calendar month and each calendar month-end thereafter, available liquidity of $350 million until the refinancing of the 1.625% convertible notes to a date that is 91 days beyond the scheduled maturity of the facility or the redemption of the 1.625% convertible notes, provided that such redemption complies with the other provisions of the facility.

 

•

We are permitted to repay our 1.625% convertible notes and our 6.125% senior notes, provided that we have available liquidity of $100 million on a pro forma basis and can demonstrate to the agent under the facility that our business plan is fully funded for the next four fiscal quarters, provided, however, that in the event that we seek to repay the 6.125% senior notes prior to repaying the 1.625% convertible notes, we must have available liquidity of $350 million on a pro forma basis.

Other than these key changes, all other definitions and substantive terms in our credit agreement governing our revolving credit facility were unchanged from the March 2011 amendment and remain in effect through the remaining life of the facility.

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 2014 senior notes and 2017 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 recently amended financial ratios for the quarterly compliance reporting period ended September 30, 2011, 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.

 

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We continuously review our debt covenants and report our compliance with financial ratios on a quarterly basis. We also consider such covenants in evaluating transactions that will have an effect on our financial ratios.

Capital Expenditures and Related Commitments

The following table summarizes the costs incurred, prior to the allocation of construction period interest, for maintenance capital expenditures for the three and nine months ended September 30, 2011 and 2010, and a forecast for fiscal 2011 (in millions):

 

		Three Months Ended September  30,								Nine Months Ended September  30,								Year Ended December 31,
		2011				2010				2011				2010				2011
		Actual				Actual				Actual				Actual				Forecast
Maintenance and Other Capital Expenditures:
Maintenance Capital Expenditures
Deferred drydocking charges (1)		$	6.1			$	3.6			$	16.5			$	15.7			$	21.0
Other vessel capital improvements (2)			1.8				0.5				8.1				5.1				15.8
			7.9				4.1				24.6				20.8				36.8
Other Capital Expenditures
Commercial-related vessel improvements (3)			8.6				0.8				14.4				17.0				21.3
Miscellaneous non-vessel additions (4)			0.7				0.2				1.4				1.5				1.9
			9.3				1.0				15.8				18.5				23.2
Total:		$	17.2			$	5.1			$	40.4			$	39.3			$	60.0

 

(1)	Deferred drydocking charges for the full-year 2011 include the actual and projected recertification costs for 16 OSVs, one MPSV, two tank barges and two tugs.

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

(3)	Commercial-related vessel improvements include items, such as cranes, ROVs and other specialized vessel equipment, which costs are typically included in and offset by higher dayrates charged to customers.

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

Forward Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements,” as contemplated by the Private Securities Litigation Reform Act of 1995, in which the Company discusses factors it believes may affect its performance in the future. Forward-looking statements are all statements other than historical facts, such as statements regarding assumptions, expectations, beliefs and projections about future events or conditions. You can generally identify forward-looking statements by the appearance in such a statement of words like “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “remain,” “should,” or “will,” or other comparable words or the negative of such words. The accuracy of the Company’s assumptions, expectations, beliefs and projections depends on events or conditions that change over time and are thus susceptible to change based on actual experience, new developments and known and unknown risks. The Company gives no assurance that the forward-looking statements will prove to be correct and does not undertake any duty to update them. The Company’s actual future results might differ from the forward-looking statements made in this Quarterly Report on Form 10-Q for a variety of reasons. An oil spill or other significant event

 

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in the United States or another offshore drilling region 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. Future results may also be impacted by legislation or regulations implemented in response to the Deepwater Horizon incident in the GoM, as well as the outcome of pending litigation brought by environmental groups challenging recent exploration plans approved by the DOI. Such legislation, regulations or litigation could further aggravate a number of other existing risks, uncertainties and assumptions, including, without limitation: the Company’s inability to successfully or timely complete any future newbuild programs, which involves the construction and integration of highly complex vessels and systems; the Company’s inability to refinance long-term debt obligations that mature or otherwise may require repayment; 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 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 exploration and production activities in Brazil; declines in oil and natural gas prices; increases in operating costs; the inability to accurately predict vessel utilization levels and dayrates; the inability to effectively compete in or operate in international markets; less than anticipated subsea infrastructure demand activity in the GoM and other markets; the level of fleet additions by competitors that could result in over capacity; economic and political risks weather related risks; the inability to attract and retain qualified personnel; 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; 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 arise as a result of the oil spill disaster in the Gulf of Mexico or the resulting drilling moratoria and regulatory reforms; 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. 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 this Quarterly Report on Form 10-Q 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.

 

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Item 3—Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes to the market risk disclosures set forth in Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2010.

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, 2011 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

Except as set forth below, 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, 2010.

Demand for our OSV services substantially depends on the level of activity in offshore oil and gas exploration, development and production.

The level of offshore oil and gas exploration, development and production activity has historically been volatile and is likely to continue to be so in the future. The level of activity is subject to large fluctuations in response to relatively minor changes in a variety of factors that are beyond our control. As discussed herein, oil and gas exploration, development and production activity in the GoM declined sharply in the wake of the Obama Administration’s drilling moratorium and subsequent de facto regulatory moratorium that followed the Deepwater Horizon incident. While there has been gradual improvement in the number of incremental deepwater well permits issued per month in the GoM, it is possible that legislation

 

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or additional regulations implemented in response to the Deepwater Horizon incident, as well as the outcome of pending litigation brought by environmental groups challenging exploration plans recently approved by the DOI may slow the pace of this permitting.

In addition to the foregoing, the following factors may influence oil and gas exploration, development and production levels in the GoM, as well as our other core markets of Mexico and Brazil:

 

•

local and international political and economic conditions and policies;

 

•

changes in capital spending budgets by our customers;

 

•

unavailability of drilling rigs in our core markets of the GoM, Mexico and Brazil;

 

•

prevailing oil and natural gas prices and expectations about future prices and price volatility;

 

•

the cost of offshore exploration for, and production and transportation of, oil and natural gas;

 

•

successful exploration for, and production and transportation of, oil and natural gas from onshore sources;

 

•

worldwide demand for oil and natural gas;

 

•

consolidation of oil and gas and oil service companies operating offshore;

 

•

availability and rate of discovery of new oil and natural gas reserves in offshore areas;

 

•

technological advances affecting energy production and consumption;

 

•

weather conditions;

 

•

environmental and other regulation affecting our customers and their other service providers; and

 

•

the ability of oil and gas companies to generate or otherwise obtain funds for exploration and production.

Failure by Petrobras to continue its announced plans for increased exploration and production activities offshore Brazil may have a material adverse effect on the market for high-spec OSVs.

Petrobras has publicly announced plans to spend approximately $128 billion on exploration and production activities from 2011 through 2015 and has stated that its vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Any decision by Petrobras to materially reduce the scope or pace of its announced exploration and production plans offshore Brazil could negatively impact the worldwide market for high-spec OSVs and could have a material adverse effect on our financial condition and results of operations.

 

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We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Increasingly stringent federal, state, local and foreign laws and regulations governing worker health and safety and the manning, construction and operation of vessels significantly affect our operations. Many aspects of the marine industry are subject to extensive governmental regulation by the United States Coast Guard, the National Transportation Safety Board, the Environmental Protection Agency and the United States Customs Service, and their foreign equivalents, and to regulation by private industry organizations such as the American Bureau of Shipping. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, while the Coast Guard and Customs Service are authorized to inspect vessels at will. Our operations are also subject to international conventions and federal, state, local and international laws and regulations that control the discharge of pollutants into the environment or otherwise relate to environmental protection. Compliance with such laws, regulations and standards may require installation of costly equipment, increased manning, or operational changes. While we endeavor to comply with all applicable laws, we might not and our failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions, imposition of remedial obligations or the suspension or termination of our operations. Some environmental laws impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others, including charterers. Moreover, these laws and regulations could change in ways that substantially increase costs that we may not be able to pass along to our customers. Any changes in applicable conventions, laws, regulations or standards that would impose additional requirements or restrictions on our or our oil and gas exploration and production customers’ operations could adversely affect our financial condition and results of operations. It is possible that, in response to the Deepwater Horizon incident, these laws and regulations may become even more stringent, which could also adversely affect our financial condition and results of operations.

We are also subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of a national emergency or a threat to the security of the national defense, the Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (which includes United States corporations), including vessels under construction in the United States. If one of our OSVs, MPSVs, tugs or tank barges were purchased or requisitioned by the federal government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our tugs is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We would also not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our OSVs, MPSVs, tugs or tank barges. The purchase or the requisition for an extended period of time of one or more of our vessels could adversely affect our results of operations and financial condition.

 

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Finally, we are subject to the Merchant Marine Act of 1920, commonly referred to as the Jones Act, which requires that vessels engaged in coastwise trade to carry cargo between U.S. ports be documented under the laws of the United States and be controlled by U.S. citizens. A corporation is not considered a U.S. citizen unless, among other things, at least 75% of the ownership of voting interests with respect to its equity securities are held by U.S. citizens. We endeavor to ensure that we would be determined to be a U.S. citizen as defined under these laws by including in our certificate of incorporation certain restrictions on the ownership of our capital stock by non-U.S. citizens and establishing certain mechanisms to maintain compliance with these laws. If we are determined at any time not to be in compliance with these citizenship requirements, our vessels would become ineligible to engage in the coastwise trade in U.S. domestic waters, and our business and operating results would be adversely affected.

On November 3, 2011, the Department of Homeland Security published in the Federal Register its request for comments and information on the various mechanisms that publicly traded companies have chosen to employ in order to assure compliance with the citizenship requirements of the Jones Act. We do not know whether the request will lead to regulatory changes that could adversely affect the manner in which we evidence that we are maintaining our required level of U.S. citizenship.

The Jones Act’s provisions restricting coastwise trade to vessels controlled by U.S. citizens have recently been circumvented by foreign interests that seek to engage in trade reserved for vessels controlled by U.S. citizens and otherwise qualifying for coastwise trade. Legal challenges against such actions are difficult, costly to pursue and are of uncertain outcome. To the extent such efforts are successful and foreign competition is permitted, such competition could have a material adverse effect on domestic companies in the offshore service vessel industry and on our financial condition and results of operations. In addition, in the interest of national defense, the Secretary of Homeland Security is authorized to suspend the coastwise trading restrictions imposed by the Jones Act on vessels not controlled by U.S. citizens. Such a waiver was issued following Hurricane Katrina and was in effect on a temporary basis for tank vessels that carried petroleum products. A more limited waiver continues in existence for vessels that carry petroleum cargoes from the Strategic Petroleum Reserve.

We may be unable to attract and retain qualified, skilled employees necessary to operate our business.

Our success depends in large part on our ability to attract and retain highly skilled and qualified personnel. Our inability to hire, train and retain a sufficient number of qualified employees could impair our ability to manage, maintain and grow our business.

In crewing our vessels, we require skilled employees who can perform physically demanding work. As a result of the volatility of the oil and gas industry and the demanding nature of the work, potential vessel employees may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. As a result of reduced utilization and dayrates over a period from April 2010 until late in the third quarter of 2011, we furloughed or layed-off employees.

 

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With a reduced pool of workers, it is possible that we will have to raise wage rates to attract workers and to retain our current employees. If we are not able to increase our service rates to our customers to compensate for wage-rate increases, our financial condition and results of operations may be adversely affected. If we are unable to recruit qualified personnel we may not be able to operate our vessels at full utilization, which would adversely affect our results of operations.

Changes in legislation, policy, restrictions or regulations for drilling in the Gulf of Mexico that cause delays or deter new drilling could have a material adverse effect on our financial position, results of operations and cash flows.

In response to the April 20, 2010, Deepwater Horizon incident, the Obama Administration and regulatory agencies with jurisdiction over oil and gas exploration, including the DOI, responded to the Deepwater Horizon incident by imposing temporary moratoria on drilling operations, by requiring operators to reapply for exploration plans and drilling permits which had previously been approved and by adopting numerous new regulations and new interpretations of existing regulations regarding operations in the U.S. Gulf of Mexico that are applicable to our Upstream customers and with which their new applications for exploration plans and drilling permits must prove compliant. Compliance with these new regulations and new interpretations of existing regulations may materially increase the cost of drilling operations in the GoM, which could materially adversely impact our business, financial position or results of operations.

The uncertainty surrounding the timing and cost of drilling activities in the GoM is primarily the result of (i) newly issued regulations by the DOI and the BOEMRE, (ii) on-going clarifications and interpretive guidance often in the form of an NTL issued by the DOI, BOEM and BSEE (defined below) relating to these newly issued regulations as well as with respect to existing regulations, (iii) continuing compliance efforts relating to these regulations, clarifications and guidance, (iv) continuing uncertainty as to the ability of the BSEE to timely review submissions and issue drilling permits, (v) the general uncertainty regarding additional regulation of the oil and gas industry’s operations in the GoM and (vi) on-going and potential third party legal challenges to industry drilling operations in the GoM. Since early 2011, there has been gradual improvement in the number of approved permits per month, however, it is possible that the improvement of this pace could slow or reverse as a result of the uncertainties discussed above. In addition, the commission appointed by the President of the United States to study the causes of the catastrophe released its report and has recommended certain legislative and regulatory measures that should be taken to minimize the possibility of a reoccurrence of a disastrous spill. Various bills are being considered by Congress which, if enacted, could either significantly impact drilling and exploration activities in the GoM, particularly in the deepwater areas, or possibly drive a substantial portion of drilling and operational activity out of the GoM.

In addition, effective October 1, 2011, the BOEMRE was split into two federal bureaus, 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

 

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of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, our GoM oil and gas exploration and production customers are interacting with two newly formed federal bureaus to obtain approval of their exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of what was formerly the BOEMRE are fully divested from the former agency and implemented in the two federal bureaus.

Given the current restrictions, potential future restrictions and the uncertainty surrounding the availability of any exceptions to any restrictions, we cannot predict with certainty the pace with which our GoM oil and gas exploration and production customers will be able to continue their drilling activities in the GoM. Further restrictions on or a prolonged delay in these drilling operations would have a material adverse effect on our business, financial position or future results of operations. Moreover, the uncertainty caused by any such legislation, policy, restrictions or regulations for new drilling in the GoM could aggravate the potentially adverse effects of many of the risks otherwise identified in this Quarterly Report on Form 10-Q and the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

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

None.

Item 3—Defaults Upon Senior Securities

None.

Item 4—Removed and Reserved

Item 5—Other Information

GLOSSARY OF TERMS

We have included below the definitions for certain terms used in this Quarterly Report on Form 10-Q:

“AHTS” means anchor-handling towing supply;

“cabotage laws” laws pertaining to the privilege of carrying traffic between two ports in the same country;

“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;

 

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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;

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

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

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

“DWT” means deadweight tons;

“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;

“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;

 

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“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);

“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;

“ROV” means 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 from the vessel and limited maintenance is performed on the vessel; and

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

Item 6—Exhibits

Exhibit Index

 

Exhibit Number				Description of Exhibit
3.1		—		Second Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 to the Company’s Form 10-Q for the quarter ended March 31, 2005).
3.2		—		Certificate of Designation of Series A Junior Participating Preferred Stock filed with the Secretary of State of the State of Delaware on June 20, 2003 (incorporated by reference to Exhibit 3.6 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).
3.3		—		Fourth Restated Bylaws of the Company adopted June 30, 2004 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q for the quarter ended June 30, 2004).

 

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Exhibit Number				Description of Exhibit
4.1		—		Indenture dated as of November 23, 2004 between the Company, the guarantors named therein and Wells Fargo Bank, National Association (as Trustee), including table of contents and cross-reference sheet (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed November 24, 2004).
4.2		—		Specimen 6.125% Series B Senior Note due 2014 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-4 dated December 22, 2004, Registration No. 333-121557).
4.3		—		Specimen stock certificate for the Company’s common stock, $0.01 par value (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form 8-A dated March 25, 2004, Registration No. 001-32108).
4.4		—		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).
4.5		—		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).
4.6		—		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).
4.7		—		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).
4.8		—		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).
4.9		—		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).

 

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Exhibit Number				Description of Exhibit
4.10		—		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).
4.11		—		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).
4.12		—		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).
*10.1		—		Amended and Restated Credit Agreement dated as of November 2, 2011 by and among the Company and two of its subsidiaries, Hornbeck Offshore Services, LLC and Hornbeck Offshore Transportation, LLC, each of the lenders and the guarantors signatory thereto, and Wells Fargo Bank, NA, as administrative agent to the lenders.
*31.1		—		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2		—		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1		—		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		—		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101		—		Interactive Data File

 

*	Filed herewith.

 

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SIGNATURE

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

 

				Hornbeck Offshore Services, Inc.
Date: November 7, 2011						/s/    JAMES O. HARP, JR.
						James O. Harp, Jr.
						Executive Vice President and Chief Financial Officer

 

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