Edgar Filing: HORNBECK OFFSHORE SERVICES INC /LA

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2011

¨	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, Louisiana 70433

(985) 727-2000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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


Title of each class		Name of exchange, on which registered
Common Stock, $0.01 par value		New York Stock Exchange

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

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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. (Check one):

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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

The aggregate market value of the Common Stock held by non-affiliates computed by reference to the price at which the Common Stock was last sold as of the last day of registrant’s most recently completed second fiscal quarter is $710,254,518.

The number of outstanding shares of Common Stock as of January 31, 2012 is 35,013,059 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive 2012 proxy statement, anticipated to be filed with the Securities and Exchange Commission within 120 days after the close of the Registrant’s fiscal year, are incorporated by reference into Part III of this Annual Report on Form 10-K.

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS


PART I		1
	Item 1—Business	1
	Item 1A—Risk Factors	18
	Item 1B—Unresolved Staff Comments	30
	Item 2—Properties	31
	Item 3—Legal Proceedings	31
	Item 4—Mine Safety Disclosures	31
PART II		32
	Item 5—Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
	Item 6—Selected Financial Data	33
	Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Item 7A—Quantitative and Qualitative Disclosures About Market Risk	59
	Item 8—Financial Statements and Supplementary Data	60
	Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	60
	Item 9A—Controls and Procedures	60
	Item 9B—Other Information	63
PART III		65
	Item 10—Directors, Executive Officers and Corporate Governance	65
	Item 11—Executive Compensation	65
	Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	65
	Item 13—Certain Relationships and Related Transactions, and Director Independence	65
	Item 14—Principal Accounting Fees and Services	65
PART IV		66
	Item 15—Exhibits and Financial Statement Schedules	66
CONSOLIDATED FINANCIAL STATEMENTS		F-1
SIGNATURES		S-1
EXHIBIT INDEX		E-1

Forward Looking Statements

This Annual Report on Form 10-K 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 Annual Report on Form 10-K for a variety of reasons, including the effect of the regulatory slow-down in the pace of issuing drilling permits and plan approvals in the GoM; the Company’s inability to successfully complete its fifth OSV newbuild program on-time and on-budget, which involves the construction and integration of highly complex vessels and systems; the inability to successfully market the vessels that the Company is constructing; an oil spill or other significant event in the United States or another offshore drilling region that could have a broad impact on deepwater and other offshore energy exploration and production activities, such as the suspension of activities or significant regulatory responses; the imposition of laws or regulations that result in reduced exploration and production activities or that increase the Company’s operating costs or operating requirements, including any such laws or regulations that may arise as a result of the Deepwater Horizon incident in the GoM or the resulting drilling moratoria and regulatory reforms, as well as the outcome of pending litigation brought by environmental groups challenging recent exploration plans approved by the Department of Interior; less than anticipated success in marketing and operating the Company’s MPSVs; bureaucratic, administrative or operating barriers that delay vessels chartered in foreign markets from going on-hire or result in contractual penalties 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; further 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; further increases in operating costs; the inability to accurately predict vessel utilization levels and dayrates; unanticipated difficulty in effectively competing in or operating in international markets; less than anticipated subsea infrastructure demand activity in the GoM and other markets; the level of fleet additions by the Company and its competitors that could result in over capacity; economic and political risks; weather-related risks; the inability to attract and retain qualified personnel, including vessel personnel for active, unstacked and newly constructed vessels; regulatory risks; the repeal or administrative weakening of the Jones Act, including any changes in the interpretation of the Jones Act related to the U.S. citizenship qualification; drydocking delays and cost overruns and related risks; vessel accidents or pollution incidents resulting in lost revenue or expenses that are unrecoverable from insurance policies or other third parties; unexpected litigation and insurance expenses;

fluctuations in foreign currency valuations compared to the U.S. dollar and risks associated with expanded foreign operations, such as non-compliance with or the unanticipated effect of tax laws, customs laws, immigration laws, or other legislation that result in higher than anticipated tax rates or other costs or the inability to repatriate foreign-sourced earnings and profits. In addition, the Company’s future results may be impacted by adverse economic conditions, such as inflation, deflation, or lack of liquidity in the capital markets, that may negatively affect it or parties with whom it does business resulting in their non-payment or inability to perform obligations owed to the Company, such as the failure of customers to fulfill their contractual obligations or the failure by individual banks to provide expected funding under the Company’s credit agreement. 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 Annual Report on Form 10-K as well as other filings the Company has made and will make with the Securities and Exchange Commission which, after their filing, can be found on the Company’s website www.hornbeckoffshore.com.

The Company makes references to certain industry-related terms in this Annual Report on Form 10-K. A glossary and definitions of such terms can be found in Item 9B – Other Information on page 63.

iii

PART I

ITEM 1—Business

COMPANY OVERVIEW

Hornbeck Offshore Services, Inc. was incorporated under the laws of the State of Delaware in 1997. In this Annual Report on Form 10-K, references to “company,” “we,” “us,” “our” or like terms refer to Hornbeck Offshore Services, Inc. and its subsidiaries, except as otherwise indicated. Hornbeck Offshore Services, Inc. is a leading provider of marine transportation services to exploration and production, oilfield service, offshore construction and U.S. military customers. Since our establishment, we have primarily focused on providing innovative technologically advanced marine solutions to meet the evolving needs of the deepwater and ultra-deepwater energy industry in domestic and, more recently, foreign locations. Throughout our history, we have expanded our fleet of vessels primarily through a series of new vessel construction programs, as well as through acquisitions of existing vessels. We maintain our headquarters at 103 Northpark Boulevard, Suite 300, Covington, Louisiana, 70433; our telephone number is (985) 727-2000.

We operate two business segments in the marine industry. Our Upstream segment owns and operates one of the youngest and largest fleets of U.S.-flagged, new generation OSVs and MPSVs. Since 2007, we have expanded our new generation fleet from 25 OSVs focused in the GoM to 51 OSVs and four MPSVs operating in three core geographic markets, the GoM, Brazil and Mexico, and in other select international regions. As discussed below, we have recently announced our fifth OSV newbuild program, which, when completed, would increase our expected OSV count to 67 vessels. Together, these vessels support the deep-well, deepwater and ultra-deepwater requirements of the offshore oil and gas industry. Such requirements include oil and gas exploration, development, production, construction, installation, IRM, well-stimulation and other enhanced oil recovery activities. Since 2006, we have also developed a specialized application of our new generation OSVs for use by the U.S. military. All of our OSVs have enhanced capabilities that allow us to more effectively support the premium drilling equipment required for deep-well, deepwater and ultra-deepwater drilling and to provide specialty services. In contrast to conventional OSVs, our vessels have dynamic positioning systems, greater fuel efficiency and speed, more cargo space, better safety characteristics, greater transit range and higher-volume transfer rates for liquid mud and dry bulk materials. These features are essential to the efficient servicing of complex offshore drilling projects given the typical size, depth and location of such projects. We believe we are one of the top three operators of new generation OSVs in each of our three core markets and one of the top five operators of such equipment worldwide based on DWT. Our fleet is among the youngest in the industry, with an average vessel age of approximately eight years compared to our domestic public company OSV peer group average vessel age of 13 years.

While we have historically operated our Upstream segment predominately in the GoM, the Deepwater Horizon incident and the resulting domestic deepwater drilling regulatory environment have contributed to our increased focus on deployment of vessels to international markets. As of December 31, 2011, we had 24 new generation OSVs working in foreign markets compared to 16 vessels and 11 vessels as of December 31, 2010 and 2009, respectively. Our Upstream segment also includes a shore-base facility located in Port

Fourchon, Louisiana. On occasion, we provide vessel management services for other vessels owners, such as crewing, daily operational management and maintenance activities.

Our Downstream segment owns and operates a fleet of ocean-going tugs and double-hulled tank barges that transport petroleum products, primarily in the northeastern United States and the GoM. For the twelve months ended December 31, 2011, our Upstream and Downstream segments contributed 98% and 2% of our operating income, respectively.

Although all of our Upstream vessels are physically capable of operating in both domestic and international waters, approximately 85% are qualified under Section 27 of the Merchant Marine Act of 1920, as amended, or the Jones Act, to engage in the U.S. coastwise trade. Foreign owned, flagged, built or crewed vessels are restricted in their ability to conduct U.S. coastwise trade and are typically excluded from such trade in the GoM. Of the public company OSV peer group, we own the largest fleet of U.S.-flagged, new generation OSVs, which we believe offers us a competitive advantage in the GoM.

We intend to continue our efforts to maximize stockholder value through our long-term return-oriented growth strategy. We will, as opportunities arise, acquire or construct additional vessels, as well as divest certain assets that we consider to be non-core or otherwise not in-line with our long-term strategy or prevailing industry trends.

DESCRIPTION OF OUR BUSINESS

Our Upstream Segment

General—OSVs

OSVs primarily serve exploratory and developmental drilling rigs and production facilities and support offshore and subsea construction, installation, IRM and decommissioning activities. OSVs differ from other ships primarily due to their cargo-carrying flexibility and capacity. In addition to transporting deck cargo, such as pipe or drummed material and equipment, OSVs also transport liquid mud, potable and drilling water, diesel fuel, dry bulk cement and personnel between shore bases and offshore rigs and production facilities. In the mid-1990s, oil and gas producers began seeking large hydrocarbon reserves in deeper water depths using new, specialized drilling and production equipment. We recognized that the then-existing fleet of conventional OSVs operating in the GoM was not designed to support these more complex projects or to operate in the challenging environments in which they were conducted. Therefore, in 1997, we conceived of a fleet of new generation OSVs with enhanced capabilities to allow them to more effectively support deepwater drilling and related construction projects. In order to best serve these projects, we designed our new generation vessels with larger liquid mud and dry bulk cement capacities, as well as larger areas of open deck space, which are features essential to deepwater projects that are often distant from shore-based support infrastructure. Deepwater environments also require dynamic positioning, or anchorless station-keeping capability, driven primarily by safety concerns that preclude vessels from physically mooring to deepwater installations. Such DP systems have experienced steady increases in technology over time with the highest DP rating currently being DP-3. The number following the DP notation generally indicates the degree of redundancy built into the vessel’s systems and the range of usefulness of the vessel in deepwater construction and subsea operations. Higher numbers represent greater DP

capabilities. Currently, 25 of our Upstream vessels are DP-1, 28 are DP-2 and two are DP-3. All 16 of the vessels to be constructed under our fifth OSV newbuild program are expected to be DP-2.

We believe that our reputation for safety and technologically superior vessels, combined with our size and scale relative to our public company OSV peer group, enhance our ability to compete for work awarded by large international oil and gas producers, who are among our primary customers. Approximately 85% of our total Upstream forward contracted revenue is currently with major oil companies, national oil companies, and the U.S. government. These customers demand a high level of safety and technological advancements to meet the more stringent regulatory standards adopted following the Deepwater Horizon incident. As our customers’ needs and requirements become more demanding, we expect that smaller vessel operators may struggle to meet these standards, which may lead to an increase in acquisition activity within our industry.

General—MPSVs

MPSVs also support the offshore exploration and production activities of the energy industry. MPSVs are distinguished from OSVs in that they are significantly larger and more specialized vessels that are principally used to support complex deepwater subsea construction, installation, intervention, IRM, decommissioning and other sophisticated operations. These vessels are or can be equipped with a variety of lifting and deployment systems, including ROVs, large capacity cranes, winches or reel systems. For example, MPSVs can serve as a platform for the subsea installation of risers, jumpers and umbilicals. MPSVs also support ROV operations, diving activities, oil spill response efforts, well intervention, including live well intervention, platform decommissioning, and other complex construction operations. Generally, MPSVs command higher day rates than OSVs due to their significantly larger relative size and versatility, as well as higher construction and operating costs.

In May 2005, we conceived of a new breed of MPSV that, in addition to the array of services described above, are also capable of being utilized to transport deck or bulk cargoes with capacities significantly exceeding that of even the largest new generation OSVs. We launched an innovative MPSV program to convert two former U.S.-flagged sulfur carriers into proprietary 370 class DP-2 new generation MPSVs. These MPSVs have approximately double the deadweight and three times the liquid mud barrel-capacity of one of our 265 class new generation OSVs and more than eight times the liquid mud barrel-capacity of one of our 200 class new generation OSVs. Moreover, these MPSVs can assist in large volume deepwater well testing and flow-back operations. In addition, these vessels can be outfitted with a variety of “tool kits” including ROVs, large capacity cranes, winches and other apparatus to support offshore construction, subsea well intervention, ROV operations, pipe-hauling, oil spill response and flotel services, among others.

Both of our 370 class MPSVs have certifications by the United States Coast Guard that permit operations as a supply vessel, industrial/construction vessel and as a petroleum and chemical tanker under subchapters “L”, “I”, “D”, and “O”, respectively. We believe that these vessels are not only the largest supply vessels in the world, but also the only vessels in the world to have received all four of these certifications.

In May 2007, we expanded our MPSV program to include the HOS Iron Horse, which is a newbuild MPSV that was constructed at IHC Holland’s Merwede Shipyard in the Netherlands. Our MPSV program was further expanded in January 2008 with the acquisition of the HOS Achiever, which was then under construction at IHC Holland’s Krimpen Shipyard, also in the Netherlands. The HOS Iron Horse and HOS Achiever are 430 class DP-3 new generation MPSVs. A DP-3 notation requires greater vessel and ship-system redundancies. DP-3 systems also include separate vessel compartments with fire-retardant walls for generators, prime movers, switchboards and most other DP components. These 430 class MPSVs are designed to handle a variety of global offshore energy applications, many of which are not dependent on the exploratory rig count. They are excellent platforms for those specialty services described above for our 370 class MPSVs with the exception of handling liquid cargoes. The HOS Iron Horse and the HOS Achiever are not U.S.-flagged vessels, however, they can engage in certain legally permissible operations in the U.S. that do not constitute coastwise trade.

The following table provides information, as of February 15, 2012, regarding our active Upstream fleet of 51 new generation OSVs and four MPSVs and the 16 new generation OSVs to be delivered under our fifth OSV newbuild program.

New Generation Vessels

Name⁽¹⁾

Design

Current
Service
Function

Current
Location

In-Service
Date

Deadweight
(long tons)

Liquid Mud
Capacity
(barrels)

Brake
Horsepower

DP
Class⁽²⁾

Active:

MPSVs

HOS Iron Horse

430

Multi-Purpose (FF)

GoM

Nov 2009

9,000

n/a

8,000

DP-3

HOS Achiever

430

Multi-Purpose (FF)

Mexico

Oct 2008

8,500

n/a

8,000

DP-3

HOS Centerline

370

Multi-Purpose

GoM

Mar 2009

8,000

32,000

6,000

DP-2

HOS Strongline

370

Multi-Purpose

GoM

Mar 2010

8,000

32,000

6,000

DP-2

OSVs

300 class (Over 5,000 DWT)

HOS Newbuild #1

320

Supply

TBD

4Q2013 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #2

320

Supply

TBD

4Q2013 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #3

320

Supply

TBD

1Q2014 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #4

320

Supply

TBD

1Q2014 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #5

320

Supply

TBD

2Q2014 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #6

320

Supply

TBD

2Q2014 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #7

320

Supply

TBD

2Q2014 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #8

320

Supply

TBD

3Q2014 est.⁽³⁾

6,200 est.

20,900 est.

6,000 est.

DP-2

HOS Newbuild #9

310

Supply

TBD

1Q2014 est.⁽³⁾

6,100 est.

22,700 est.

6,700 est.

DP-2

HOS Newbuild #10

310

Supply

TBD

2Q2014 est.⁽³⁾

6,100 est.

22,700 est.

6,700 est.

DP-2

HOS Newbuild #11

310

Supply

TBD

3Q2014 est.⁽³⁾

6,100 est.

22,700 est.

6,700 est.

DP-2

HOS Newbuild #12

310

Supply

TBD

4Q2014 est.⁽³⁾

6,100 est.

22,700 est.

6,700 est.

DP-2

HOS Newbuild #13

300

Supply

TBD

2Q2013 est.⁽³⁾

5,600 est.

21,100 est.

6,700 est.

DP-2

HOS Newbuild #14

300

Supply

TBD

3Q2013 est.⁽³⁾

5,600 est.

21,100 est.

6,700 est.

DP-2

HOS Newbuild #15

300

Supply

TBD

4Q2013 est.⁽³⁾

5,600 est.

21,100 est.

6,700 est.

DP-2

HOS Newbuild #16

300

Supply

TBD

1Q2014 est.⁽³⁾

5,600 est.

21,100 est.

6,700 est.

DP-2

HOS Coral

290

Supply

GoM

Mar 2009

5,600

15,200

6,100

DP-2

280 class (3,500 to 5,000 DWT)

HOS Ridgewind (4)

265

Supply

GoM

Nov 2001

3,756

10,700

6,700

DP-2

HOS Brimstone

265

Supply

GoM

Jun 2002

3,756

10,400

6,700

DP-2

HOS Stormridge

265

Supply

Brazil

Aug 2002

3,756

10,400

6,700

DP-2

HOS Sandstorm

265

Supply

Brazil

Oct 2002

3,756

10,400

6,700

DP-2

Name⁽¹⁾

Design

Current
Service
Function

Current
Location

In-Service
Date

Deadweight
(long tons)

Liquid Mud
Capacity
(barrels)

Brake
Horsepower

DP
Class⁽²⁾

240 class (2,500 to 3,500 DWT)

HOS Saylor

240

Well Stimulation (FF)

Mexico

Oct 1999

3,322

n/a

8,000

DP-1

HOS Navegante

240

Supply (FF)

Brazil

Jan 2000

3,322

6,000

7,845

DP-1

HOS Resolution

250EDF

Supply

Brazil

Oct 2008

2,950

8,300

6,000

DP-2

HOS Mystique

250 EDF

ROV Support

GoM

Jan 2009

2,950

8,300

6,000

DP-2

HOS Pinnacle

250 EDF

Supply

Brazil

Feb 2010

2,950

8,300

6,000

DP-2

HOS Windancer

250 EDF

Supply

Brazil

May 2010

2,950

8,300

6,000

DP-2

HOS Wildwing

250 EDF

Supply

Brazil

Sept 2010

2,950

8,300

6,000

DP-2

HOS Black Powder

250 EDF

Military

Other U.S.

Jun 2009

2,900

8,300

6,000

DP-2

HOS Westwind

250 EDF

Military

Other U.S.

Jun 2009

2,900

8,300

6,000

DP-2

HOS Eagleview

250 EDF

Military

Other U.S.

Oct 2009

2,900

8,300

6,000

DP-2

HOS Arrowhead

250 EDF

Military

Other U.S.

Jan 2010

2,900

8,300

6,000

DP-2

HOS Bluewater

240 ED

Supply

Brazil

Mar 2003

2,850

8,300

4,000

DP-2

HOS Gemstone

240 ED

Supply

Brazil

Jun 2003

2,850

8,300

4,000

DP-2

HOS Greystone

240 ED

Supply

Brazil

Sep 2003

2,850

8,300

4,000

DP-2

HOS Silverstar

240 ED

Supply

GoM

Jan 2004

2,850

8,300

4,000

DP-2

HOS Polestar

240 ED

Supply

GoM

May 2008

2,850

8,300

4,000

DP-2

HOS Shooting Star

240 ED

Supply

GoM

Jul 2008

2,850

8,300

4,000

DP-2

HOS North Star

240 ED

Supply

GoM

Nov 2008

2,850

8,300

4,000

DP-2

HOS Lode Star

240 ED

Supply

GoM

Feb 2009

2,850

8,300

4,000

DP-2

HOS Silver Arrow

240 ED

Supply

GoM

Oct 2009

2,850

8,300

4,000

DP-2

HOS Sweet Water

240 ED

Supply

GoM

Dec 2009

2,850

8,300

4,000

DP-2

200 class (1,500 to 2,500 DWT)

HOS Innovator

240 E

Supply

GoM

Apr 2001

2,380

5,500

4,500

DP-2

HOS Dominator

240 E

Military

Other U.S.

Feb 2002

2,380

6,400

4,500

DP-2

HOS Deepwater

240

Supply (FF)

Mexico

Nov 1999

2,250

6,300

4,500

DP-1

HOS Cornerstone

240

Supply

GoM

Mar 2000

2,250

6,300

4,500

DP-1

HOS Hope

200

Supply

Brazil

Jan 1999

2,250

4,100

4,200

DP-1

HOS Beaufort

200

Well Stimulation

Mexico

Mar 1999

2,250

4,100

4,200

DP-1

HOS Hawke

200

Well Stimulation (FF)

Mexico

Jul 1999

2,250

4,100

4,200

DP-1

HOS Byrd

200

Supply

GoM

Aug 1999

2,250

4,100

4,200

DP-1

HOS Douglas

200

Supply

Middle East

Apr 2000

2,250

4,100

4,200

DP-1

HOS Davis

200

Supply

GoM

Jun 2000

2,250

4,100

4,200

DP-1

HOS Nome

200

Supply

Middle East

Aug 2000

2,250

4,100

4,200

DP-1

HOS North

200

Supply

Brazil

Oct 2000

2,250

4,100

4,200

DP-1

HOS St. James

200

Supply

Brazil

Oct 1999

2,246

4,100

4,200

DP-1

HOS St. John

200

Supply

Brazil

Jan 2000

2,246

4,100

4,200

DP-1

HOS Crossfire

200

Supply (FF)

Mexico

Nov 1998

1,750

3,600

4,000

DP-1

HOS Super H

200

Supply

GoM

Jan 1999

1,750

3,600

4,000

DP-1

HOS Brigadoon

200

Supply (FF)

Mexico

Mar 1999

1,750

3,600

4,000

DP-1

HOS Thunderfoot

200

Supply

Mexico

May 1999

1,750

3,600

4,000

DP-1

HOS Dakota

200

Supply (FF)

Mexico

Jun 1999

1,750

3,600

4,000

DP-1

HOS Explorer

220

Supply

GoM

Feb 1999

1,607

3,100

3,900

DP-1

HOS Express

220

Supply

GoM

Sep 1998

1,607

3,100

3,900

DP-1

Inactive:⁽⁵⁾

OSVs

200 class (1,500 to 2,500 DWT)

HOS Trader

220

Supply

GoM

Nov 1997

1,607

3,100

3,900

DP-1

HOS Voyager

220

Supply

GoM

May 1998

1,607

3,100

3,900

DP-1

HOS Mariner

220

Supply

GoM

Sep 1999

1,607

3,100

3,900

DP-1

HOS Pioneer

220

Supply

GoM

Jun 2000

1,607

3,100

4,200

DP-1

FF—foreign-flagged

TBD—to be determined

(1)	Excludes one conventional OSV acquired with the Sea Mar Fleet in August 2007. This vessel, the Cape Breton, is considered a non-core asset and is currently inactive and marketed for sale.

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

(3)	These vessels are currently being constructed under our fifth OSV newbuild construction program with anticipated in-service dates ranging from 2013 through 2014.

(4)	The HOS Ridgewind was formerly known as the BJ Blue Ray and the Independence.

(5)

As a result of soft Upstream market conditions that occurred preceding and during the Obama Administration’s drilling moratorium and the subsequent de facto regulatory moratorium, we elected to stack up to a total of 15 new generation OSVs. As demand for this equipment increased, we were able to re-activate 11 of our stacked vessels since early 2011. The four remaining stacked vessels are expected to be re-activated for service in the GoM by the end of the first half of 2012, provided that we are able to re-crew such vessels and complete any required drydocking activities within that timeframe.

In December 2005, we acquired the lease rights to a shore-base facility located in Port Fourchon, Louisiana, which we renamed HOS Port. Port Fourchon’s proximity to the deepwater GoM provides a strategic logistical advantage for servicing drilling rigs and production units. Developed as a multi-use facility, Port Fourchon has historically been a land base for offshore oil support services and the Louisiana Offshore Oil Port, or LOOP. According to industry sources, Port Fourchon services nearly all deepwater rigs and almost half of all shallow rigs in the GoM. The HOS Port facility lease has one year remaining on its initial term, with four additional five-year renewal periods. In January 2008, we purchased a leasehold interest in an additional parcel of improved real estate adjacent to HOS Port. The new facility lease has three years remaining on its initial term, with four additional five-year renewal periods. The combined acreage of the two adjoining properties now comprising HOS Port is approximately 60 acres with total waterfront bulkhead of nearly 3,000 linear feet. HOS Port not only supports our existing fleet and Upstream customers’ deepwater logistics requirements, but it underscores our long-term commitment to and our long-term outlook for the deepwater GoM.

Principal Markets for 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 64 floating rigs under construction or on order on January 31, 2012 and, as of that date, there were options outstanding to build 22 additional floating rigs. In addition, on that date, there were 78 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 24 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 often measure transit time for a new generation vessel to some of the newer, more logistically remote deepwater 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.

OSVs and MPSVs operate worldwide, but are generally concentrated in relatively few offshore regions with high levels of exploration and development activity, such as the GoM, the North Sea, Southeast Asia, West Africa, Latin America, and the Middle East. While there

is some vessel migration between regions, key factors such as mobilization costs, vessel suitability and government statutes prohibiting foreign-flagged vessels from operating in certain waters, or coastwise cabotage laws such as the Jones Act, can limit the migration of OSVs. Because MPSVs are generally utilized for non-cargo operations, they are less limited by cabotage laws. Demand for OSVs, as evidenced by dayrates and utilization rates, is primarily related to offshore oil and natural gas exploration, development and production activity. Such activity is influenced by a number of factors, including the actual and forecasted price of oil and natural gas, the level of drilling permit activity, capital budgets of offshore exploration and production companies, and repair and maintenance needs in the deepwater oilfield. Historically, our principal geographic market has been the GoM, where we provide services to several major integrated oil companies as well as mid-size and large independent oil companies with deepwater and ultra-deepwater activities. We also operate in select international markets, primarily Brazil, Mexico, Trinidad and Qatar, where we provide services to state-owned oil companies and major international oil and oilfield service companies. We are often subcontracted by other oilfield service companies, both in the GoM and internationally, to provide a new generation fleet that enables them to render offshore oilfield services, such as well stimulation or other enhanced oil recovery activities, diving and ROV operations, construction, installation, maintenance, repair and decommissioning services. Since 2006, we have also developed a specialized application of our new generation OSVs for use by the United States military.

The April 20, 2010 catastrophic Deepwater Horizon incident and the U.S. government’s response has significantly and adversely disrupted oil and gas exploration activities in the GoM. Shortly after the explosion, the Department of the Interior (DOI) imposed a moratorium effectively suspending all deepwater drilling activity in the GoM. Although the DOI announced that it was lifting such drilling moratorium on October 12, 2010, delays in obtaining drilling permits and uncertainty surrounding compliance with new safety regulations, or a de facto regulatory moratorium, continue to slow new drilling and exploration activity by GoM operators, including operators in shallow waters. In response to the de facto regulatory moratorium, we further expanded our international presence by mobilizing additional vessels out of the GoM into foreign markets such as Latin America, West Africa, the Middle East or other regions during 2011. The ability or desirability of obtaining additional charters in international locations is not certain given the global competition that exists for such charters. Given the regulatory-driven weak market conditions in the GoM that prevailed during 2011, we elected to stack 15 of our new generation OSVs and took other measures to reduce costs, such as laying off crew members and deferring certain vessel drydocking and upgrades. Because of improving market conditions that began during the third quarter of 2011 and have continued into early 2012, we have returned all but four of our stacked new generation OSVs to service.

Our charters are the product of either direct negotiation or a competitive proposal process, which evaluates vessel capability, availability and price. Our primary method of chartering in the GoM is through direct vessel negotiations with our customers on either a long-term or spot basis. In the international market, we sometimes charter through local entities in order to comply with cabotage or other local requirements. Some charters are solicited by customers through international vessel brokerage firms, which earn a commission that is customarily paid by the vessel owner. Our military charters are the product of a competitive procurement process conducted by the Military Sealift Command. All of our

charters, whether long-term or spot, are priced on a dayrate basis, whereby for each day that the vessel is under contract to the customer, we earn a fixed amount of charter-hire for making the vessel available for the customer’s use. Many long-term contracts and all government, including national oil company, charters contain early termination options in favor of the customer; however, some have fees designed to discourage early termination. Long-term charters sometimes contain provisions that permit us to increase our dayrates in order to be compensated for certain increased operational expenses or regulatory changes.

Competition for Upstream Segment

The OSV and MPSV industry is highly competitive. Competition primarily involves such factors as:

•

quality, capability and age of vessels;

•

quality and capability of the crew members;

•

ability to meet the customer’s schedule;

•

safety record;

•

reputation;

•

price and;

•

experience.

All but nine of our OSVs and MPSVs are U.S.-flagged vessels, which are qualified under the Jones Act to engage in domestic coastwise trade. The Jones Act restricts the ability of vessels that are foreign-built, foreign-owned, foreign-crewed or foreign-flagged from engaging in coastwise trade in the United States including its territories, like Puerto Rico. The services typically provided by OSVs constitute coastwise trade as defined by the Jones Act. Consequently, competition for our Upstream services in the GoM is largely restricted to other U.S. vessel owners and operators, both publicly and privately held. We believe that we operate the second largest fleet of new generation Jones Act qualified OSVs in the United States. See “Environmental and Other Governmental Regulation” for a more detailed discussion of the Jones Act. Internationally, our OSVs compete against other U.S. owners, as well as foreign owners and operators of OSVs. Some of our international competitors may benefit from a lower cost basis in their vessels, which are not generally constructed in U.S. shipyards, as well as from lower crewing costs and favorable tax regimes. While foreign vessel owners cannot engage in U.S. coastwise trade, some cabotage laws in other parts of the world permit waivers for foreign vessels if domestic vessels are unavailable. We and other U.S. and foreign vessel owners have been able to obtain such waivers in the foreign jurisdictions in which we operate.

Many of the services provided by MPSVs do not involve the transportation of merchandise and therefore are generally not considered coastwise trade under U.S. and foreign cabotage laws. Consequently, our U.S.-flagged 370 class MPSVs face more competition from foreign-flagged vessels for non-coastwise trade activities. However, unlike most MPSVs that do not carry significant amounts of deck, bulk or liquid cargo, these vessels will compete for projects with other international MPSVs as well as participate in the GoM and international OSV markets as large-capacity carriers of drilling fluids, petroleum products and

deck cargos in support of deep-well exploration, development and production operations. Competition in the MPSV industry is significantly affected by the particular capabilities of a vessel to meet the requirements of a customer’s project. While operating in the GoM, our foreign-flagged DP-3 MPSVs are required to utilize U.S. crews while foreign-owned vessels are not. U.S. crews are often more expensive than foreign crews. Also, foreign MPSV owners may have more favorable tax regimes than ours. Consequently, prices for foreign-owned MPSVs in the GoM are often lower than prices we can charge. Finally, some potential MPSV customers are also owners of MPSVs that will compete with our vessels. However, we believe that in the GoM, MPSV customers prefer to contract U.S.-owned vessels for a variety of reasons, including reduced operating risks and perceived legal risks.

Although some of our principal competitors are larger, have greater financial resources and have more extensive international operations than we do, we believe that our operating capabilities and reputation for quality and safety enable us to compete effectively with other fleets in the market areas in which we operate or intend to operate. In particular, we believe that the relatively young age and advanced features of our OSVs and MPSVs provide us with a competitive advantage. The ages of our new generation OSVs range from one year to 13 years. In fact, one-third of our active new generation OSVs have been placed in service since January 1, 2008. The average age of the industry’s conventional U.S.-flagged OSV fleet is approximately 30 years. We believe that most of these older vessels are cold-stacked and many of them have been or will be permanently retired in the next few years due to physical and economic obsolescence. Worldwide competition for new generation vessels has been impacted in recent years by the increase in newbuild OSVs placed in service, greater customer interest in deep-well, deepwater and ultra-deepwater drilling activity and the U.S. government-imposed drilling moratorium and de facto regulatory moratorium in the GoM.

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 weak market conditions that prevailed throughout 2010 and for the majority of 2011, we furloughed or laid-off hundreds of employees. As Upstream market conditions began to improve during the third quarter of 2011, the demand for qualified mariners intensified in domestic and international markets. We have re-hired some of our previously laid-off or furloughed crewmembers as well as hired new employees. With a reduced pool of qualified mariners, it is possible that we will have to raise wage rates to attract workers and to retain our current employees which would negatively impact our operating costs. 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.

Our Downstream Segment

General

The domestic tank barge industry provides marine transportation of crude oil, petroleum products and petrochemicals by ocean-going tugs and tank barges and is a critical link in the U.S. petroleum distribution chain. The largest domestic tank barge market is on the East Coast. The largest tank barge market in the northeastern United States is New York Harbor. Petroleum products are transported in the northeastern United States through a vast network

of terminals, tankers and pipelines. Imported petroleum products are primarily delivered to New York Harbor as it has the capacity to receive products in cargo lots of 50,000 tons or more per tanker. By contrast, draft limitations in most New England ports and drawbridge limitations in Boston, Massachusetts and Portland, Maine limit the average cargo-carrying capacity of direct imports into many of the largest New England ports to about 30,000 tons per tanker. As larger petroleum tankers are being built, we believe that direct delivery into New York Harbor has favorably impacted tank barge demand for lightering services and further shipment to New England, the Hudson River and Long Island.

We offer marine transportation, distribution and logistics services primarily in the northeastern United States, GoM, Great Lakes and Puerto Rico with our active Downstream fleet of nine double-hulled tank barges and nine ocean-going tugs. We also own six ocean-going tugs that are stacked and marketed for sale. We provide our services to major integrated oil companies, independent refineries and oil traders. Generally, a tug and tank barge work together as a tow to transport refined or bunker grade petroleum products. Our tank barges carry petroleum products that are typically characterized as either “clean” or “dirty”. Clean petroleum products, or CPP, are primarily gasoline, home heating oil, diesel fuel and jet fuel. Dirty petroleum products, or DPP, are mainly crude oils, residual crudes and feedstocks, heavy fuel oils and asphalts. The demand for clean oil products is impacted by vehicle usage, air travel and prevailing weather conditions, while demand for black oil products varies depending on the type of product transported and other factors, such as refinery output and turnarounds, asphalt consumption, the use of residual fuel oil by electric utilities and bunker fuel demand.

Oil Pollution Act of 1990

OPA 90 mandates that all single-hulled tank vessels operating in U.S. waters be removed from petroleum transportation service according to a set time schedule. On March 2, 2011, we sold our last remaining single-hulled barge, which was scheduled to be retired by 2015 and had already been removed from service due to the soft demand for such vessels. None of our double-hulled tank barges are subject to OPA 90 retirement dates.

The following tables provide information, as of February 15, 2012, regarding our Downstream fleet of 15 ocean-going tugs and nine tank barges.

Ocean-Going Tugs


Name	Gross Tonnage		Length (feet)		Year Built/ Rebuilt⁽¹⁾	Brake Horsepower		Location
Active:
Freedom Service		180		126	1982/2005		6,140	GoM
Liberty Service		180		126	1982/2005		6,140	Northeast
Patriot Service		198		124	1996/2006		6,140	GoM
Eagle Service		198		124	1996/2006		6,140	GoM
Gulf Service		198		126	1979		3,900	Northeast
Erie Service		98		105	1981/2008		3,620	Northeast
Superior Service		98		105	1981/2008		3,620	Caribbean
Huron Service		98		105	1981/2007		3,000	Northeast
Michigan Service		98		105	1981/2007		3,000	Caribbean

Inactive:(2)
Caribe Service		194		111	1970		3,900	GoM
Brooklyn Service		198		105	1975		3,900	GoM
Atlantic Service		198		105	1978		3,900	GoM
Tradewind Service		183		105	1975		3,200	GoM
Spartan Service		126		102	1978		3,000	GoM
Sea Service		173		109	1975		2,820	GoM

(1)	Our first and second TTB newbuild programs included the retrofitting of a total of eight tugs. These vessels were significantly improved and modernized, including the addition of upper pilot houses, to accommodate our newbuild double-hulled tank barges.

(2)

In recognition of the soft Downstream market conditions for our equipment that began early in the second quarter of 2008 and the subsequent sale of all of our single-hulled tank barges, we have stacked six lower-horsepower tugs on various dates since April 1, 2008. These inactive vessels are currently being marketed for sale.

Ocean-Going Double-Hulled Tank Barges


Name	Barrel Capacity		Length (feet)		Year Built		Current Service		Current Location
Active:
Energy 13501		135,380		450		2005		DPP	GoM
Energy 13502		135,380		450		2005		DPP	GoM
Energy 11103		112,269		390		2005		DPP	GoM
Energy 11104		112,269		390		2005		CPP	Northeast
Energy 11105		112,269		390		2005		CPP	Northeast
Energy 8001		81,364		350		1996		DPP	Caribbean
Energy 6506		64,282		362		2007		CPP	Northeast
Energy 6507		65,230		362		2007		CPP	Northeast
Energy 6508		65,230		362		2008		CPP	Caribbean

Principal Market for Downstream Segment

Major oil companies, as well as refining, marketing and trading companies, constitute the majority of our customers for Downstream services. We enter into a variety of contractual arrangements with our Downstream customers, including spot and time charters, contracts of affreightment, consecutive voyage contracts and, occasionally, bareboat charters. Our contracts are obtained through competitive bidding, or with established customers through

negotiation. We sometimes place charters through the brokerage community, which charges a brokerage commission payable by us. The brokerage commissions are based on the dayrates charged to customers. Our ocean-going tugs and tank barges serve the northeastern U.S. coast, primarily New York Harbor, by transporting both clean and dirty petroleum products to and from refineries and distribution terminals. Our tugs and tank barges have also transported both clean and dirty petroleum products from refineries and distribution terminals in Puerto Rico to the Puerto Rico Electric Power Authority and to utilities located on other Caribbean islands. In addition, we have provided ship lightering, bunkering and docking services in these markets and are well positioned to provide such services to the increasing number of new tankers that are too large to make direct deliveries to distribution terminals and refineries. Also, since 2005, we have accessed new markets for our double-hulled tank barges by performing upstream services for our OSV customers in the deepwater GoM. Re-deploying some of our Downstream equipment to the GoM provided additional market opportunities with new downstream customers. Our tug and tank barge fleet has also served the Great Lakes region on a seasonal basis to support increased demand for clean fuels during the summer driving season.

Competition for Downstream Segment

In addition to pricing, which is a significant factor, the basis for competition in the Downstream industry is dependent upon four major determinants:

•

Management systems: The operating capabilities of the vessels and the skill of the crews that man those vessels is a key determinant of a fleet’s ability to operate efficiently.

•

Scheduling: The ability of the fleet to meet stringent customer sailing and delivery schedule requirements.

•

Experience: Efficient sailing schedules and lower fleet incident rates are indicative of higher safety standards and experienced personnel.

•

Vessel size and accessibility to customer terminals: Customer terminals vary widely in the sizes and types of vessels than can be accepted in their berths.

When analyzing our competitive landscape, we consider the blue-water, short-haul niche within the East Coast market to be our primary operating domain. In defining the East Coast, we include the entire Atlantic seaboard from the northeastern U.S. to Florida, the GoM region, Puerto Rico and the Great Lakes. The total barrel capacity of all short-haul competitors that are either headquartered or currently operating the majority of their vessels within the East Coast market is fairly evenly distributed among seven companies that own about 90% of the short-haul fleet; including the barrels that we transport. Competitors in our market niche are primarily comprised of well-established, multi-generational, family-owned businesses, with only two publicly traded companies, including us, having a critical mass of coastwise barges in the size range of 50,000 to 150,000 barrels of cargo-carrying capacity.

We do not anticipate significant competition in the near term from new “greenfield” refined products pipelines or pipeline expansions along the primary transportation routes in the northeastern U.S. or Puerto Rico.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 15 to our consolidated financial statements for further discussion regarding financial information by segment and geographic location.

CUSTOMER DEPENDENCY

Our customers are generally limited to large, independent, integrated or nationally-owned energy companies. These firms are relatively few in number. The percentage of revenues attributable to a customer in any particular year depends on the level of oil and natural gas exploration, development and production activities undertaken or refined petroleum products or crude oil transported by a particular customer, the availability and suitability of our vessels for the customer’s projects or products and other factors, many of which are beyond our control. For the year ended December 31, 2011, Petrobras and the United States Military Sealift Command each accounted for more than 10% of our total revenues. Both of these customers are government entities or government-owned entities. We also have significant contracts with PEMEX or with customers who have been contracted by PEMEX. Our contracts with Petrobras, PEMEX and the United States Military Sealift Command are subject to cancellation at the election of such entities, as is typical with government or government-owned entities. For a discussion of significant customers in prior periods, see Note 13 to our consolidated financial statements.

GOVERNMENT REGULATION

Environmental Laws and Regulations

Our operations are subject to a variety of federal, state, local and international laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. The requirements of these laws and regulations have become more complex and stringent in recent years and may, in certain circumstances, impose strict liability, rendering a company liable for environmental damages and remediation costs without regard to negligence or fault on the part of such party. Aside from possible liability for damages and costs including natural resource damages associated with releases of oil or hazardous materials into the environment, such laws and regulations may expose us to liability for the conditions caused by others or even acts of ours that were in compliance with all applicable laws and regulations at the time such acts were performed. Failure to comply with applicable laws and regulations may result in the imposition of administrative, civil and criminal penalties, revocation of permits, issuance of corrective action orders and suspension or termination of our operations. Moreover, it is possible that changes in the environmental laws, regulations or enforcement policies that impose additional or more restrictive requirements or claims for damages to persons, property, natural resources or the environment could result in substantial costs and liabilities to us. We believe that we are in substantial compliance with currently applicable environmental laws and regulations.

OPA 90 and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to the prevention and/or reporting of oil spills and liability for damages resulting from such spills. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel or the lessee or permittee of the area in which an offshore

facility is located. OPA 90 assigns liability to each responsible party for oil removal costs and a variety of public and private damages. Under OPA 90, as amended by the Coast Guard and Maritime Transportation Act of 2006, “tank vessels” of over 3,000 gross tons that carry oil or other hazardous materials in bulk as cargo, a defined term that includes our tank barges, are subject to liability limits of (i) for a single-hulled vessel, the greater of $3,200 per gross ton or $23.5 million or (ii) for a tank vessel other than a single-hulled vessel, the greater of $2,000 per gross ton or $17.1 million. “Tank vessels” of 3,000 gross tons or less are subject to liability limits of (i) for a single-hulled vessel, the greater of $3,200 per gross ton or $6.4 million or (ii) for a tank vessel other than a single-hulled vessel, the greater of $2,000 per gross ton or $4.3 million. For any vessels, other than “tank vessels,” that are subject to OPA 90, the liability limits are the greater of $1,000 per gross ton or $854,400. A party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. In addition, for vessels carrying crude oil from a well situated on the Outer Continental Shelf, the limits apply only to liability for damages. The owner or operator of such vessel is liable for all removal costs resulting from a discharge without limits. If the party fails to report a spill or to cooperate fully in the cleanup, the liability limits likewise do not apply and certain defenses may not be available. Moreover, OPA 90 imposes on responsible parties the need for proof of financial responsibility to cover at least some costs in a potential spill. As required, we have provided satisfactory evidence of financial responsibility to the U.S. Coast Guard for all of our vessels over 300 tons.

OPA 90 also imposes ongoing requirements on a responsible party, including preparedness and prevention of oil spills and preparation of an oil spill response plan. We have engaged the Marine Spill Response Corporation and National Response Corporation to serve as our independent contractors for purposes of providing stand-by oil spill response services for our fleet for all geographical areas of our operations. In addition, our Oil Spill Response Plan has been approved by the U.S. Coast Guard. OPA 90 requires that all newly-built tank vessels used in the transportation of petroleum products be built with double hulls and provides for a phase-out period for existing single hull vessels. Modifying or replacing existing vessels to provide for double hulls will be required of all single-hulled tank barges and tankers in the industry by the year 2015. None of our vessels are subject to this OPA 90 single-hulled retirement date.

The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the United States. The Clean Water Act also provides for civil, criminal and administrative penalties for any unauthorized discharge of oil or other hazardous substances in reportable quantities and imposes liability for the costs of removal and remediation of an unauthorized discharge, including the costs of restoring damaged natural resources. Many states have laws that are analogous to the Clean Water Act and also require remediation of accidental releases of petroleum in reportable quantities. Our OSVs routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. Our OSVs also transport bulk chemical materials used in drilling activities and liquid mud, which contain oil and oil by-products. In addition, our tank barges are specifically engaged to transport a variety of petroleum products. We maintain vessel response plans as required by the Clean Water Act to address potential oil and fuel spills.

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and similar laws impose liability for releases of hazardous substances into the environment. CERCLA currently exempts crude oil from the

definition of hazardous substances for purposes of the statute, but our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for response costs, as well as natural resource damages. Under CERCLA, responsible parties include owners and operators of vessels. Thus, we could be held liable for releases of hazardous substances that resulted from operations by third parties not under our control or for releases associated with practices performed by us or others that were standard in the industry at the time.

The Resource Conservation and Recovery Act regulates the generation, transportation, storage, treatment and disposal of onshore hazardous and non-hazardous wastes and requires states to develop programs to ensure the safe disposal of wastes. We generate non-hazardous wastes and small quantities of hazardous wastes in connection with routine operations. We believe that all of the wastes that we generate are handled in all material respects in compliance with the Resource Conservation and Recovery Act and analogous state statutes.

The United States Coast Guard has announced proposed regulations that when adopted, would require all of our existing vessels to meet certain standards pertaining to ballast water discharge, on or before certain dates between January 2014 and January 2016. The cost of compliance with these standards is presently unknown; however, our internal estimates range between $250,000 and $700,000, per vessel, for Phase I compliance and additional amounts thereafter for Phase II compliance.

The United States Environmental Protection Agency, or EPA, also has recently imposed emissions regulations affecting vessels that operate in the United States. These regulations impose standards that may require modifications to our vessels at a cost that we have as yet been unable to estimate. Moreover, the EPA’s decision to regulate “green house gasses” as a pollutant may result in further regulations and compliance costs.

Climate Change

Greenhouse gas emissions have increasingly become the subject of international, national, regional, state and local attention. Cap and trade initiatives to limit greenhouse gas emissions have been introduced in the European Union. Similarly, numerous bills related to climate change have been introduced in the U.S. Congress, which could adversely impact most industries. In addition, future regulation of greenhouse gas could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. It is uncertain whether any of these initiatives will be implemented. However, based on published media reports, we believe that it is unlikely that the current proposed initiatives in the U.S. will be implemented without substantial modification. If such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our operating results.

Restrictions on greenhouse gas emissions or other related legislative or regulatory enactments could have an effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently and indirectly, our offshore transportation and support services. We are currently unable to predict the manner or extent of any such effect. Furthermore, one of the

asserted long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our vessels in general and in the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.

EMPLOYEES

On December 31, 2011, we had 1,036 employees, including 811 operating personnel and 225 corporate, administrative and management personnel. Excluded from these personnel totals are 406 third-country nationals, or TCNs, that we contracted to serve on our vessels as of December 31, 2011. These non-U.S. crewmembers are typically provided by international crewing agencies. With the exception of our shoreside employees in Brazil, none of our employees are represented by a union or employed pursuant to a collective bargaining agreement or similar arrangement. We have not experienced any strikes or work stoppages, and our management believes that we continue to experience good relations with our employees.

SEASONALITY

Demand for our offshore support services is directly affected by the levels of offshore drilling activity. Budgets of many of our customers are based upon a calendar year, and demand for our Upstream services has historically been stronger in the second and third calendar quarters when allocated budgets are expended by our customers and weather conditions are more favorable for offshore activities. Many other factors, such as the expiration of drilling leases and the supply of and demand for oil and natural gas, may affect this general trend in any particular year. In addition, we typically have an increase in demand for our Upstream vessels to survey and repair offshore infrastructure immediately following major hurricanes or other named storms in the GoM.

Downstream services are significantly affected by the strength of the U.S. economy, changes in weather patterns and population growth that affect the consumption of and the demand for refined petroleum products and crude oil. The Downstream market has been historically impacted by seasonal weather patterns. Demand for heating oil in the northeastern United States, which is a significant market for our Downstream services, is generally driven by temperature levels experienced during the winter months. Normal winter conditions in the northeastern United States usually drive demand higher from December through March. However, unseasonably mild winters result in significantly lower demand during such months. In addition, the summer driving season, notwithstanding the impact of general economic trends such as gasoline price volatility, can increase demand for automobile fuel and, accordingly, the demand for our marine transportation services.

WEBSITE AND OTHER ACCESS TO COMPANY REPORTS AND OTHER MATERIALS

Our website address is http://www.hornbeckoffshore.com. We make available on this website, free of charge, access to our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as well as other documents that we file with, or furnish to, the Commission pursuant to Sections 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such documents are filed with, or furnished to, the Commission. We intend to use our website as a means of disclosing material non-public information and for complying with disclosure obligations under Regulation FD. Such disclosures will be included on our website under the heading “Investors—IR Home.” Accordingly, investors should monitor such portion of our website, in addition to following our press releases, Commission filings and public conference calls and webcasts. You may read and copy any materials we file with the Commission at the Commission’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You can obtain information on the operation of the Public Reference Room by calling the Commission at 1-800-732-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the Commission at http://www.sec.gov. Our Corporate Governance Guidelines, Employee Code of Business Conduct and Ethics (which applies to all employees, including our Chief Executive Officer and certain Financial and Accounting Officers), Board of Directors Code of Business Conduct and Ethics, and the charters for our Audit, Nominating/Corporate Governance and Compensation Committees, can all be found on the Investor Relations page of our website under “Corporate Governance”. We intend to disclose any changes to or waivers from the Employee Code of Business Conduct and Ethics that would otherwise be required to be disclosed under Item 5.05 of Form 8-K on our website. We will also provide printed copies of these materials to any stockholder upon request to Hornbeck Offshore Services, Inc., Attn: General Counsel, 103 Northpark Boulevard, Suite 300, Covington, Louisiana 70433. The information on our website is not, and shall not be deemed to be, a part of this report or incorporated into any other filings we make with the Commission.

ITEM 1A—Risk Factors

Our results of operations and financial condition can be adversely affected by numerous risks. You should carefully consider the risks described below as well as the other information we have provided in this Annual Report on Form 10-K. The risks described below are not the only ones we face. You should also consider the factors contained in our “Forward Looking Statements” disclaimer found on page ii of this Annual Report on Form 10-K. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations.

The failure to successfully complete our OSV Newbuild Program #5 or repairs, maintenance and routine drydockings on schedule and on budget could adversely affect our financial condition and results of operations.

In November 2011, we commenced our fifth OSV newbuild program. We have contracted with two domestic shipyards on the Gulf Coast to construct a total of 16 new generation, high-spec OSVs and have options with the shipyards to build an additional 48 vessels, in the aggregate. We routinely engage shipyards to drydock our vessels for regulatory compliance and to provide repair and maintenance. Our vessel newbuild program and drydockings are subject to the risks of delay and cost overruns inherent in any large construction project, including shortages of equipment, lack of shipyard availability, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, including costs of steel, inability to obtain necessary certifications and approvals and shortages of materials or skilled labor. Significant delays under our fifth OSV newbuild program could have a material adverse effect on anticipated contract commitments or anticipated revenues. Further, significant delays with respect to other possible newbuild programs or the conversion or drydockings of vessels could result in similar adverse effects to our anticipated contract commitments or revenues. Significant cost overruns or delays for vessels under construction, conversion or retrofit not adequately protected by liquidated damages provisions, in general could adversely affect our financial condition and results of operations.

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 such as the following:

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local and international political and economic conditions and policies,

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changes in capital spending budgets by our customers;

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

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

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

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

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worldwide demand for oil and natural gas;

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

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

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technological advances affecting energy production and consumption;

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weather conditions;

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

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

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. It is possible that legislation 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.

Failure by Petrobras to continue its announced plans for increased exploration and production activities offshore Brazil could 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.

We expect levels of oil and gas exploration, development and production activity to continue to be volatile and affect the demand for our Upstream and Downstream services.

Oil and natural gas prices are volatile. A downturn in oil prices or a deterioration in natural gas prices is likely to cause a decline in expenditures for exploration, development and production activity, which would likely result in a corresponding decline in the demand for OSVs and MPSVs and thus decrease the utilization and dayrates of our OSVs and MPSVs. Such decreases could negatively impact our financial condition and results of operations. Moreover, increases in oil and natural gas prices and higher levels of expenditure by oil and gas companies for exploration, development and production may not necessarily result in increased demand for our OSVs and MPSVs and could adversely affect utilization of our tugs and tank barges.

Increases in the supply of vessels could decrease dayrates.

In addition to our OSV Newbuild Program #5, certain of our competitors have announced plans to construct new vessels to be deployed in domestic and foreign locations. A remobilization to the GoM oilfield of U.S.-flagged vessels currently operating in other regions or in non-oilfield applications would result in an increase in vessel capacity in the GoM, one of our core markets. Similarly, vessel capacity in foreign markets, including our core markets of Mexico and Brazil, may also be impacted by U.S.-flagged or other vessels migrating to such foreign locations. Construction of double-hulled, ocean-going tank barges has increased ocean-going tank barge capacity. Further, a repeal, suspension or significant modification of the Jones Act, or the administrative erosion of its benefits, permitting vessels that are either foreign-flagged, foreign-built, foreign-owned, foreign-controlled or foreign-operated to engage in the U.S. coastwise trade, would also result in an increase in capacity. Any increase in the supply of OSVs or MPSVs, whether through new construction, refurbishment or conversion of vessels from other uses, remobilization or changes in law or its application, could not only increase competition for charters and lower utilization and dayrates, which would adversely affect our revenues and profitability, but could also worsen the impact of any downturn in the oil and gas industry on our results of operations and financial condition. Similarly, any increase in the supply of ocean-going tank barges, could not only increase competition, domestically and internationally, for charters and lower utilization and dayrates, which could negatively affect our revenues and profitability, but could also worsen the impact of any reduction in domestic consumption of refined petroleum products or crude oil on our results of operations and financial condition. Because some services provided by MPSVs are not protected by the Jones Act, foreign competitors may bring MPSVs to the GoM or build additional MPSVs that we will compete with domestically or internationally.

We may not have the funds available or be able to obtain the funds necessary to meet the obligations relating to our OSV Newbuild Program #5, our 6.125% senior notes due 2014, our 1.625% convertible senior notes due 2026 and our 8.000% senior notes due 2017.

Under our fifth OSV newbuild program, we will be required to spend approximately $720.0 million, excluding capitalized construction period interest, for the construction of the initial sixteen 300 class DP-2 OSVs. The amounts required to fund our fifth OSV newbuild program represent a substantial capital commitment. We expect the obligations relating to this newbuild program to be paid, over time through 2014, based on construction milestones. In November 2013, holders of the 1.625% convertible senior notes may require us to purchase their notes for cash. In November 2014, our 6.125% senior notes mature. In August 2017, our 8.000% senior notes mature. In addition, upon the occurrence of certain change of control events, as defined in the indentures governing the 6.125% senior notes and 8.000% senior notes, holders of such notes would have the right to require us to repurchase such notes at 101% of their principal amount, plus accrued and unpaid interest. To the extent that our cash on hand and cash flow from operations are not sufficient to meet these obligations, we plan to borrow on our currently undrawn and recently expanded credit facility, sell non-core assets and arrange for additional financing. Nevertheless, there can be no assurance that we will be able to sell our non-core assets or arrange for additional financing on acceptable terms. Further, under our amended and restated credit facility, we must meet certain liquidity requirements before we are permitted to purchase or repay our 1.625% convertible senior notes and our 6.125% senior notes. Failure to meet our obligations related to our fifth OSV

newbuild program, our 8.000% senior notes, our 1.625% convertible senior notes and our 6.125% senior notes may result in the acceleration of our other indebtedness and result in a material adverse effect on our financial condition and results of operations.

Intense competition in our industry could reduce our profitability and market share.

Contracts for our vessels are generally awarded on an intensely competitive basis. Some of our competitors, including diversified multinational companies in the Upstream segment, have substantially greater financial resources and larger operating staffs than we do. They may be better able to compete in making vessels available more quickly and efficiently, meeting the customer’s schedule and withstanding the effect of declines in dayrates and utilization rates. They may also be better able to weather a downturn in the oil and gas industry. As a result, we could lose customers and market share to these competitors. Some of our competitors may also be willing to accept lower dayrates in order to maintain utilization, which can have a negative impact on dayrates and utilization in both of our market segments. Similarly, competition in various markets may also be impacted by U.S.-flagged vessels migrating in and out of foreign locations due to the pace of drilling permit activity in the GoM. Moreover, customer demand for vessels under our fifth OSV newbuild program may not be as strong as we have anticipated and our inability to obtain contracts on anticipated terms or at all may have a material adverse effect on our revenues and profitability.

We have grown, and may continue to grow, through acquisitions that give rise to risks and challenges that could adversely affect our future financial results.

We regularly consider possible acquisitions of single vessels, vessel fleets and businesses that complement our existing operations to enable us to grow our business. Acquisitions can involve a number of special risks and challenges, including:

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diversion of management time and attention from our existing business and other business opportunities;

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delays in closing or the inability to close an acquisition for any reason, including third party consents or approvals;

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any unanticipated negative impact on us of disclosed or undisclosed matters relating to any vessels or operations acquired;

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loss or termination of employees, including costs associated with the termination or replacement of those employees;

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assumption of debt or other liabilities of the acquired business, including litigation related to the acquired business;

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the incurrence of additional acquisition-related debt as well as increased expenses and working capital requirements;

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dilution of stock ownership of existing stockholders;

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increased costs and efforts in connection with compliance with Section 404 of the Sarbanes-Oxley Act; and

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substantial accounting charges for restructuring and related expenses, impairment of goodwill, amortization of intangible assets, and stock-based compensation expense.

Even if we consummate an acquisition, the process of integrating acquired operations into our own may result in unforeseen operating difficulties and costs and may require significant management attention and financial resources. In addition, integrating acquired businesses may impact the effectiveness of our internal control over financial reporting. Any of the foregoing, and other factors, could harm our ability to achieve anticipated levels of utilization and profitability from acquired vessels or businesses or to realize other anticipated benefits of acquisitions.

We can give no assurance that we will be able to identify desirable acquisition candidates or that we will be successful in entering into definitive agreements or closing such acquisitions on satisfactory terms. An inability to acquire additional vessels or businesses may limit our growth potential.

Revenues from our Downstream business could be further adversely affected by a decline in demand for domestic refined petroleum products and crude oil or a change in existing methods of delivery in response to insufficient availability of Downstream services and other conditions.

A reduction in domestic consumption of refined petroleum products or crude oil has adversely affected the revenues of our Downstream business and could worsen. Further worsening could affect our financial condition and results of operation. Weather conditions also affect demand for our Downstream services. For example, a mild winter may reduce demand for heating oil in the northeastern United States.

Moreover, alternative methods of delivery of refined petroleum products or crude oil may develop as a result of insufficient availability of Downstream services, the cost of compliance with homeland security, environmental regulations or increased liabilities connected with the transportation of refined petroleum products and crude oil. For example, long-haul transportation of refined petroleum products and crude oil is generally less costly by pipeline than by tank barge. While there are significant impediments to building new pipelines, such as high capital costs and environmental concerns, entities may propose new pipeline construction to meet demand for petroleum products. To the extent new pipeline segments are built or existing pipelines converted to carry petroleum products, such activity could have an adverse effect on our ability to compete in particular markets.

The early termination of contracts on our vessels could have an adverse effect on our operations.

Some of the long-term contracts for our vessels and all contracts with governmental entities and national oil companies contain early termination options in favor of the customer; however, some have early termination remedies or other provisions designed to discourage the customers from exercising such options. We cannot assure that our customers would not choose to exercise their termination rights in spite of such remedies or the threat of litigation with us. Until replacement of such business with other customers, any termination could temporarily disrupt our business or otherwise adversely affect our financial condition and results of operations. We might not be able to replace such business on economically equivalent terms.

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, 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 or 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.

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. The Department of Homeland Security recently 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 been circumvented in recent years 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 waivers are granted from time-to-time, including in the recent past.

Our business involves many operating risks that may disrupt our business or otherwise result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks.

Our vessels are subject to operating risks such as:

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catastrophic marine disaster;

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adverse weather and sea conditions;

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mechanical failure;

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collisions or allisions;

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oil and hazardous substance spills;

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navigation errors;

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acts of God; and

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war and terrorism.

The occurrence of any of these events may result in damage to or loss of our vessels and their tow or cargo or other property and injury to passengers and personnel. If any of these events were to occur, we could be exposed to liability for resulting damages and possible penalties, that pursuant to typical marine indemnity policies, we must pay and then seek reimbursement from our insurer. Affected vessels may also be removed from service

and thus be unavailable for income-generating activity. While we believe our insurance coverage is at adequate levels and insures us against risks that are customary in the industry, we may be unable to renew such coverage in the future at commercially reasonable rates. Moreover, existing or future coverage may not be sufficient to cover claims that may arise and we do not maintain insurance for loss of income resulting from a marine casualty.

Our expansion of operations into international markets and shipyard activities in foreign shipyards subjects us to risks inherent in conducting business internationally.

Over the past several years we have derived an increasing portion of our revenues from foreign sources. In addition, certain of our shipyard repair and procurement activities are being conducted with foreign vendors. We therefore face risks inherent in conducting business internationally, such as legal and governmental regulatory requirements, potential vessel seizure or nationalization of assets, import-export quotas or other trade barriers, difficulties in collecting accounts receivable and longer collection periods, political and economic instability, kidnapping of or assault on personnel, piracy, adverse tax consequences, difficulties and costs of staffing international operations and language and cultural differences. We do not hedge against foreign currency risk. While we endeavor to contract in U.S. Dollars when operating internationally, some contracts may be denominated in a foreign currency, which would result in a foreign currency exposure risk. All of these risks are beyond our control and difficult to insure against. We cannot predict the nature and the likelihood of any such events. If such an event should occur, however, it could have a material adverse effect on our financial condition and results of operations.

We may lose the right to operate in some international markets in which we have a presence.

In certain foreign markets in which we operate, most notably Mexico and Brazil, we depend upon governmental waivers of cabotage laws. These waivers could be revoked or made more burdensome, which could result in our inability to continue our operations or materially increase the costs of operating in such foreign locations.

Future results of operations depend on the long-term financial stability of our customers.

Some of the contracts we enter into for our vessels are full utilization contracts with initial terms ranging from one to five years. We enter into these long-term contracts with our customers based on a credit assessment at the time of execution. Our financial condition in any period may therefore depend on the long-term stability and creditworthiness of our customers. We can provide no assurance that our customers will fulfill their obligations under our long-term contracts and the insolvency or other failure of a customer to fulfill its obligations under such contract could adversely affect our financial condition and results of operations.

We may be unable to attract and retain qualified, skilled employees necessary to operate 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. Further, we face strong competition within the broader oilfield industry for potential employees, including competition from drilling rig operators for our fleet personnel. 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 laid-off employees. As utilization improves and as the vessels being constructed in our OSV Newbuild Program #5 are delivered and placed in service and additional vessels are transitioned from stacked to active status, we may not be able rehire these employees or find suitable replacements. 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.

Our employees are covered by federal laws that may subject us to job-related claims in addition to those provided by state laws.

Some of our employees are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws preempt state workers’ compensation laws and permit these employees and their representatives to pursue actions against employers for job-related incidents in federal courts based on tort theories. Because we are not generally protected by the damage limits imposed by state workers’ compensation statutes for these types of claims, we may have greater exposure for any claims made by these employees.

Our success depends on key members of our management, the loss of whom could disrupt our business operations.

We depend to a large extent on the efforts and continued employment of our executive officers and key management personnel. We do not maintain key-man insurance. The loss of services of one or more of our executive officers or key management personnel could have a negative impact on our financial condition and results of operations.

Restrictions contained in the indentures governing our 6.125% senior notes due 2014 and our 8.000% senior notes due 2017 and in the agreement governing our revolving credit facility may limit our ability to obtain additional financing and to pursue other business opportunities.

Covenants contained in the indentures governing our 6.125% senior notes due 2014 and our 8.000% senior notes due 2017 and in the agreement governing our revolving credit facility require us to meet certain financial tests, which may limit or otherwise restrict:

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our flexibility in operating, planning for, and reacting to changes, in our business;

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our ability to dispose of assets, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and

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our ability to obtain additional financing for working capital, capital expenditures, including our newbuild programs, acquisitions, general corporate and other purposes.

We have high levels of fixed costs that will be incurred regardless of our level of business activity.

Our business has high fixed costs. Downtime or low productivity due to reduced demand, as experienced in 2009, 2010, and 2011, weather interruptions or other causes can have a significant negative effect on our operating results and financial condition.

Our revenues and operating results may vary significantly from quarter to quarter due to a number of factors such as volatility in our vessel dayrates, changes in utilization, vessel incidents and other unforeseen matters. Many of these factors that may cause our actual financial results to vary from our publicly disclosed earnings guidance and forecasts are outside of our control.

Our actual financial results might vary from those anticipated by us or by securities analysts and investors, and these variations could be material. From time to time we publicly provide various forms of guidance, which reflect our projections about future market expectations and operating performance. The numerous assumptions underlying such guidance may be impacted by factors that are beyond our control and might not turn out to be correct. Although we believe that the assumptions underlying our projections are reasonable, when such projections are made, actual results could be materially different, particularly with respect to our MPSVs.

We are susceptible to unexpected increases in operating expenses such as materials and supplies, crew wages, maintenance and repairs, and insurance costs.

Many of our operating costs are unpredictable and vary based on events beyond our control. Our gross margins will vary based on fluctuations in our operating costs. If our costs increase or we encounter unforeseen costs, we may not be able to recover such costs from our customers, which could adversely affect our financial position, results of operations and cash flows.

We may be adversely affected by uncertainty in the global financial markets.

Our future results may be impacted by continued volatility, weakness or deterioration in the debt and equity capital markets. Inflation, deflation, or other adverse economic conditions may negatively affect us or parties with whom we do business resulting in their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments, the failure of shipyards and major suppliers to complete orders or the failure by banks to provide expected funding under our revolving credit agreement. Additionally, credit market conditions may slow our collection efforts as customers experience increased difficulty in obtaining requisite financing, potentially leading to lost revenue and higher than normal accounts receivable. This could result in greater expense associated with collection efforts and increased bad debt expense.

The cost of raising money in the debt and equity capital markets has increased substantially during the ongoing financial crisis while the availability of funds from those markets has diminished significantly. The current global economic downturn may adversely impact our ability to issue additional debt and equity in the future on acceptable terms. Also, the cost of obtaining money from the credit markets has increased as many lenders and

institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt upon maturity or on terms similar to expiring debt. If we require additional sources of short-term liquidity for any reason including without limitation the factors stated above, our existing lenders may be unable or unwilling to extend credit to us. Due to these factors, we cannot be certain that additional funding will be available if needed and to the extent required, on acceptable terms.

We may be unable to collect amounts owed to us by our customers.

We typically grant our customers credit on a short-term basis. Related credit risks are inherent as we do not typically collateralize receivables due from customers. We provide estimates for uncollectible accounts based primarily on our judgment using historical losses, current economic conditions and individual evaluations of each customer as evidence supporting the receivables valuations stated on our financial statements. However, our receivables valuation estimates may not be accurate and receivables due from customers reflected in our financial statements may not be collectible.

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, imposed 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 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. In addition, the Commission appointed by the President of the United States to study the causes of the catastrophe released its report and recommended certain legislative and regulatory measures that the Commission believed 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 of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, since 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 being 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 Annual Report on Form 10-K.

The fundamental change purchase feature of our 1.625% convertible senior notes and provisions of our certificate of incorporation, bylaws, stockholder rights plan and Delaware law may delay or prevent an otherwise beneficial takeover attempt of our company.

The terms of our 1.625% convertible senior notes require us to purchase the notes for cash in the event of a fundamental change. A takeover of our company would trigger the requirement that we purchase the notes. Furthermore, our certificate of incorporation and bylaws, Delaware corporations law, and our stockholder rights plan contain provisions that could have the effect of making it more difficult for a third party to acquire, or discourage a third party from attempting to acquire, control of us. These provisions could limit the price that investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a takeover of our company that would otherwise be beneficial to investors.

The convertible note hedge and warrant transactions may affect the value of our common stock.

In connection with the original issuance of our 1.625% convertible senior notes, we entered into convertible note hedge and warrant transactions with counterparties that include affiliates of the initial purchasers of the convertible senior notes. The convertible note hedge transactions are expected to reduce the potential dilution upon conversion of such notes. However, if the warrants are exercised, such exercise would mitigate some of that reduction.

In connection with these hedging and warrant transactions, such counterparties or their affiliates may enter into, or may unwind, various derivatives and/or purchase or sell our common stock in secondary market transactions (and are likely to do so during any observation period related to a conversion of notes).

The effect, if any, of these convertible note hedge and warrant transactions or any of these hedging activities on the market price of our common stock or the convertible senior notes will depend in part on market conditions and cannot be ascertained at this time, but any of these activities could materially and adversely affect the value of our common stock.

Conversion of the 1.625% convertible senior notes or exercise of the warrants issued in the warrant transactions may dilute the ownership interest of existing stockholders.

The conversion of the 1.625% convertible senior notes or exercise of some or all of the warrants we issued in the warrant transactions may dilute the ownership interests of existing stockholders. Although the convertible note hedge transactions are expected to reduce potential dilution upon conversion of the 1.625% convertible senior notes, the warrant transactions could have a dilutive effect on our earnings per share to the extent that the price of our common stock exceeds the strike price of the warrants. Any sales in the public market of our common stock issuable upon such conversion of the 1.625% convertible senior notes could adversely affect prevailing market prices of our common stock. In addition, the anticipated exercise of the warrants for shares of our common stock could depress the price of our common stock.

ITEM 1B—Unresolved Staff Comments

None.

ITEM 2—Properties

Our principal executive offices are in Covington, Louisiana, where we lease approximately 61,000 square feet of office space under leases expiring in September 2013. Our primary domestic operating offices are located in Port Fourchon, Louisiana, and Brooklyn, New York. We also maintain four international offices from which we operate our fleet of vessels in Mexico and Brazil, as set forth below. For more information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations included within this report. We believe that our facilities, including waterfront locations used for vessel dockage and certain vessel repair work, provide an adequate base of operations for the foreseeable future. Our principal properties as of December 31, 2011 are as follows:


Location	Description	Segment Using Property	Owned/Leased
Covington, Louisiana, USA	Corporate Headquarters	Corporate	Leased
Hammond, Louisiana, USA	Warehouse	Upstream	Owned
Brooklyn, New York, USA	Dock, Office, Warehouse, Yard	Downstream	Leased
Port Fourchon, Louisiana, USA	Dock, Office, Warehouse, Yard	Upstream/Downstream	Leased
Paraiso, Tabasco, Mexico	Office	Upstream	Leased
Ciudad Del Carmen, Campeche, Mexico	Office	Upstream	Leased
Barra da Tijuca, Rio de Janeiro, Brazil	Office	Upstream	Leased
Macae, Rio de Janeiro, Brazil	Office	Upstream	Leased
Houston, Texas, USA	Office	Upstream	Leased

In addition to the foregoing, our revenues are principally derived from our fleet of 51 new generation OSVs and four MPSVs and nine ocean-going tank barges described in Item 1—Business of this Annual Report on Form 10-K.

Item 3—Legal Proceedings

A discussion of current legal proceedings is set forth in Note 10 to our consolidated financial statements.

Item 4—Mine Safety Disclosures

None.

PART II

Item 5— Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock, $0.01 par value, trades on the New York Stock Exchange, or NYSE, under the trading symbol “HOS”. The following table sets forth, for the quarterly periods indicated, the high and low sale prices for our common stock as reported by the NYSE during 2011 and 2010.


	2011				2010
	High		Low		High		Low
First Quarter	$	31.77	$	19.87	$	25.59	$	17.50
Second Quarter	$	31.38	$	23.65	$	25.75	$	12.63
Third Quarter	$	29.39	$	19.80	$	20.03	$	14.33
Fourth Quarter	$	36.24	$	21.96	$	23.68	$	18.72

On January 31, 2012, we had 30 holders of record of our common stock.

We have not previously declared or paid, and we do not plan to declare or pay in the foreseeable future, any cash dividends on our common stock. We presently intend to retain all of the cash our business generates to meet our working capital requirements, retire debt and fund future growth. Any future payment of cash dividends will depend upon the financial condition, capital requirements, plans to reduce our long-term debt and earnings of our Company, as well as other factors that our Board of Directors may deem relevant. In addition, the indentures governing our 6.125% senior notes and our 8.000% senior notes and the agreement governing our revolving credit facility include restrictions on our ability to pay cash dividends on our common stock. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 6 to our consolidated financial statements for further discussion.

See Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding shares of common stock authorized for issuance under our equity compensation plans.

Item 6—Selected Financial Data

SELECTED HISTORICAL CONSOLIDATED FINANCIAL INFORMATION

(In thousands, except operating and per share data)

Our selected historical consolidated financial information as of and for the years ended December 31, 2011, 2010, 2009, 2008, and 2007 was derived from our audited historical consolidated financial statements prepared in accordance with generally accepted accounting principles, or GAAP. The data should be read in conjunction with and is qualified in its entirety by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and the notes to those statements included elsewhere in this Annual Report on Form 10-K.


	Year Ended December 31,
	2011			2010			2009			2008			2007
Statement of Operations Data:
Revenues	$	381,627		$	420,804		$	385,948		$	432,084		$	338,970
Operating expenses		211,201			196,771			161,188			164,532			126,876
Depreciation and amortization⁽¹⁾		81,587			77,055			93,369			52,002			35,169
General and administrative expenses		35,363			36,774			30,844			37,155			32,857
Gain on sale of assets		1,539			2,025			1,147			8,402			1,859
Operating income		55,015			112,229			101,694			186,797			145,927
Interest income		829			528			482			1,525			18,414
Interest expense		59,649			55,183			21,024			8,331			21,299
Other income (expenses)⁽²⁾		442			344			(597	)		190			(43	)
Income (loss) before income taxes		(3,363	)		57,918			80,555			180,181			142,999
Income tax expense (benefit)		(802	)		21,502			30,155			64,379			51,782
Net income (loss)		(2,561	)		36,416			50,400			115,802			91,217

Per Share Data:
Basic net income (loss)	$	(0.09	)	$	1.38		$	1.94		$	4.48		$	3.55
Diluted net income (loss)	$	(0.09	)	$	1.34		$	1.87		$	4.29		$	3.45
Weighted average basic shares outstanding		27,876			26,396			26,040			25,840			25,662
Weighted average diluted shares outstanding⁽³⁾		27,876			27,176			26,975			27,020			26,467

Balance Sheet Data (at period end):
Cash and cash equivalents	$	356,849		$	126,966		$	51,019		$	20,216		$	173,552
Working capital		401,216			162,156			85,736			66,069			214,266
Property, plant, and equipment, net		1,605,785			1,606,121			1,602,663			1,405,340			956,558
Total assets		2,136,346			1,878,425			1,786,348			1,595,743			1,265,399
Total long-term debt⁽⁴⁾		770,648			758,233			746,674			618,519			484,076
Total stockholders’ equity		1,072,988			841,877			797,063			736,900			606,147

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	63,735		$	131,013		$	183,244		$	206,832		$	138,550
Investing activities		(62,299	)		(56,987	)		(263,050	)		(487,293	)		(442,032	)
Financing activities		228,830			1,866			110,590			127,109			2,710

Other Financial Data (unaudited):
EBITDA⁽⁵⁾	$	137,044		$	189,628		$	194,466		$	238,989		$	181,053
Capital expenditures		73,638			61,643			273,646			505,105			447,915
Other Operating Data (unaudited)⁽⁶⁾:
Offshore Supply Vessels:
Average number of new generation OSVs⁽⁷⁾		51.0			49.9			43.2			36.4			29.0
Average number of active new generation OSVs⁽⁸⁾		41.8			42.4			39.2			36.4			29.0
Average new generation OSV fleet capacity (DWT)		128,190			124,965			105,858			84,892			67,739
Average new generation OSV vessel capacity (DWT)		2,514			2,507			2,448			2,329			2,341
Average new generation OSV utilization rate⁽⁹⁾		71.5	%		71.6	%		79.9	%		95.4	%		93.3	%
Effective new generation OSV utilization rate⁽¹⁰⁾		87.2	%		84.3	%		88.0	%		95.4	%		93.3	%
Average new generation OSV dayrate⁽¹¹⁾	$	21,121		$	21,561		$	21,348		$	22,939		$	21,505
Effective dayrate⁽¹²⁾	$	15,102		$	15,438		$	17,057		$	21,884		$	20,064

Double-hulled Tank Barges⁽¹³⁾:
Average number of tank barges⁽¹⁴⁾		9.0			9.0			9.0			8.8			6.5
Average fleet capacity (barrels)⁽¹⁴⁾		884,621			884,621			884,621			872,347			719,354
Average barge capacity (barrels)		98,291			98,291			98,291			98,824			109,943
Average utilization rate⁽⁹⁾		88.1	%		80.5	%		71.5	%		85.0	%		92.4	%
Average dayrate⁽¹⁵⁾	$	17,557		$	17,502		$	21,138		$	21,806		$	23,026
Effective dayrate⁽¹²⁾	$	15,468		$	14,089		$	15,114		$	18,535		$	21,276

(1)

In June 2009, we recorded a pre-tax non-cash asset impairment charge of $25.8 million related to ten single-hulled tank barges and six ocean-going tugs. This impairment charge is reflected in depreciation expense for the year ended December 31, 2009. The Company’s amortization expense for such period includes a $0.9 million pre-tax non-cash charge for the write-off of remaining goodwill associated with our Downstream segment. Effective January 1, 2007, we modified our assumptions regarding estimated salvage values for our marine equipment. Salvage values for marine equipment are estimated to range between 5% and 25% of the originally recorded cost, depending on vessel type. For the year ended December 31, 2007, this change in estimated salvage values resulted in an increase in operating income, net income and diluted earnings per share of approximately $6.2 million, $4.0 million and $0.15, respectively.

(2)	Represents other operating income and expenses, including equity in income from investments and foreign currency transaction gains or losses.

(3)

Due to a net loss, we excluded, for the calculation of loss per share, the effect of equity awards representing the rights to acquire 1,209 shares of common stock for the year ended December 31, 2011 because the effect was anti-dilutive. For the years ended December 31, 2010, 2009, 2008, and 2007, stock options representing rights to acquire 400, 414, 3, and 146 shares, respectively, of common stock 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. See Note 3 of our consolidated financial statements for more information about diluted shares outstanding.

(4)

Excludes original issue discount associated with our 6.125% senior notes in the amount of $215, $279, $341, $398, and $453 as of December 31, 2011, 2010, 2009, 2008, and 2007, respectively; original issue discount associated with our 8.000% senior notes in the amount of $5,571, $6,305, and $6,980 as of December 31, 2011, 2010 and 2009, respectively; and original issue discount associated with our 1.625% convertible senior notes in the amount of $23,566, $35,183, $46,005, $56,083, and $65,471 as of December 31, 2011, 2010, 2009, 2008, and 2007, respectively.

(5)	See our discussion of EBITDA as a non-GAAP financial measure immediately following these footnotes.

(6)

Excluded from the Other Operating Data are the results of operations for our MPSVs, our shore-base facility, and vessel management services. Since our MPSVs are relatively new, we have not had the opportunity to have all four MPSVs working in a non-moratorium (de facto or otherwise) market environment or to fully develop the market’s understanding of their capabilities and various service offerings. This makes it difficult to predict the dayrate and utilization profile of these MPSVs under normal operating conditions and, therefore, the income generating potential that these MPSVs could have on our results of operations. Nevertheless, due to the fact that each of our MPSVs have a workload capacity and significantly higher income generating potential than each of our new generation OSVs, the utilization and dayrate levels of our MPSVs could have a very large impact on our results of operations. For this reason, our consolidated operating results, on a period-to-period basis, are disproportionately impacted by the level of dayrates and utilization achieved by our four MPSVs.

(7)

We owned 51 new generation OSVs as of December 31, 2011. Our average number of new generation OSVs for the years ended December 31, 2010, 2009 and 2008 reflect the deliveries of several vessels under our fourth OSV newbuild program. During 2010, 2009 and 2008, we placed in service, four OSVs, eight OSVs and four OSVs, respectively. Please refer to the New Generation OSVs table on page 4 of this Form 10-K for more information about vessel names and placed in service dates. Our average number of new generation OSVs for the year ended December 31, 2007 includes ten new generation OSVs that were acquired in August 2007. Excluded from this data are ten conventional OSVs that were also acquired in August 2007, nine of which have been sold on various dates in 2008, 2009, and 2010. Our remaining conventional OSV, which is stacked, is considered a non-core asset.

(8)

In response to weak market conditions, we elected to stack certain of our new generation OSVs on various dates in 2009 and 2010. Based on improved market conditions, we had re-activated 10 new generation OSVs as of December 31, 2011 and had one additional new generation OSV re-activated in January 2012. We also plan to unstack the remaining four vessels by the end of the first half of 2012, provided that we are able to re-crew such vessels and complete any required drydocking activities within that timeframe. Active new generation OSVs represent vessels that are immediately available for service during each respective period.

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

(10)	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.

(11)	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.

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

(13)

Other operating data for tugs and tank barges reflects our active Downstream fleet of nine double-hulled barges and nine ocean-going tugs. We also own six older, lower horsepower tugs, which we consider to be non-core assets and are marketed for sale. We previously owned a fleet of single-hulled tank barges; however, all of these vessels have been sold as they were also considered non-core assets, as a result of OPA 90.

(14)

The averages for the years ended December 31, 2011, 2010, 2009, 2008 and 2007 include the Energy 6506, Energy 6507 and Energy 6508, three double-hulled tank barges delivered under our second TTB newbuild program in August 2007, November 2007, and March 2008, respectively. As of December 31, 2011, our double-hulled tank barge fleet consisted of nine vessels.

(15)

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 of in-chartering third-party equipment paid by customers.

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 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 their usefulness as comparative measures.

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 bonuses paid to our executive officers and 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 years ended December 31, 2011, 2010, 2009, 2008, and 2007 respectively (in thousands).


	Year Ended December 31,
	2011			2010			2009			2008			2007
Components of EBITDA:
Net income (loss)	$	(2,561	)	$	36,416		$	50,400		$	115,802		$	91,217
Interest, net:
Debt obligations		59,649			55,183			21,024			8,331			21,299
Interest income		(829	)		(528	)		(482	)		(1,525	)		(18,414	)

Total interest, net		58,820			54,655			20,542			6,806			2,885

Income tax expense (benefit)		(802	)		21,502			30,155			64,379			51,782
Depreciation		60,960			58,509			69,461			33,498			22,950
Amortization		20,627			18,546			23,908			18,504			12,219

EBITDA	$	137,044		$	189,628		$	194,466		$	238,989		$	181,053

The following table reconciles EBITDA to cash flows provided by operating activities for the years ended December 31, 2011, 2010, 2009, 2008, and 2007 respectively (in thousands).


	Year Ended December 31,
	2011			2010			2009			2008			2007
EBITDA Reconciliation to GAAP:
EBITDA	$	137,044		$	189,628		$	194,466		$	238,989		$	181,053
Cash paid for deferred drydocking charges		(19,704	)		(22,510	)		(19,234	)		(19,773	)		(19,812	)
Cash paid for interest		(43,811	)		(44,178	)		(24,201	)		(24,981	)		(22,644	)
Cash paid for taxes		(1,272	)		(2,809	)		(15,520	)		(6,119	)		(4,799	)
Changes in working capital		(14,027	)		4,317			41,117			15,406			(986	)
Stock-based compensation expense		6,525			8,710			8,704			10,815			7,390
Changes in other, net		(1,020	)		(2,145	)		(2,088	)		(7,505	)		(1,652	)

Cash flows provided by operating activities	$	63,735		$	131,013		$	183,244		$	206,832		$	138,550

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 applicable covenants contained in our credit facility are described in the Liquidity and Capital Resources section of Item 7.

The following table provides certain detailed adjustments to EBITDA, as defined in our revolving credit facility for the years ended December 31, 2011, 2010, 2009, 2008, and 2007, respectively (in thousands).

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


	Year Ended December 31,
	2011		2010		2009		2008		2007
Stock-based compensation expense	$	6,525	$	8,710	$	8,704	$	10,815	$	7,390
Interest income		829		528		482		1,525		18,414

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.

Item 7—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 in conjunction with our historical consolidated financial statements and their notes included elsewhere in this Annual Report on Form 10-K. 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 or as a result of certain factors such as those set forth in our Forward Looking Statements disclaimer on page ii of this Annual Report on Form 10-K.

General

Our operations are conducted in three core markets comprised of the GoM, Brazil and Mexico. Descriptions of these core markets are included below.

Gulf of Mexico

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 IHS-Petrodata, the number of floating rigs available in the GoM region is currently 34 and remains unchanged from the pre-Macondo level of 34 rigs, because the 12 floaters that left the region have since been replaced by 12 similar or more advanced rigs. From early 2011 through October 2011, there was 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. However, permit approvals slowed again late in the fourth quarter of 2011. In January of 2012, the rate of deepwater drilling permit approvals was less than half of the average approval rate over the pre-Macondo five-year period. We anticipate that the pace of permit issuance will be uneven for some time to come. We believe that there is a backlog of permit applications and requests for approval of drilling plans, which would 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 34 rigs available in the GoM, the number of floating rigs actively drilling has also increased to 24 on January 31, 2012 from seven 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 if the pace of issuance of drilling permits and approval of exploratory plans experienced in September and October of 2011 becomes the norm, floating rig activity could return to pre-2010 levels by the end of 2013 with approximately 30 floating rigs expected to be drilling in the GoM, up approximately 25% from the 24 rigs drilling as of January 31, 2012. 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 laid-off employees, and moved vessels to new markets. According to IHS-Petrodata, as of February 2, 2012, 41 new generation Jones Act qualified vessels, or approximately 24% of the active pre-Macondo fleet, had left the GoM since Macondo and were 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. As of January 31, 2012, we have 18 active new generation OSVs and three 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. However, we also expect that some vessels that were already operating internationally pre-Macondo or left the GoM following the drilling moratorium will return, which could result in an oversupply of new generation OSVs if the pace of drilling does not continue to improve.

Due to a limited supply of high-spec U.S.-flagged vessels in the GoM and a substantial increase in deepwater drilling permits being issued in September and October 2011, we have recently seen improvement in dayrates and utilization for our vessels commencing late in the third quarter of 2011. Leading-edge spot market OSV dayrates in the GoM for our 240 class DP-2 equipment have been in the $28,000 to $30,000 range, which are 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 today and thus, currently have the most transaction volume. Since February 2011, we have re-activated 11 new generation OSVs. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs decreased about $300, or 2%, from 2010 to $15,102 for 2011. During 2011, we had an average stacked new generation OSV fleet of 9.2 vessels compared to 7.5 vessels in 2010. However, our averaged stacked new generation OSV fleet was 4.9 vessels for January 2012. With the re-activation of the 220 class HOS Explorer in October 2011 and the HOS Express in January 2012, we now have four DP-1 new generation OSVs stacked. Given the recent improvement in market conditions, our four remaining stacked new generation OSVs are expected to be re-activated for service in the GoM by the end of the first half of 2012, provided that we are able to re-crew such vessels and complete any required drydocking activities within that timeframe. The recovery in the GoM may also be adversely affected by an increasing shortage of and competition for qualified mariners. This shortage is being exacerbated by customer-driven requirements that increase the manning levels on many vessels, including drilling units that operate in the GoM. We expect that our labor costs, which comprise the highest portion of our operating costs, will increase due to this mariner shortage.

As of February 15, 2012, we had nearly 59% of our new generation OSV vessel-days contracted for 2012, with 20 vessels contracted beyond the end of 2012. Our forward OSV

contract coverage for 2013 currently stands at 27%. Our MPSV contract coverage for 2012 has also strengthened. In July 2011, 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, commenced a long-term contract with a major oil and gas company in the GoM during 2011. 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 89% for the fourth quarter of 2011, and MPSV contract coverage for 2012 and 2013 is currently 69% and 40%, respectively.

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 the state-owned oil company, Petroleo Brasileiro S.A., or Petrobras, and other producers, including BP p.l.c., Chevron Corporation, Exxon Mobil Corporation, OGX Petroleo e Gas Participacoes and Royal Dutch Shell plc. Petrobras has publicly announced plans to spend approximately $128 billion on exploration and production activities from 2011 through 2015 and has stated that its vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Brazilian operators plan to add 11 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 shore-side support personnel in the cities of Macae and Barra da Tijuca located in Rio de Janeiro, Brazil. Despite the emerging importance of Brazil as a long-term deepwater drilling market, we are experiencing high operating costs as well as regulatory complexity and bureaucratic inefficiency there, which impact our ability to generate operating margins commensurate with those we have historically generated in the GoM. Moreover, Petrobras is the single largest consumer of our services in Brazil and, for 2011, the Company overall. Petrobras accounted for more than 10% of our consolidated revenues in 2011. As is typical with large state-owned national oil companies, Petrobras’ contracts are onerous and contain multiple provisions that allow Petrobras to impose penalties for performance issues even if we disagree with the basis of these penalties. Petrobras has asserted penalties related to our contract and we expect that we will continue to confront similar issues with Petrobras going forward. In addition to regulatory complexity and the inherent difficulties associated with the Petrobras contracting regime, there is an acute shortage of mariners in Brazil, which we are required by law to employ on our vessels. This shortage is a significant contributor to escalating costs in Brazil.

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 27 jack-up rigs drilling offshore Mexico, and PEMEX has announced there are no plans to add another floating rig, however three more high-spec jack-up rigs will be added.

We began working in Mexico in 2002 and currently have seven vessels working there under long-term contracts and two vessels working under spot contracts. We will continue to actively bid additional vessels into Mexico as tenders are issued by PEMEX. We established our own Mexican navigation company, or Naviera, in 2008 and have increased our physical presence there with additional shore-side support personnel in Ciudad del Carmen and Dos Bocas.

Upstream Segment

All of our current Upstream vessels are qualified under the Jones Act to engage in U.S. coastwise trade, except for five foreign-flagged new generation OSVs, two foreign-flagged well stimulation vessels and two foreign-flagged MPSVs. As of December 31, 2011, our 46 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:


Domestic
GoM			20
Other U.S. coastlines⁽¹⁾			5

			25

Foreign
Brazil			14
Mexico			9
Middle East			2

			25

Total Upstream Vessels⁽²⁾			50

(1)	Represents vessels that are currently supporting the U.S. military.

(2)

Excluded from this table are five of our new generation OSVs and one conventional OSV that were stacked as of December 31, 2011. One additional new generation OSV was activated in January 2012. We expect all four remaining new generation OSVs that are stacked to be re-activated by the end of the first half of 2012, provided that we can re-crew such vessels and complete required regulatory drydockings within that timeframe.

OSV Newbuild Program #5. Our fifth OSV newbuild program consists of vessel construction contracts with two domestic shipyards to build four 300 class OSVs, four 310 class OSVs, and eight 320 class OSVs. Delivery of the first 16 vessels to be constructed under this program is expected to occur on various dates during 2013 and 2014. We expect to own and operate 56 and 67 new generation OSVs as of December 31, 2013 and 2014, respectively. These vessel additions result in a projected average new generation OSV fleet complement of 52.2 and 62.8 vessels for the fiscal years 2013 and 2014, respectively. The

aggregate cost of our fifth OSV newbuild program, excluding construction period interest, is expected to be approximately $720 million. For further information regarding our fifth OSV newbuild program, please refer to the Capital Expenditures and Related Commitments section.

Downstream Segment

As of December 31, 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 and being marketed for sale. The prolonged weakness in the overall economy, which has impacted our Downstream segment since 2008, continues to adversely impact demand for Downstream equipment. Although Downstream results for the second half of 2011 showed improvement 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 2012 and will substantially improve only when the U.S. economy rebounds. 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.

Operating Costs

Our operating costs are primarily a function of fleet size, areas of operations and utilization levels. The most significant direct operating costs are wages paid to vessel crews, maintenance and repairs, and marine insurance. Because most of these expenses are incurred regardless of vessel utilization, our direct operating costs as a percentage of revenues may fluctuate considerably with changes in dayrates and utilization. By stacking under-utilized vessels, we have been able to realize some reductions in our operating costs.

In certain foreign markets in which we operate, we are susceptible to higher operating costs, such as materials and supplies, crew wages, maintenance and repairs, taxes, and insurance costs. Difficulties and costs of staffing international operations, including vessel crews, and language and cultural differences generally contribute to a higher cost structure in foreign locations compared to our domestic operations. We may not be able to recover higher international operating costs through higher dayrates charged to our customers. Therefore, when we increase our international complement of vessels, particularly for our Upstream segment, our gross margins may fluctuate depending on the foreign areas of operation and the complement of vessels operating domestically.

In addition to the operating costs described above, we incur fixed charges related to the depreciation of our fleet and amortization of costs for routine drydock inspections and maintenance and repairs necessary to ensure compliance with applicable regulations and to maintain certifications for our vessels with the U.S. Coast Guard and various classification societies. The aggregate number of drydockings and other repairs undertaken in a given period determines the level of maintenance and repair expenses and marine inspection amortization charges. We capitalize costs incurred for drydock inspection and regulatory compliance and amortize such costs over the period between such drydockings, typically 30 months. Applicable maritime regulations require us to drydock our vessels twice in a five-year

period for inspection and routine maintenance and repair. If we undertake a large number of drydockings in a particular fiscal period, comparative results may be affected. While we can defer required drydockings of stacked vessels, we will be required to conduct such deferred drydockings prior to such vessels returning to service.

Critical Accounting Estimates

Our consolidated financial statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally accepted in the United States. In many cases, the accounting treatment of a particular transaction is specifically dictated by generally accepted accounting principles. In other circumstances, we are required to make estimates, judgments and assumptions that we believe are reasonable based upon 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. We believe that of our significant accounting policies discussed in Note 2 to our consolidated financial statements, the following may involve estimates that are inherently more subjective.

Carrying Value of Vessels. We depreciate our tugs, tank barges, OSVs, and MPSVs over estimated useful lives of 14 to 25 years, 25 years, ten to 25 years and 25 years, respectively. The shorter useful lives relate to acquired vessels. Salvage values for marine equipment range between 5% and 25% of the originally recorded cost, depending on vessel type. The useful lives used for double-hulled tank barges is 25 years. In assigning depreciable lives to these assets, we have considered the effects of both physical deterioration largely caused by wear and tear due to operating use and other economic and regulatory factors that could impact commercial viability. To date, our experience confirms that these policies are reasonable, although there may again be events or changes in circumstances in the future that indicate that recovery of the carrying amount of our vessels might not be possible. We review for impairment of our vessels by asset group. Vessels with similar operating and marketing characteristics are grouped for asset impairment review. For vessels that are not expected to be placed back into service, the impairment review is performed on a vessel-by-vessel basis. Examples of events or changes in circumstances that could indicate that the recoverability of the carrying amount of our asset groups should be assessed might include a change in regulations such as OPA 90, a significant decrease in the market value of the asset group and current period operating or cash flow losses combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the asset group. If events or changes in circumstances as set forth above indicate that the asset group’s carrying amount may not be recoverable, we would then be required to estimate the undiscounted future cash flows expected to result from the use of the asset group and its eventual disposition. If the sum of the expected future cash flows is less than the carrying amount of the vessel, we would be required to reduce the carrying amount to fair value. Fair value is determined by using appropriate valuation techniques such as expected discounted cash flows and third-party appraisals. Please refer to Note 14 of our consolidated financial statements included herein for further discussion regarding asset impairment.

Recertification Costs. Our vessels are required by regulation to be recertified after certain periods of time. These recertification costs are incurred while the vessel is in drydock where other routine repairs and maintenance are performed and, at times, major replacements and

improvements are performed. We expense routine repairs and maintenance as they are incurred. Recertification costs can be accounted for in one of two ways: (1) defer and amortize or (2) expense as incurred. We defer and amortize recertification costs over the length of time that the recertification is expected to last, which is generally 30 months. Major replacements and improvements, which extend the vessel’s economic useful life or functional operating capability, are capitalized and depreciated over the vessel’s remaining economic useful life. Inherent in this process are judgments we make regarding whether the specific cost incurred is capitalizable and the period that the incurred cost will benefit.

Mobilization Costs. Vessels will routinely move to and from international and domestic operating areas. Mobilization costs associated with relocating vessels typically include fuel, crew costs, vessel modifications, materials and supplies, importation taxes or other pre-positioning expenses required by the customer. The extent of mobilization costs incurred to relocate a vessel is directly related to the customer contract terms and area of operation. Some of our charter agreements provide for us to recover mobilization costs through either direct reimbursement or higher dayrates charged to our customers. Unless mobilization costs are rebillable to customers, we expense these costs as incurred.

Revenue Recognition. We charter our vessels to customers under time charters based on a daily rate of hire and recognize revenue as earned on a daily basis during the contract period of the specific vessel. We also contract our Downstream vessels to customers under COAs, under which revenue is recognized based on the number of days incurred for the voyage as a percentage of total estimated days applied to total estimated revenues. Voyage related costs are expensed as incurred. Substantially all voyages under COAs are less than 10 days in length.

Allowance for Doubtful Accounts. Our customers are primarily major and independent, domestic and international, oil and gas and oil service companies. Our customers are granted credit on a short-term basis and related credit risks are considered minimal. We usually do not require collateral. We provide an estimate for uncollectible accounts based primarily on management’s judgment. Management uses historical losses, current economic conditions and individual evaluations of each customer to make adjustments to the allowance for doubtful accounts. Our historical losses have not been significant. However, because amounts due from individual customers can be significant, future adjustments to the allowance can be material if one or more individual customer’s balances are deemed uncollectible.

Income Taxes. We follow accounting standards for income taxes as set forth by the Financial Accounting Standards Board, which requires the use of the liability method of computing deferred income taxes. Under this method, deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The assessment of the realization of deferred tax assets, particularly those related to tax net operating loss carryforwards, involves the use of management’s judgment to determine whether it is more likely than not that we will realize such tax benefits in the future. In addition, each reporting period, we assess and adjust for any significant changes to our liability for unrecognized income tax benefits. We account for any interest and penalties relating to uncertain tax positions in general and administrative expenses.

Stock-Based Compensation Expense. In accordance with accounting standards set forth by the Financial Accounting Standards Board, all share-based payments to employees and directors, including grants of stock options and restricted stock, are recognized in the income statement based on their fair values at the date of grant.

Convertible Senior Notes. Effective January 1, 2009, we retroactively applied new accounting rules set forth by the Financial Accounting Standards Board regarding the Company’s 1.625% convertible senior notes due 2026, or convertible senior notes. The new requirements state that the liability and equity components of a convertible debt instrument that may be settled in cash upon conversion be accounted for separately so that an entity’s accounting reflects additional non-cash original issue discount, or OID, interest expense to match the non-convertible debt borrowing rate when interest cost is recognized in subsequent periods. We applied a non-convertible debt borrowing rate of 7.125% upon adoption of these new rules based on quoted market prices for our 6.125% senior notes due 2014 on the date the convertible senior notes were issued. The impact of this requirement has resulted in a material increase to our non-cash OID interest expense for financial statements covering the periods ended December 31, 2006 through December 31, 2013. The additional interest costs are being amortized over the period ending November 15, 2013, which is the date that the convertible senior notes are first putable by the convertible note holders.

Legal Contingencies. We are involved in a variety of claims, lawsuits, investigations and proceedings, as described in Note 10 to our consolidated financial statements. We determine whether an estimated loss from a contingency should be accrued by assessing whether a loss is deemed probable and can be reasonably estimated. We assess our potential liability by analyzing our litigation and regulatory matters using available information. We develop our views on estimated losses in consultation with outside counsel handling our defense in these matters, which involves an analysis of potential results, assuming a combination of litigation and settlement strategies. Should developments in any of these matters cause a change in our determination such that we expect an unfavorable outcome and result in the need to recognize a material accrual, or should any of these matters result in a final adverse judgment or be settled for a significant amount, they could have a material adverse effect on our results of operations in the period or periods in which such change in determination, judgment or settlement occurs.

Results of Operations

The tables below set forth, by segment, the average dayrates, utilization rates and effective dayrates for our vessels and the average number and size of vessels owned during the periods indicated. These new generation OSVs and tank barges generate a substantial majority of our revenues and operating profit. Excluded from the OSV information below is the results of operations for our MPSVs, conventional vessels, our shore-base facility, and vessel management services. Since our MPSVs are relatively new, we have not had the opportunity to have all four MPSVs working in a non-moratorium (de facto or otherwise) market environment or to fully develop the market’s understanding of their capabilities and various service offerings. This makes it difficult to predict the dayrate and utilization profile of these MPSVs under normal operating conditions and, therefore, the income generating potential that these MPSVs could have on our results of operations. Nevertheless, due to the fact that each of our MPSVs have a workload capacity and significantly higher income generating

potential than each of the Company’s new generation OSVs, the utilization and dayrate levels of our MPSVs could have a very large impact on our results of operations. For this reason, our consolidated operating results, on a period-to-period basis, are disproportionately impacted by the level of dayrates and utilization achieved by our four MPSVs.


	Years Ended December 31,
	2011			2010			2009
Offshore Supply Vessels:
Average number of new generation OSVs⁽¹⁾		51.0			49.9			43.2
Average number of active new generation OSVs⁽²⁾		41.8			42.4			39.2
Average new generation OSV fleet capacity (DWT)		128,190			124,965			105,858
Average new generation vessel capacity (DWT)		2,514			2,507			2,448
Average new generation OSV utilization rate⁽³⁾		71.5	%		71.6	%		79.9	%
Effective new generation OSV utilization rate⁽⁸⁾		87.2	%		84.3	%		88.0	%
Average new generation OSV dayrate⁽⁴⁾	$	21,121		$	21,561		$	21,348
Effective dayrate⁽⁵⁾	$	15,102		$	15,438		$	17,057
Double-hulled Tank Barges:
Average number of double-hulled tank barges⁽⁶⁾		9.0			9.0			9.0
Average fleet capacity (barrels)		884,621			884,621			884,621
Average barge size (barrels)		98,291			98,291			98,291
Average utilization rate⁽³⁾		88.1	%		80.5	%		71.5	%
Average dayrate⁽⁷⁾	$	17,557		$	17,502		$	21,138
Effective dayrate⁽⁵⁾	$	15,468		$	14,089		$	15,114

(1)

We owned 51 new generation OSVs as of December 31, 2011. Our average number of new generation OSVs for the years ended December 31, 2011, 2010, and 2009 reflect the deliveries of several vessels under our fourth OSV newbuild program. During 2010 and 2009, we placed in service four OSVs and eight OSVs, respectively. Please refer to the New Generation OSVs table on page 4 of this Form 10-K for more information about vessel names and placed in service dates. Excluded from this data are ten conventional OSVs that were acquired in August 2007, nine of which were sold on various dates since 2008. We consider our remaining conventional OSV to be a non-core asset.

(2)

In response to weak market conditions, we elected to stack certain of our new generation OSVs on various dates in 2009 and 2010. Based on improved market conditions, we had re-activated 10 new generation OSVs as of December 31, 2011 and had re-activated one additional new generation OSV in January 2012. We also plan to unstack the remaining four vessels by the end of the first half of 2012, provided that we are able to re-crew such vessels and complete any required drydocking activities within that timeframe. Active new generation OSVs represent vessels that are immediately available for service during each respective period.

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

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

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

(6)

Other operating data for tugs and tank barges reflects our active Downstream fleet of nine double-hulled barges and nine ocean-going tugs. We also own six older, lower-horsepower tugs, which we consider to be non-core assets and are marketed for sale. We previously owned a fleet of single-hulled tank barges; however, all of those vessels have been sold as they were also considered non-core assets.

(7)

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

(8)	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.

YEAR ENDED DECEMBER 31, 2011 COMPARED TO YEAR ENDED DECEMBER 31, 2010

Summarized financial information concerning our reportable segments for the years ended December 31, 2011 and 2010, respectively, is shown below in the following table (in thousands, except percentage changes):


	Year Ended December 31,					Increase (Decrease)
	2011			2010		$ Change			% Change
Revenues:
Upstream
Domestic	$	182,226		$	298,400	$	(116,174	)		(38.9)	%
Foreign		148,610			76,127		72,483			95.2

		330,836			374,527		(43,691	)		(11.7)	%

Downstream
Domestic		42,866			42,854		12			0.0	%
Foreign⁽¹⁾		7,925			3,423		4,502			>100.0

		50,791			46,277		4,514			9.8

	$	381,627		$	420,804	$	(39,177	)		(9.3)	%

Operating expenses:
Upstream	$	177,868		$	166,349	$	11,519			6.9	%
Downstream		33,333			30,422		2,911			9.6

	$	211,201		$	196,771	$	14,430			7.3	%

Depreciation and amortization:
Upstream	$	67,910		$	64,685	$	3,225			5.0	%
Downstream		13,677			12,370		1,307			10.6

	$	81,587		$	77,055	$	4,532			5.9	%

General and administrative expenses:
Upstream	$	32,170		$	33,956	$	(1,786	)		(5.3)	%
Downstream		3,193			2,818		375			13.3

	$	35,363		$	36,774	$	(1,411	)		(3.8)	%

Gain on sale of assets:
Upstream	$	980		$	986	$	(6	)		(0.6)	%
Downstream		559			1,039		(480	)		(46.2)

	$	1,539		$	2,025	$	(486	)		(24.0)	%

Operating income:
Upstream	$	53,868		$	110,523	$	(56,655	)		(51.3)	%
Downstream		1,147			1,706		(559	)		(32.8)

	$	55,015		$	112,229	$	(57,214	)		(51.0)	%

Interest expense	$	59,649		$	55,183	$	4,466			8.1	%

Interest income	$	829		$	528	$	301			57.0	%

Income tax expense (benefit)	$	(802	)	$	21,502	$	(22,304	)		>(100.0)	%

Net income (loss)	$	(2,561	)	$	36,416	$	(38,977	)		>(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.

Revenues. Revenues for 2011 decreased by $39.2 million, or 9.3%, to $381.6 million compared to $420.8 million for 2010. After the Deepwater Horizon incident, regulatory-driven declines in demand for our Upstream vessels in the GoM resulted in a significant reduction in MPSV revenues, which accounted for substantially all of our consolidated revenue decrease from 2010. The reduced drilling activity in the GoM also led to our decision to stack certain new generation OSVs. Our weighted-average active operating fleet for 2011 was approximately 64 vessels compared to 65 vessels for 2010.

Revenues from our Upstream segment decreased by $43.7 million, or 11.7%, to $330.8 million for 2011 compared to $374.5 million for 2010. These lower revenues primarily resulted from a significant decline in activity from our MPSVs, lower revenue from new generation OSVs that were in-service during each of the years ended December 31, 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. Days worked for our MPSV fleet declined by 28% to 692 days for 2011 compared to 2010. However, MPSV utilization was 88.7% for the fourth quarter of 2011. Our new generation OSV average dayrates were $21,121 for 2011 compared to $21,561 for 2010, a decrease of $440, or 2.0%. Our new generation OSV dayrates for 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 $20,756, or 1.8% lower than 2011. Our new generation OSV utilization was 71.5% for 2011 compared to 71.6% for 2010. During 2011, our average OSV utilization was adversely affected by roughly 3,300 days out-of-service related to stacked vessels and 528 days of aggregate downtime related to customer-required modifications and pre-positioning of eight vessels that were mobilized to foreign markets during 2011. The deepwater drilling moratorium and de facto regulatory moratorium in the GoM also contributed to the lower Upstream utilization. We had an average of 9.2 new generation OSVs stacked during 2011 compared to an average of 7.5 stacked vessels during the prior-year. Domestic revenues for our Upstream segment decreased $116.2 million during 2011 due to reduced drilling activity in the GoM. Foreign revenues for our Upstream segment increased $72.5 million primarily due to an average of 11 additional vessels deployed to Latin America since December 31, 2010. Foreign revenues comprised 44.9% of our total Upstream revenues compared to 20.3% for 2010.

Revenues from our Downstream segment increased by $4.5 million, or 9.8%, to $50.8 million for 2011 compared to $46.3 million for 2010. This revenue increase was due to higher demand for our clean and dirty petroleum product barges in the Northeast during 2011 compared to 2010 and, to a lesser extent, fewer days out-of-service for regulatory drydocking during 2011. Our double-hulled tank barge average dayrates were $17,557 for 2011, which was slightly higher than $17,502 for 2010. Our double-hulled tank barge utilization was 88.1% for 2011 compared to 80.5% for 2010. Foreign revenues for our Downstream segment increased $4.5 million, or 131.5%, due to an additional vessel deployed to Puerto Rico during 2011 compared to the prior-year.

Operating expenses. Operating expenses for 2011 increased by $14.4 million, or 7.3%, to $211.2 million. This increase was primarily associated with $9.5 million of higher costs for vessels mobilizing to international markets during 2011.

Operating expenses for our Upstream segment were $177.9 million, an increase of $11.5 million, or 6.9%, for 2011 compared to $166.3 million for 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 in foreign markets during 2011 partially offset by lower costs associated with our MPSV fleet and decreased activity at our shore-base port facility. We incurred mobilization costs of $9.5 million and $9.7 million during 2011 and 2010, respectively, associated with the mobilization and pre-positioning of vessels in foreign locations. For the twelve months ended December 31, 2011, we had an average active new generation OSV fleet of 41.8 vessels compared to 42.4 vessels for the same period in 2010. Aggregate cash operating expenses for our Upstream segment are projected to be in the range of $200.0 million and $210.0 million for 2012, inclusive of approximately $0.3 million expected to be incurred for our inactive stacked OSVs. Our cash operating expense estimate is exclusive of any additional repositioning expenses we may incur that are not recoverable through charter hire in connection with the potential relocation of more of our vessels into international markets; or any customer-required cost-of-sales related to future contract fixtures that are typically recovered through higher dayrates.

Operating expenses for our Downstream segment were $33.3 million, an increase of $2.9 million, or 9.6%, for 2011 compared to $30.4 million for 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 (COA) charters during 2011. Vessel owners typically bear the fuel costs under COA arrangements while customers are usually responsible for fuel costs under time charter contracts.

Depreciation and Amortization. Depreciation and amortization was $4.5 million higher for 2011 compared to 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 and, to a lesser extent, the incremental amortization resulting from higher shipyard costs to drydock our Upstream and Downstream vessels. In addition, amortization expense was higher during 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 $35.4 million, or 9.3% of revenues, decreased by $1.4 million during 2011 compared to 2010. This decrease in G&A expenses were primarily the result of lower shoreside incentive compensation. Our general and administrative expenses are expected to increase to the approximate annual range of $48 million to $52 million for 2012, commensurate with our pending fleet growth and international expansion. However, we still expect our G&A expenses as a percentage of revenues, or G&A margin, to remain within the historical range of our domestic public company OSV peer group.

Gain on Sale of Assets. During 2011, we sold our four remaining 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 ($1.1 million after-tax or $0.04 per diluted share). During 2010, we sold two conventional OSVs, one older, lower-horsepower tug, and two single-hulled tank barges for net cash proceeds of $4.5 million, which resulted in aggregate gains of approximately $1.9 million ($1.2 million after-tax or $0.04 per diluted share).

Operating Income. Operating income decreased by $57.2 million to $55.0 million during 2011 compared to 2010 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 16.3% for 2011 compared to 29.5% for 2010. Excluding roughly $9.5 million of incremental operating costs as a result of mobilizing vessels to foreign markets, our operating income as a percentage of revenues for our Upstream segment would have been 19.2% for 2011. Operating income as a percentage of revenues for our Downstream segment was 2.2% for 2011 compared to 3.7% for 2010.

Interest Expense. Interest expense increased $4.5 million during 2011 compared to 2010, although our outstanding debt did not change from the prior-year. Lower capitalized interest from having fewer vessels under construction or conversion was the primary reason that our interest expense increased from 2010. During 2011, we capitalized interest of $0.4 million, or roughly 1% of our total interest costs compared to capitalized interest of $3.7 million, or roughly 6% of our total interest costs, for 2010. See “Liquidity and Capital Resources” for further discussion.

Interest Income. Interest income increased by $0.3 million to $0.8 million for 2011 compared to $0.5 million for 2010. Our average cash balance increased to $189.5 million for 2011 compared to $82.7 million for 2010. The average interest rate earned on our invested cash balances during 2011 was approximately 0.4% compared to 0.6% for 2010.

Income Tax Expense (Benefit). Our effective tax rate was 23.8% and 37.1% for 2011 and 2010, respectively. The benefit rate for 2011 is less than the tax rate for 2010 due to the amplified effect of our permanent book tax differences on the relatively smaller pre-tax book income (loss) for 2011 compared to 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 $39.0 million for a reported net loss of $2.6 million for 2011. The net loss incurred for 2011 was primarily due to a decrease in operating income discussed above and a $4.2 million pre-tax increase in net interest expense.

YEAR ENDED DECEMBER 31, 2010 COMPARED TO YEAR ENDED DECEMBER 31, 2009

Summarized financial information concerning our reportable segments for the years ended December 31, 2010 and 2009, respectively, is shown below in the following table (in thousands, except percentage changes):


	Year Ended December 31,					Increase (Decrease)
	2010		2009			$ Change			% Change
Revenues:
Upstream
Domestic	$	298,400	$	274,782		$	23,618			8.6	%
Foreign		76,127		51,875			24,252			46.8

		374,527		326,657			47,870			14.7

Downstream
Domestic		42,854		58,050			(15,196	)		(26.2	)
Foreign⁽¹⁾		3,423		1,241			2,182			>100.0

		46,277		59,291			(13,014	)		(21.9	)

	$	420,804	$	385,948		$	34,856			9.0	%

Operating expenses:
Upstream	$	166,349	$	121,488		$	44,861			36.9	%
Downstream		30,422		39,700			(9,278	)		(23.4	)

	$	196,771	$	161,188		$	35,583			22.1	%

Depreciation and amortization:
Upstream	$	64,685	$	50,740		$	13,945			27.5	%
Downstream⁽²⁾		12,370		42,629			(30,259	)		(71.0	)

	$	77,055	$	93,369		$	(16,314	)		(17.5	)%

General and administrative expenses:
Upstream	$	33,956	$	25,641		$	8,315			32.4	%
Downstream		2,818		5,203			(2,385	)		(45.8	)

	$	36,774	$	30,844		$	5,930			19.2	%

Gain on sale of assets:
Upstream	$	986	$	111		$	875			>100.0	%
Downstream		1,039		1,036			3			0.3

	$	2,025	$	1,147		$	878			76.5	%

Operating income:
Upstream	$	110,523	$	128,899		$	(18,376	)		(14.3	)%
Downstream		1,706		(27,205	)		28,911			>100.0

	$	112,229	$	101,694		$	10,535			10.4	%

Interest expense	$	55,183	$	21,024		$	34,159			>100.0	%

Interest income	$	528	$	482		$	46			9.5	%

Income tax expense	$	21,502	$	30,155		$	(8,653	)		(28.7	)%

Net income	$	36,416	$	50,400		$	(13,984	)		(27.7	)%

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

(2)

Included in depreciation and amortization, for the year ended December 31, 2009, is a pre-tax non-cash asset impairment charge of $25.8 million related to ten single-hulled tank barges and six ocean-going tugs as well as a $0.9 million pre-tax non-cash charge for the write-off of remaining goodwill associated with this segment.

Revenues. Revenues for 2010 increased by $34.9 million, or 9.0%, to $420.8 million compared to 2009 primarily due to the full and partial-period contribution of newbuild and converted Upstream vessels that were added to our fleet since January 1, 2009. Although we added 14 vessels to our fleet from early 2009 to the end of 2010, our weighted-average active operating fleet as of December 31, 2010 was approximately 65 vessels compared to 66 vessels for the same period in 2009 as a result of vessels that were stacked, sold or retired during 2009 and 2010.

Revenues from our Upstream segment increased by $47.9 million, or 14.7%, to $374.5 million for 2010 compared to $326.7 million for 2009. The vessels placed in service under our newbuild and conversion programs accounted for a $98.5 million increase in Upstream revenues. These incremental revenues were offset by an $18.3 million decrease in revenue primarily from lower effective dayrates for our new generation OSVs that were in service during each of the years ended December 31, 2010 and 2009 and a $32.3 million decrease in revenue for our new generation and conventional OSVs that were in service during 2009, but have either been stacked or sold on various dates since then and decreased activity at our shore-base port facility. Our new generation OSV average dayrates of $21,561 for 2010 were in-line with dayrates of $21,348 for 2009. Our new generation OSV dayrates for the year ended December 31, 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 new generation OSV dayrates would have been $20,756, or 2.7% lower than the prior-year. This decrease in comparable dayrates is largely due to contracts that expired in 2009 and early 2010 having terms that were negotiated during stronger OSV market conditions. Several OSV time charter contracts that were in effect during 2009 and previously fixed in 2008 at dayrates in the range of $20,000 to $36,000 were replaced or renewed with spot time charters at dayrates that were roughly 50% lower than their previously contracted rates. Our new generation OSV utilization was 71.6% for 2010 compared to 79.9% for 2009. The decline in utilization was driven by weaker GoM OSV market conditions, which was further exacerbated by the federal drilling moratorium and de facto regulatory moratorium in the deepwater GoM. In addition, we had 962 incremental days out-of-service to ready eight OSVs for long-term charters in Latin America. Domestic revenues for our Upstream segment increased $23.6 million during 2010 due to the full or partial-period contribution of eleven additional OSVs and three additional MPSVs that were placed in service on various dates since January 1, 2009. This increase was partially offset by an average of 7.5 new generation OSVs being stacked during 2010 compared to an average of 4.1 new generation OSVs being stacked during 2009. Foreign revenues for our Upstream segment increased $24.3 million due to five additional vessels deployed to foreign markets since 2009. For the year ended December 31, 2010, oil spill response activities accounted for approximately $89.6 million of our Upstream revenues.

Revenues from our Downstream segment decreased by $13.0 million, or 21.9%, to $46.3 million for 2010 compared to $59.3 million for 2009. The partial-period revenue contribution from single-hulled tank barges that were in service during 2009, but have been retired, stacked or sold since then, accounted for $9.6 million of the Downstream revenue decline. The remaining $3.4 million decrease in 2010 Downstream revenues was largely due to well-test contract cancellation fees recognized during 2009. Such fees typically represent customer revenue that we would have otherwise earned over a contract term for specialty services contracts. Well-test contract cancellations are not uncommon for these types of high

profile specialty service projects and will likely occur again in the future. However, we had no such well-test contract cancellations during 2010. Excluding the well-test contract cancellation revenues, our Downstream revenues for 2010 would have decreased $7.6 million, or 12.8% from 2009. Our Downstream revenues for 2010 were favorably impacted by one of our double-hulled tank barges performing well-test services for an Upstream customer in the GoM and having up to five double-hulled tank barges temporarily contracted by BP to support oil skimming operations in the GoM. Our double-hulled tank barge average dayrates were $17,502 for 2010, a decrease of $3,636, or 17.2%, from $21,138 for 2009. Excluding the incremental revenues associated with well-test revenue in 2010 and 2009, double-hulled tank barge average dayrates would have been $16,640 and $18,840, respectively. Our double-hulled tank barge utilization was 80.5% for 2010 compared to 71.5% for 2009. The increase in double-hulled tank barge utilization was primarily driven by the temporary increase in demand related to our oil spill recovery efforts in the GoM during 2010. For the year ended December 31, 2010, oil spill response activities accounted for approximately $12.5 million of our Downstream revenues.

Operating expenses. Operating expenses for 2010 increased by $35.6 million, or 22.1%, to $196.8 million. This increase was primarily associated with adding eleven new generation OSVs and three MPSVs to our active fleet since 2009 under our fourth OSV newbuild program and MPSV program, respectively. Through vessel sales or stacking, we have partially offset these higher operating costs by removing Upstream and Downstream equipment from our operating fleet.

Operating expenses for our Upstream segment were $166.3 million, an increase of $44.9 million, or 36.9%, for 2010 compared to $121.5 million for 2009. Newly constructed vessels placed in service since 2009 accounted for approximately $38.7 million of the higher operating costs. Vessels that operated during all of 2009 and 2010 accounted for approximately $18.5 million of the operating expense variance, which primarily resulted from pre-positioning costs for vessels operating in Latin America. Included in these pre-positioning costs was industry-wide Brazilian importation and regulatory review delays which resulted in higher than expected days out-of-service, and mobilization costs of approximately $9.7 million associated with placing eight vessels on charter in Brazil. These increases were partially offset by approximately $12.3 million in operating expense decreases resulting from a reduction of our operating fleet through vessel sales or stacking and decreased activity at our shore-base port facility. Excluding vessels that were mobilizing to Brazil, operating expenses were flat for vessels that were in-service during all of 2009 and 2010.

Operating expenses for our Downstream segment were $30.4 million, a decrease of $9.3 million, or 23.4%, for 2010 compared to $39.7 million for 2009. The decrease in operating expenses for the Downstream segment is primarily associated with the lower cost of maintaining equipment that was stacked, sold or retired from service since 2009. Operating expenses for our twelve active double-hulled tank barges and associated tugs was down approximately $2.6 million for 2010 compared to 2009.

Depreciation and Amortization. Depreciation and amortization was $16.3 million lower for 2010 compared to 2009 due to the $26.7 million asset and goodwill impairment charges for our Downstream segment recorded during the second quarter of 2009. In addition, we incurred incremental depreciation in 2010 related to eleven OSVs placed in service under our

fourth OSV newbuild program and three MPSVs placed in service under our MPSV program since 2009. 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 $36.8 million, or 8.7% of revenues, increased by $5.9 million during 2010 compared to 2009. This increase is primarily the result of higher personnel and stock-based compensation expense costs recorded during 2010.

Gain on Sale of Assets. During 2010, we sold two conventional OSVs, one older, lower-horsepower tug, and two single-hulled tank barges for net cash proceeds of $4.5 million, which resulted in aggregate gains of approximately $1.9 million ($1.2 million after-tax or $0.04 per diluted share). During 2009, we sold one older, lower-horsepower tug, six single-hulled tank barges, and three conventional OSVs for net cash proceeds of $10.6 million, which resulted in aggregate gains of approximately $1.1 million ($0.7 million after-tax or $0.03 per diluted share).

Operating Income. Operating income increased by $10.5 million, or 10.4%, to $112.2 million during 2010 compared to 2009 due to the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 29.5% for 2010 compared to 39.5% for 2009. The primary driver for this margin decrease relates to operating costs associated with the mobilization of eight vessels to Latin America. We recorded operating income of $1.7 million for our Downstream segment for 2010, compared to an operating loss of $27.2 million for 2009. Excluding the asset and goodwill impairment charges noted above, the Downstream segment operating loss for 2009 would have been $0.5 million.

Interest Expense. Interest expense increased $34.2 million during 2010 compared to 2009. This increase was driven by incremental interest resulting from our 8.000% senior notes due 2017, which were issued in August 2009, and lower capitalized interest driven by having fewer vessels under construction in our newbuild and conversion programs. See “Liquidity and Capital Resources” for further discussion.

Interest Income. Interest income increased 9.5% during 2010 compared to 2009. The average interest rate earned on our invested cash balances during 2010 was approximately 0.6% compared to 1.1% for 2009. Although we earned lower rates on our invested cash balances, our average cash balance increased to $82.7 million for 2010 compared to $36.2 million for 2009.

Income Tax Expense. Our effective tax rate was 37.1% and 37.4% for 2010 and 2009, respectively. Our income tax expense primarily consists of deferred taxes. Our income tax rate is higher than the federal statutory rate primarily due to expected state tax liabilities and items not deductible for federal income tax purposes.

Net Income. Net income decreased by $14.0 million, or 27.7%, to $36.4 million for 2010 compared to 2009 primarily due to a $34.1 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, obligations under our fifth OSV newbuild program, vessel recertifications, discretionary capital expenditures and debt service and may require capital to fund potential future vessel construction, retrofit or conversion projects or acquisitions. The nature of our capital requirements and the types of our financing sources are not expected to change significantly for 2012. 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, which is expected for our four remaining stacked new generation OSVs by the end of the first half of 2012.

We have reviewed all of our debt agreements as well as our liquidity position and projected future cash needs. Despite volatility in financial and commodity markets, we remain confident in our current financial position, the strength of our balance sheet and the short- and long-term viability of our business model. To date, our liquidity has not been materially impacted and we do not expect that it will be materially impacted in the near-future due to such volatility. We believe that our cash on-hand, projected operating cash flow and available borrowing capacity under our recently amended revolving credit facility will be more than sufficient to operate the Company and meet all of its near-term obligations, including milestone construction payments required under our fifth OSV newbuild program.

Although we expect to continue generating positive working capital through our operations, events beyond our control, such as further regulatory-driven delays in the issuance of drilling plans and permits in the GoM , declines in expenditures for exploration, development and production activity, mild winter conditions or any extended reduction in domestic consumption of refined petroleum products and other reasons discussed under the “Forward Looking Statements” on page ii and the Risk Factors stated in Item 1A of this Annual Report on Form 10-K, may affect our financial condition, results of operations or cash flows. None of our funded debt instruments mature any sooner than November 2013. Our currently undrawn revolving credit facility now matures in November 2016, provided that we meet certain liquidity and bond refinancing conditions required by such facility. See further discussion of these refinancing conditions in the Contractual Obligations section below. Depending on the market demand for our vessels, long-term debt maturities and other growth opportunities that may arise, we may require additional debt or equity financing. We currently expect to generate sufficient cash to meet our obligations under our fifth OSV newbuild program and we expect to refinance senior debt as market conditions warrant. To the extent we do not refinance such debt, we currently expect to generate sufficient cash to re-pay our long-term debt upon maturity. However, it is possible that, due to events beyond our control, including those described in our Risk Factors, should such need for additional financing arise, we may not be able to access the capital markets on attractive terms at that time or otherwise obtain sufficient capital to meet our maturing debt obligations or finance growth opportunities that may arise. We will continue to closely monitor our liquidity position, as well as the state of the global capital and credit markets.

On November 16, 2011, we completed an underwritten public offering of 8.1 million shares of our common stock at $30.00 per share, for total gross proceeds of $241.5 million

before underwriting discounts, commissions and offering expenses. This includes 1,050,000 additional shares of common stock purchased pursuant to the exercise in full of the underwriters’ over-allotment option. Underwriting discounts, commissions and offering expenses of approximately $11.4 million were recorded as a reduction of additional paid-in capital. We intend to use net proceeds from the offering to partially fund our fifth OSV newbuild program. The aggregate cost of this program, excluding construction period interest, is expected to be approximately $720.0 million, of which $242.9 million, $347.7 million and $87.0 million is expected to be incurred in 2012, 2013 and 2014, respectively. From the inception of our fifth OSV newbuild program through December 31, 2011, we have incurred $42.4 million, or 5.9%, of total expected project costs. In addition, offering proceeds may be used in connection with possible future acquisitions and additional new vessel construction, as well as for general corporate purposes.

As of December 31, 2011, we had total cash and cash equivalents of $356.8 million. 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. As of December 31, 2011, we had a posted letter of credit for $0.9 million and had $299.1 million of credit available under our revolving credit facility. The full undrawn credit amount of such facility is available for its intended uses, which are the acquisition of assets that generate additional EBITDA and the potential repayment of existing long-term debt.

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 $63.7 million in 2011, $131.0 million in 2010, and $183.2 million in 2009. Operating cash flows in 2011 were unfavorably affected by a decrease in demand for our Upstream equipment, including our MPSVs, primarily due to regulatory-driven market weakness in the GoM. Operating cash flows decreased in 2010 compared to 2009 mainly due to a decline in effective dayrates and utilization for our Upstream and Downstream segments, which was partially offset by the growth of our Upstream fleet. Cash flows from operations for 2011 reflect full-period contributions from four additional new generation OSVs and one MPSV that were placed in service between January 1, 2010 and December 31, 2011. Cash flows from operations for 2010 reflect full and partial-period contributions from eleven additional new generation OSVs and three MPSVs that were placed in service between January 1, 2009 and December 31, 2010. Cash flows from operations for 2009 reflect full- and partial-period contributions from eight additional new generation OSVs and two MPSVs that were placed in service between January 1, 2008 and December 31, 2009.

Investing Activities. Net cash used in investing activities was $62.3 million in 2011, $57.0 million in 2010, and $263.1 million in 2009. Cash utilized during 2011 primarily consisted of construction costs incurred for our fifth OSV newbuild program and capital improvements made to our existing 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 2010 primarily consisted of construction costs incurred for our fourth OSV newbuild program and our MPSV program, which were partially offset by approximately $4.7 million in aggregate net cash proceeds from the sale of two conventional

OSVs, one older, lower-horsepower tug, two single-hulled barges, and other non-revenue generating equipment. Cash utilized during 2009 primarily consisted of construction costs incurred for our fourth OSV newbuild program and our MPSV program, which were partially offset by approximately $10.6 million in net cash proceeds from the sale of three conventional OSVs, six single-hulled barges and one older, lower-horsepower tug.

Financing Activities. Net cash provided by financing activities was $228.8 million in 2011, $1.9 million in 2010, and $110.6 million in 2009. Net cash provided by financing activities for 2011 primarily resulted from our November 2011 public offering of 8.1 million shares of our common stock resulting in net proceeds of approximately $230.1 million. Net cash provided by financing activities for 2010 primarily resulted from proceeds from common shares issued pursuant to our employee stock-based compensation plans. Net cash provided by financing activities for 2009 is primarily the result of approximately $237.3 million in net proceeds in connection with a private placement of $250.0 million in 8.000% senior notes offset by net payments on our revolving credit facility.

Commitments and Contractual Obligations

The following table sets forth our aggregate contractual obligations as of December 31, 2011 (in thousands).


Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		Thereafter
Vessel construction commitments⁽¹⁾	$	677,285	$	242,882	$	434,403	$	—	$	—
6.125% senior notes⁽²⁾		300,000		—		300,000		—		—
8.000% senior notes⁽³⁾		250,000		—		—		—		250,000
1.625% convertible senior notes⁽⁴⁾		250,000		—		—		—		250,000
Interest payments⁽⁵⁾		199,330		42,438		82,706		40,245		33,941
Operating leases⁽⁶⁾		33,949		3,176		4,227		2,469		24,077

Total	$	1,710,564	$	288,496	$	821,336	$	42,714	$	558,018

(1)

Vessel construction commitments reflect contractual milestone payments for our fifth OSV newbuild program. The total project costs for this 16-vessel program are expected to be $720.0 million, excluding capitalized construction period interest. From the inception of this program through December 31, 2011, we have incurred $42.4 million, or 5.9%, of total expected project costs, all of which was incurred during the fourth quarter of 2011.

(2)	Our 6.125% senior notes mature on December 1, 2014 and include $215 of original issue discount.

(3)	Our 8.000% senior notes mature on September 1, 2017 and include $5,571 of original issue discount.

(4)

Our 1.625% convertible senior notes, with an initial interest rate of 1.625% per year, declining to 1.375% beginning on November 15, 2013, mature on November 15, 2026 and currently include $23,566 of non-cash original issue discount. Holders of the convertible senior notes may require that such notes be repurchased at their option on November 15, 2013, 2015 and 2021, pursuant to certain conditions described in Note 6 of our consolidated financial statements included herein. The debt maturities reflected in the table above assume that the holders of our convertible senior notes do not require that such notes be repurchased prior to their maturity in November 2026.

(5)

Interest payments relate to our 6.125% senior notes due December 1, 2014, our 8.000% senior notes due September 1, 2017 and our 1.625% convertible senior notes due November 15, 2026 with semi-annual interest payments of $9.2 million payable June 1 and December 1, $10.0 million payable March 1 and September 1, and $2.0 million payable May 15 and November 15, respectively. The semi-annual interest payments for our convertible senior notes will decline to $1.7 million for interest payments made after November 15, 2013. Effective January 1, 2009, we adopted new accounting standards which require us to record additional non-cash interest expense. Non-cash interest expense has been excluded from the table above.

(6)	Included in operating leases are commitments for vessel rentals, a shore-base port facility, office space, office equipment and vehicles. See “—Properties” for additional information regarding our leased office space and other facilities.

Debt

As of December 31, 2011, we had total debt of $770.6 million, net of original issue discount of $29.4 million. Our debt, net of original issue discount, is comprised of $299.8 million of our 6.125% senior notes due 2014, or 2014 senior notes, $244.4 million of our 8.000% senior notes due 2017, or 2017 senior notes, and $226.4 million of our 1.625% convertible senior notes due 2026, or convertible senior notes. The effective interest rate on the 2014 senior notes is 6.39% with semi-annual cash interest payments of $9.2 million due and payable each June 1 and December 1. The effective interest rate on the 2017 senior notes is 8.63% with semi-annual cash interest payments of $10.0 million due and payable each March 1 and September 1, commencing March 1, 2010. The $250.0 million, in face amount, of convertible senior notes bear interest at an annual coupon of 1.625% with semi-annual cash interest payments of $2.0 million due May 15 and November 15, declining to 1.375%, or $1.7 million semi-annually, beginning on November 15, 2013. The effective interest rate on such notes is 6.36%. The senior notes do not require any payments of principal prior to their stated maturity dates, but pursuant to the each indenture under which the 2014 senior notes and 2017 senior notes were issued, we would be required to make offers to purchase such senior notes upon the occurrence of specified events, such as certain asset sales or a change in control. On March 14, 2011 we amended our revolving credit facility to modify its covenants. On November 2, 2011, we amended and extended our revolving credit facility to modify its covenants, increase its borrowing base and extend the maturity date of such facility. The $300.0 million revolving credit facility remains undrawn as of February 15, 2012. With the revolving credit facility, we have the option of borrowing at a variable rate of interest equal to either (i) the greater of the Prime Rate or the Federal Funds Effective Rate plus 1/2 of 1% or (ii) the London Interbank Offered Rate, or LIBOR; plus in each case an applicable margin. The applicable margin for each base rate is determined by a pricing grid, which is based on our leverage ratio, as defined in the credit agreement governing the revolving credit facility, as amended. The applicable LIBOR margin for the amended revolving credit facility ranges from 200 to 300 basis points. Unused commitment fees are payable quarterly at the annual rate of 37.5 to 50.0 basis points of the unused portion of the borrowing base of the new revolving credit facility, based on the defined leverage ratio. For additional information with respect to our revolving credit facility, our 2014 senior notes, our 2017 senior notes and our convertible senior notes, please refer to Note 6 of our consolidated financial statements included herein.

The credit agreement governing the 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. For the quarter ended December 31, 2011, we were in compliance with all of our debt covenants. We continuously review our debt covenants and report to our lenders our compliance with financial ratios on a quarterly basis. We also consider such covenants in evaluating transactions that will have an effect on our financial ratios.

Capital Expenditures and Related Commitments

The following table sets forth the amounts incurred for our newbuild and conversion programs, before construction period interest, during the year ended December 31, 2011 and since each program’s inception, respectively, as well as the estimated total project costs for each of our current expansion programs (in millions):


	For the Year Ended December 31, 2011		Incurred Since Inception		Estimated Program Totals⁽¹⁾		Projected Delivery Dates⁽¹⁾


Growth Capital Expenditures:
OSV Newbuild Program #5⁽²⁾	$	42.4	$	42.4	$	720.0		2Q2013-4Q2014

(1)

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

(2)

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

The following table summarizes the costs incurred, prior to the allocation of construction period interest, for the purposes set forth below for the years ended December 31, 2011, 2010, and 2009 and a forecast for 2012 (in millions):


	Year Ended December 31,
	2012		2011		2010		2009
	Forecast		Actual		Actual		Actual
Maintenance and Other Capital Expenditures:
Maintenance Capital Expenditures
Deferred drydocking charges⁽¹⁾	$	40.5	$	19.7	$	22.5	$	19.2
Other vessel capital improvements⁽²⁾		12.3		11.0		7.0		5.5

		52.8		30.7		29.5		24.7

Other Capital Expenditures
Commercial-related vessel improvements⁽³⁾		7.7		18.0		17.2		7.3
Miscellaneous non-vessel additions⁽⁴⁾		8.8		1.8		1.6		3.5

		16.5		19.8		18.8		10.8

Total:	$	69.3	$	50.5	$	48.3	$	35.5

(1)	Deferred drydocking charges for 2012 include the projected recertification costs for 25 OSVs, two MPSVs, three tank barges and four tugs.

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

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

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

Inflation

To date, general inflationary trends have not had a material effect on our operating revenues or expenses.

Item 7A—Quantitative and Qualitative Disclosures About Market Risk

We have not entered into any derivative financial instrument transactions to manage or reduce market risk or for speculative purposes, other than the convertible note hedge and warrant transactions entered into concurrently with our convertible note offering in November 2006. Such transactions were entered into to mitigate the potential dilutive effect of the conversion feature of the convertible notes on our common stock. A hypothetical 25% change from our closing share price of $31.02 as of December 31, 2011 would not have had an impact on such transactions.

Changes in interest rates may result in changes in the fair market value of our financial instruments, interest income and interest expense. Our financial instruments that are exposed to interest rate risk are cash equivalents and long-term borrowings. Due to the short duration and conservative nature of our cash equivalent investment portfolio, we do not expect any material loss with respect to our investments. The book value for cash equivalents is considered to be representative of its fair value. A hypothetical 10% change in interest rates as of December 31, 2011 would have had no material impact on such investments, interest income or interest expense.

Changes in interest rates would not impact the interest expense for our long-term fixed interest rate 6.125% senior notes, 8.000% senior notes and 1.625% convertible senior notes. However, changes in interest rates would impact the fair market value of such notes. In general, the fair market value of debt with a fixed interest rate will increase as interest rates fall. Conversely, the fair market value of debt will decrease as interest rates rise. The currently outstanding 6.125% senior notes accrue interest at the rate of 6.125% per annum and mature on December 1, 2014 and the effective interest rate on such notes is 6.39%. The currently outstanding 8.000% senior notes accrue interest at a rate of 8.000% per annum and mature on September 1, 2017 and the effective interest rate on such notes is 8.63%. Our outstanding 1.625% convertible senior notes accrue interest at the rate of 1.625%, which will decline to 1.375% beginning on November 15, 2013, and mature on November 15, 2026. The effective interest rate on such notes is 6.36%. In connection with our convertible notes, we are a party to convertible note hedge transactions with respect to our common stock with Jefferies & Company, Inc., Bear Stearns International Limited and AIG-FP Structured Finance (Cayman) Limited, or the counterparties. As a result of the financial markets crisis during the third quarter of 2008, the Bear Stearns International Limited position has been assumed by JPMorgan Chase in its acquisition of Bear Stearns and AIG-FP Structured Finance (Cayman) Limited’s parent company, or AIG, was re-capitalized by the U.S. Government. We are not currently aware of any collection issues with regard to any of these counter-parties.

We estimate the fair value of our 6.125% senior notes due 2014, our 8.000% senior notes due 2017 and our 1.625% convertible senior notes due 2026, all of which are publicly traded, by using quoted market prices. The fair value of our undrawn revolving credit facility, when there are outstanding balances, approximates its carrying value. The face value, carrying value and fair value of our total debt was $800.0 million, $770.6 million and $810.3 million, respectively, as of December 31, 2011.

As of December 31, 2011, we had no amounts outstanding under our variable interest rate revolving credit facility. Therefore it is not subject to interest rate risk.

Historically, our operations were primarily conducted between U.S. ports, including along the coast of Puerto Rico, and we were not exposed to significant foreign currency fluctuation. We have now expanded our operations into two new core markets, Brazil and Mexico. We currently have time charters for 25 of our Upstream vessels working in foreign markets. Although most of our time charter contracts are denominated U.S. Dollars, we do collect time charter payments and value added tax, or VAT, payments in local currencies for four vessels, which creates an exchange risk related to currency fluctuations. We also frequently acquire other vessel equipment for our active vessels that are denominated in foreign currencies, which creates an exchange risk to foreign currency fluctuations related to the payment terms of such commitments or purchases. To date, we have not hedged against any foreign currency rate fluctuations associated with foreign currency VAT payments or other foreign currency denominated transactions arising in the normal course of business. We continually monitor the currency exchange risks associated with conducting international operations. To date, gains or losses associated with such fluctuations have not been material. However, as we further expand our operations in international markets, we may become exposed to certain risks typically associated with foreign currency fluctuation.

Item 8—Financial Statements and Supplementary Data

The financial statements and information required by this Item appear on pages F-1 through F-33 of this Annual Report on Form 10-K.

Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

None.

Item 9A—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.

Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13(a)-15(f) or Rule15d-15(f) under the Exchange Act. Internal control over financial reporting is a process to

provide reasonable assurance regarding the reliability of our financial reporting for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes maintaining records that, in reasonable detail, accurately and fairly reflect our transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of our financial statements in accordance with U.S. generally accepted accounting principles; providing reasonable assurance that receipts and expenditures of company assets are made in accordance with authorizations of the Company’s management and board of directors; and providing reasonable assurance that unauthorized acquisition, use or disposition of company assets that could have a material effect on our financial statements would be prevented or detected on a timely basis. Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of our financial statements would be prevented or detected. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies of procedures may deteriorate.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011, utilizing the criteria set forth in the report entitled Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based upon such assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2011.

Ernst & Young LLP, an independent registered public accounting firm, who audited our consolidated financial statements included in this Form 10-K, has issued an attestation report on our internal control over financial reporting which is included herein.

There were no changes in our internal controls over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Hornbeck Offshore Services, Inc.

We have audited Hornbeck Offshore Services, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Hornbeck Offshore Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Hornbeck Offshore Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Hornbeck

Offshore Services, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2011 of Hornbeck Offshore Services, Inc. and subsidiaries and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 29, 2012

Item 9B—Other Information

Recent Events

Amendment to Employment Agreements

The Company has employment agreements with Todd M. Hornbeck, Carl G. Annessa, James O. Harp, Jr. and Samuel A. Giberga. These agreements provide for, among other things, base salaries and a structured cash incentive compensation program dependent upon the Company achieving certain targeted results. For the years 2008 through 2010, these agreements contained an EBITDA target as well as a discretionary component, established by the Compensation Committee of the Company’s Board of Directors. Notwithstanding the agreement terms, it was decided at the beginning of 2011, that cash incentive compensation would be determined solely on a discretionary basis by the Compensation Committee. In February 2012, the Appendix A to each of these employment agreements was amended, effective January 1, 2012, to add two new non-discretionary components for the determination of potential cash incentive compensation. Under the revised methodology, in addition to the EBITDA component and the discretionary component of the program, the following components were added: (i) the Company achieving an operating margin for the upstream segment equal to or greater than the average operating margin achieved by the Company’s publicly traded OSV industry peers worldwide and (ii) the Company maintaining a total recordable incident rate lower than or equal to the average of the latest available annual industry benchmarks. Under the revised methodology, the EBITDA component represents 37.5% of the aggregate potential cash incentive compensation, the operating margin component and the safety component each represents 18.75% of the aggregate potential cash incentive compensation and the discretionary component represents 25% of aggregate potential cash incentive compensation, each such percentage being referred to herein as an Applicable Percentage. Further, under the revised methodology, for the EBITDA and operating margin components, achievement of 75% of a component target earns a bonus of 50% of base salary multiplied by the Applicable Percentage, achievement of 100% of a component target earns a bonus of 100% of base salary multiplied by the Applicable Percentage, and achievement of 125% of a component target earns a bonus of 200% of base salary multiplied by the Applicable Percentage, with bonuses interpolated on a straight-line basis for target results between 75% and 100%, or 100% and 125%, as applicable. For the safety component, achievement of 125% of a component target earns a bonus of 50% of base salary multiplied by the Applicable Percentage, achievement of 100% of a component target earns a bonus of 100% of base salary multiplied by the Applicable Percentage, and

achievement of 75% of a component target earns a bonus of 200% of base salary multiplied by the Applicable Percentage, with bonuses interpolated on a straight-line basis for target results between 125% and 100%, or 100% and 75%, as applicable.

This summary of the foregoing employment agreements is qualified in its entirety by reference to the full text of such employment agreements, including amendments thereto, and the recently revised form Appendix A to the executive employment agreements, which are attached as Exhibits 10.7, 10.8, 10.9, 10.10, 10.11, 10.12, 10.13, 10.14, 10.15, 10.16 and 10.42, respectively.

Amendment of Non-Employee Director Compensation Policy

In February 2012, the Board of Directors approved revising the non-employee director compensation policy, with such revision to be effective as of January 1, 2012. For the fiscal year ended December 31, 2011, in addition to cash consideration, non-employee directors received an annual grant of restricted stock units covering 4,000 shares of common stock. After giving effect to the amendments to the policy, non-employee directors are entitled to receive quarterly grants of that number of shares of common stock equal for each quarter to $25,000 divided by the closing stock price on the applicable grant date. For the year ending December 31, 2012, the Compensation Committee has determined to grant fully vested stock awards quarterly. Should, in the future, the compensation committee determine to apply a vesting period to shares awarded under this policy, such grants may be made of restricted stock units. Any equity awards made under this policy are granted under the incentive compensation plan. The award is subject to annual review and may be increased at the discretion of the compensation committee.

The amended non-employee director compensation policy also provides for longevity service awards to non-employee directors. Upon completion of three years of service as a non-employee director, a director is granted a number of shares of common stock, restricted stock units or options equaling 25% of the shares of common stock, restricted stock units and options granted to such director over the previous three years. Upon completion of five years of service as a non-employee director, a director will be granted a number of shares of common stock, restricted stock units or options equaling 50% of the shares of common stock, restricted stock units and options granted to such director over the previous five years less the number of shares of common stock, restricted stock units and options awarded to such director after three years of service. Thereafter, upon completion of each successive period of five years of service, a non-employee director will be granted a number of shares of common stock, restricted stock units or options equaling 50% of the shares of common stock, restricted stock units and options granted to such director over the previous five years. Any restricted stock units granted will vest as determined by the Compensation Committee.

This foregoing summary of the Company’s revised non-employee director compensation policy is qualified in its entirety by reference to the full text of such policy, which is attached as Exhibit 10.2.

Amendment to Letter Agreement with Larry Hornbeck

Effective as of October 30, 2007, the independent members of the Board of Directors approved a letter agreement between the Company and Mr. Larry Hornbeck. Under the terms of such agreement, Mr. Larry Hornbeck agreed, among other things, to make himself available to the Company, the Board of Directors or any committee of the Board of Directors to assist in the assessment of potential targets for acquisitions, to travel for Company projects, to attend industry meetings and to provide assistance in other ways. On February 14, 2012, this agreement was amended and restated, effective January 1, 2012, with the approval of the independent members of the Board of Directors to set the compensation paid to Mr. Larry Hornbeck at $12,000 per month, which was deemed to be more commensurate with the scope of services provided by Mr. Larry Hornbeck. This foregoing summary of the letter agreement with Mr. Larry Hornbeck is qualified in its entirety by reference to the full text of such policy, which is attached as Exhibit 10.43.

Glossary of Terms

“AHTS” means anchor-handling towing supply;

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

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

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

“CPP” means clean petroleum products;

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

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

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

“DOI” means U.S. Department of the Interior and all its various sub-agencies, including effective October 1, 2011 the Bureau of Ocean Energy Management (“BOEM”), which

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

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

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

“DPP” means dirty petroleum products;

“DWT” means deadweight tons;

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

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

“GoM” means the U.S. Gulf of Mexico;

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

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

“Jones Act” means the U.S. cabotage law known as the Merchant Marine Act of 1920, as amended;

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

“Macondo” means the well site location in the deepwater GoM where the Deepwater Horizon incident occurred;

“MPSV” means a multi-purpose support vessel;

“MSRC” means the Marine Spill Response Corporation;

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

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

“PEMEX” means Petroleos Mexicanos;

“Petrobras” means Petroleo Brasileiro S.A.;

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

“ROV” means a remotely operated vehicle;

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

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

PART III

Item 10—Directors, Executive Officers and Corporate Governance

The information required under this item is incorporated by reference herein from the Company’s definitive 2011 proxy statement anticipated to be filed with the Securities and Exchange Commission within 120 days after December 31, 2011.

Item 11—Executive Compensation

Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13—Certain Relationships and Related Transactions, and Director Independence

Item 14—Principal Accounting Fees and Services

PART IV

Item 15—Exhibits and Financial Statement Schedules

(a) The following items are filed as part of this report:

1. Financial Statements. The financial statements and information required by Item 8 appear on pages F-1 through F-33 of this report. The Index to Consolidated Financial Statements appears on page F-1.

2. Financial Statement Schedules. All schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.

3. Exhibits. The Exhibit Index is shown on page E-1 of this report.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
CONSOLIDATED FINANCIAL STATEMENTS OF HORNBECK OFFSHORE SERVICES, INC.:

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2011 and 2010		F-3

Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2011		F-4

Consolidated Statements of Comprehensive Income (Loss) for Each of the Three Years in the Period Ended December 31, 2011		F-5

Consolidated Statements of Changes in Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2011		F-6

Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2011		F-7

Notes to Consolidated Financial Statements		F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Hornbeck Offshore Services, Inc.

We have audited the accompanying consolidated balance sheets of Hornbeck Offshore Services, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated balance sheets of Hornbeck Offshore Services, Inc. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hornbeck Offshore Services, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

New Orleans, Louisiana

February 29, 2012

F-2

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	356,849		$	126,966
Accounts receivable, net of allowance for doubtful accounts of $1,253 and $734, respectively		85,629			71,777
Other current assets		26,087			17,598

Total current assets		468,565			216,341

Property, plant and equipment, net		1,605,785			1,606,121
Deferred charges, net		47,781			41,058
Other assets		14,215			14,905

Total assets	$	2,136,346		$	1,878,425

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	36,708		$	25,100
Accrued interest		8,955			9,024
Accrued payroll and benefits		12,781			13,413
Deferred revenue		1,774			2,197
Other accrued liabilities		7,131			4,451

Total current liabilities		67,349			54,185
Long-term debt, net of original issue discount of $29,352 and $41,767, respectively		770,648			758,233
Deferred tax liabilities, net		223,678			222,413
Other liabilities		1,683			1,717

Total liabilities		1,063,358			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; 35,013 and 26,584 shares issued and outstanding, respectively		350			266
Additional paid-in capital		649,644			415,673
Retained earnings		423,073			425,634
Accumulated other comprehensive income (loss)		(79	)		304

Total stockholders’ equity		1,072,988			841,877

Total liabilities and stockholders’ equity	$	2,136,346		$	1,878,425

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

F-3

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Year Ended December 31,
	2011			2010			2009
Revenues	$	381,627		$	420,804		$	385,948
Costs and expenses:
Operating expenses		211,201			196,771			161,188
Depreciation		60,960			58,509			69,461
Amortization		20,627			18,546			23,908
General and administrative expenses		35,363			36,774			30,844

		328,151			310,600			285,401

Gain on sale of assets		1,539			2,025			1,147

Operating income		55,015			112,229			101,694
Other income (expense):
Interest income		829			528			482
Interest expense		(59,649	)		(55,183	)		(21,024	)
Other income (expense), net		442			344			(597	)

		(58,378	)		(54,311	)		(21,139	)

Income (loss) before income taxes		(3,363	)		57,918			80,555
Income tax expense (benefit)		(802	)		21,502			30,155

Net income (loss)	$	(2,561	)	$	36,416		$	50,400

Basic earnings (loss) per common share	$	(0.09	)	$	1.38		$	1.94

Diluted earnings (loss) per common share	$	(0.09	)	$	1.34		$	1.87

Weighted average basic shares outstanding		27,876			26,396			26,040

Weighted average diluted shares outstanding		27,876			27,176			26,975

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

F-4

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)


	Year Ended December 31,
	2011			2010		2009
Net income (loss)	$	(2,561	)	$	36,416	$	50,400
Other comprehensive income, net of tax:
Foreign currency translation gain (loss)		(383	)		55		19

Total comprehensive income (loss)	$	(2,944	)	$	36,471	$	50,419

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

F-5

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)


	Common Stock				Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Stockholders’ Equity
	Shares		Amount		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Stockholders’ Equity
Balance at January 1, 2009		25,920	$	259	$	397,593		$	338,818		$	230		$	736,900
Shares issued under employee benefit programs		240		3		1,508			—			—			1,511
Stock-based compensation expense		—		—		9,788			—			—			9,788
Tax benefits from equity awards		—		—		(1,555	)		—			—			(1,555	)
Net income		—		—		—			50,400			—			50,400
Foreign currency translation		—		—		—			—			19			19

Balance at December 31, 2009		26,160	$	262	$	407,334		$	389,218		$	249		$	797,063

Shares issued under employee benefit programs		424		4		(6	)		—			—			(2	)
Stock-based compensation expense		—		—		9,064			—			—			9,064
Tax expense from equity awards		—		—		(719	)		—			—			(719	)
Net income		—		—		—			36,416			—			36,416
Foreign currency translation		—		—		—			—			55			55

Balance at December 31, 2010		26,584	$	266	$	415,673		$	425,634		$	304		$	841,877

Public offering of common stock		8,050		80		230,024			—			—			230,104
Shares issued under employee benefit programs		379		4		(676	)		—			—			(672	)
Stock-based compensation expense		—		—		6,600			—			—			6,600
Tax expense from equity awards		—		—		(1,977	)		—			—			(1,977	)
Net income (loss)		—		—		—			(2,561	)		—			(2,561	)
Foreign currency translation		—		—		—			—			(383	)		(383	)

Balance at December 31, 2011		35,013	$	350	$	649,644		$	423,073		$	(79	)	$	1,072,988

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

F-6

HORNBECK OFFSHORE SERVICES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(2,561	)	$	36,416		$	50,400
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		60,960			58,509			69,461
Amortization		20,627			18,546			23,908
Stock-based compensation expense		6,525			8,710			8,704
Provision for bad debts		519			(126	)		(1,275	)
Deferred tax expense (benefit)		(1,657	)		20,559			27,507
Amortization of deferred financing costs		15,884			15,199			12,869
Gain on sale of assets		(1,539	)		(2,025	)		(1,147	)
Equity in loss from investment		—			6			555
Changes in operating assets and liabilities:
Accounts receivable		(13,127	)		(9,930	)		26,500
Other receivables and current assets		(12,539	)		6,738			12,141
Deferred drydocking charges		(19,704	)		(22,510	)		(19,234	)
Accounts payable		11,624			7,124			(4,869	)
Accrued liabilities and other liabilities		(1,208	)		(5,440	)		(29,953	)
Accrued interest		(69	)		(763	)		7,677

Net cash provided by operating activities		63,735			131,013			183,244
CASH FLOWS FROM INVESTING ACTIVITIES:
Costs incurred for MPSV program		—			(8,533	)		(114,507	)
Costs incurred for OSV newbuild program #4		—			(27,377	)		(142,842	)
Costs incurred for OSV newbuild program #5		(42,781	)		—			—
Net proceeds from sale of assets		11,339			4,656			10,596
Vessel capital expenditures		(29,028	)		(24,169	)		(12,774	)
Non-vessel capital expenditures		(1,829	)		(1,564	)		(3,523	)

Net cash used in investing activities		(62,299	)		(56,987	)		(263,050	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facility		—			—			75,000
Repayment of borrowings under revolving credit facility		—			—			(200,000	)
Net proceeds from issuance of senior notes		—			—			242,808
Deferred financing costs		(3,273	)		(89	)		(9,514	)
Gross proceeds from public offerings of common stock		241,500			—			—
Payments for public offering costs		(11,396	)		—			—
Net cash proceeds from other shares issued		1,999			1,955			2,296

Net cash provided by financing activities		228,830			1,866			110,590

Effects of exchange rate changes on cash		(383	)		55			19

Net increase in cash and cash equivalents		229,883			75,947			30,803
Cash and cash equivalents at beginning of period		126,966			51,019			20,216

Cash and cash equivalents at end of period	$	356,849		$	126,966		$	51,019

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES:
Cash paid for interest	$	43,811		$	44,178		$	24,201

Cash paid for income taxes	$	1,272		$	2,809		$	15,520

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

F-7

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

Nature of Operations

Hornbeck Offshore Services, Inc., or the Company, was incorporated in the state of Delaware in 1997. The Company, through its subsidiaries, operates offshore supply vessels, or OSVs, multi-purpose support vessels, or MPSVs, and a shore-base facility to provide logistics support and specialty services to the offshore oil and gas exploration and production industry, primarily in the U.S. Gulf of Mexico, or GoM, Latin America and select international markets. The Company, through its subsidiaries, also operates ocean-going tugs and tank barges that provide transportation of petroleum products, primarily in the northeastern United States, GoM and Puerto Rico. All significant intercompany accounts and transactions have been eliminated.

2. Summary of Significant Accounting Policies

Revenue Recognition

The Company charters its OSVs, MPSVs and certain of its tank barges to clients under time charters based on a daily rate of hire and recognizes revenue as earned on a daily basis during the contract period of the specific vessel.

The Company also contracts certain of its tank barges to clients under contracts of affreightment, or COAs, under which revenue is recognized based on the number of days incurred for the voyage as a percentage of total estimated days applied to total estimated revenues. Voyage related costs are expensed as incurred. Substantially all voyages under these contracts are less than 10 days in length.

Deferred revenue represents payments received from customers or billings submitted to customers in advance of vessels commencing time charters.

Cash and Cash Equivalents

Cash and cash equivalents consist of all highly liquid investments in money market funds, deposits and investments available for current use with an initial maturity of three months or less.

Accounts Receivable

Accounts receivable consists of trade receivables net of reserves and amounts to be rebilled to customers.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Depreciation and amortization of equipment and leasehold improvements are computed using the straight-line method based on the estimated useful lives of the related assets. Major modifications and improvements,

F-8

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

which extend the useful life of the vessel, are capitalized and amortized over the remaining useful life of the vessel. Gains and losses from retirements or other dispositions are recognized as incurred. Salvage values for marine equipment are estimated to range between 5% and 25% of the originally recorded cost, depending on the vessel type.

The estimated useful lives by classification are as follows:


Tugs			14-25 years
Tank barges			25 years
Offshore supply vessels			10-25 years
Multi-purpose support vessels			25 years
Non-vessel related property, plant and equipment			3-28 years

All of the Company’s single-hulled tank barges, which have been sold, had estimated useful lives based on their classification under the Oil Pollution Act of 1990. The Company’s double-hulled tank barges have an estimated useful life of 25 years. Assets having shorter useful lives primarily relate to acquired vessels. See “Impairment of Long-Lived Assets” below for more information.

Deferred Charges

The Company’s vessels are required by regulation to be recertified after certain periods of time. The Company defers the drydocking expenditures incurred due to regulatory marine inspections and amortizes the costs on a straight-line basis over the period to be benefited from such improvements (generally 30 months). Financing charges are amortized over the term of the related debt.

Deferred charges also include prepaid lease expenses related to the Company’s shore-base port facility. Such prepaid lease expenses are being amortized on a straight-line basis over the effective remaining term of the lease.

Mobilization Costs

The Company incurs mobilization costs to transit its vessels to and from certain regions and/or for long-term contracts. These costs, which are typically expensed as incurred, include, but are not limited to, fuel, crew wages, vessel modification and pre-positioning expenses, materials and supplies and importation taxes. The Company incurred mobilization costs of $9.5 million and $9.7 million during 2011 and 2010, respectively, associated with the mobilization and pre-positioning of vessels to foreign locations.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

F-9

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred tax assets and liabilities are measured using currently enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The provision for income taxes includes provisions for federal, state and foreign income taxes. Interest and penalties relating to uncertain tax positions are recorded as general and administrative expenses. In addition, the Company provides a valuation allowance for deferred tax assets if it is more likely than not that such items will either expire before the Company is able to realize the benefit or the future deductibility is uncertain. No valuation allowances were recorded for the years ended December 31, 2011, 2010 or 2009.

Use of Estimates

The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Legal Liabilities

In the ordinary course of business, the Company may become party to lawsuits, administrative proceedings, or governmental investigations. These matters may involve large or unspecified damages or penalties that may be sought from the Company and may require years to resolve. The Company records a liability related to a loss contingency to such legal matters in accrued liabilities if the Company determines the loss to be both probable and estimable. The liability is recorded for an amount that is management’s best estimate of the loss, or when a best estimate cannot be made, the minimum loss amount of a range of possible outcomes. Significant judgment is required in estimating such liabilities, the results of which can vary significantly from the actual outcomes of lawsuits, administrative proceedings or governmental investigations.

Concentration of Credit Risk

Customers are primarily major and independent, domestic and international, oil and oil service companies, as well as national oil companies. The Company’s customers are granted credit on a short-term basis and related credit risks are considered minimal. The Company usually does not require collateral. The Company provides an estimate for uncollectible accounts based primarily on management’s judgment using historical losses, current economic conditions and individual evaluations of each customer to make adjustments to the allowance for doubtful accounts.

The following table represents the allowance for doubtful accounts (in thousands):


	December 31,
	2011		2010			2009
Balance, beginning of year	$	734	$	860		$	2,135
Changes to provision		519		(126	)		(1,275	)

Balance, end of year	$	1,253	$	734		$	860

F-10

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Impairment of Long-Lived Assets

When events or circumstances indicate that the carrying amount of long-lived assets to be held and used or intangible assets might not be recoverable, the expected future undiscounted cash flows from the assets are estimated and compared with the carrying amount of the assets. If the sum of the estimated undiscounted cash flows is less than the carrying amount of the assets, an impairment loss is recorded. The impairment loss is measured by comparing the fair value of the assets with their carrying amounts. Fair value is determined based on discounted cash flow or appraised values, as appropriate. See Note 14 for further information.

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 adopted this guidance for our annual goodwill impairment test that was 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 issued new guidance regarding the presentation of comprehensive income. This guidance eliminates the option to present the components of other comprehensive income, or OCI, as part of the statement of stockholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income, which contains two sections, net income and OCI, or in two separate but consecutive statements. In each case, the entity is required to present reclassification adjustments on the face of the financial statements for items that are reclassified from OCI to net income in the statement where those components are presented. The amendments do not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. This new guidance is effective for interim and annual periods beginning after December 15, 2011.

In October 2011, the FASB announced it would defer the effective date of the requirement to present reclassifications from OCI to net income on the face of the financial statements. However, it did not change the requirement to present net income, components of OCI, and total comprehensive income in either one continuous statement or two separate consecutive statements. The Company elected to early adopt this new guidance effective for the year ended December 31, 2011 and has presented components of OCI in two consecutive statements. The Company does not believe the adoption of the remainder of this guidance will have a material impact on its consolidated financial statements.

Management does not expect other accounting standards that have been issued 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.

F-11

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Earnings Per Share

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


	Year Ended December 31,
	2011			2010		2009
Net income (loss)	$	(2,561	)	$	36,416	$	50,400

Weighted average number of shares of common stock outstanding		27,876			26,396		26,040
Add: Net effect of dilutive stock options⁽¹⁾⁽²⁾		—			780		935

Adjusted weighted average number of shares of common stock outstanding⁽³⁾		27,876			27,176		26,975

Earnings (loss) per common share:
Basic	$	(0.09	)	$	1.38	$	1.94

Diluted	$	(0.09	)	$	1.34	$	1.87

(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 shares of common stock for the year ended December 31, 2011 because the effect was anti-dilutive. As of December 31, 2010, and 2009, stock options representing rights to acquire 400, and 414, shares, respectively, of common stock were excluded from the calculation of diluted earnings per share because the effect was antidilutive. Stock options are anti-dilutive when the exercise price of the options is greater than the average market price of the common stock for the period or when the results from operations are a net loss.

(2)	For the years ended December 31, 2011, 2010, and 2009, 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 the Notes. See Note 6 for further information.

(3)	Dilutive restricted stock is expected to fluctuate from quarter to quarter depending the Company’s performance compared to a predetermined set of performance criteria. See Note 8 for further information regarding certain of the Company’s restricted stock awards.

4. Defined Contribution Plan

The Company offers a 401(k) plan to all full-time employees. Employees must be at least eighteen years of age and have completed three months of service to be eligible for participation. Participants may elect to defer up to 60% of their compensation, subject to certain statutorily established limits. The Company may elect to make annual matching and profit sharing contributions to the 401(k) plan. During the years ended December 31, 2011, 2010 and 2009, the Company made contributions to the 401(k) plan of approximately $0.6 million, $2.9 million, and $2.9 million, respectively. Contributions declined in 2011 because the Company temporarily suspended its 401(k) discretionary match from March 2011 through December 2011 in an effort to manage costs during the de facto regulatory moratorium in the GoM.

F-12

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Property, Plant and Equipment

Property, plant and equipment consisted of the following (in thousands):


	December 31,
	2011			2010
Tugs	$	76,038		$	75,602
Tank barges		153,475			162,077
Offshore supply vessels and multi-purpose support vessels		1,517,601			1,501,573
Non-vessel related property, plant and equipment		92,881			89,026
Less: Accumulated depreciation		(281,534	)		(229,642	)

		1,558,461			1,598,636

Construction in progress		47,324			7,485

	$	1,605,785		$	1,606,121

During 2011, the Company announced its fifth OSV newbuild program, which consists of vessel construction contracts with two domestic shipyards to build four 300 class OSVs, four 310 class OSVs, and eight 320 class OSVs. Delivery of the first 16 vessels to be constructed under this program is expected to occur on various dates during 2013 and 2014. The Company expects to own and operate 51, 56 and 67 new generation OSVs as of December 31, 2012, 2013 and 2014, respectively. These vessel additions result in a projected average new generation OSV fleet complement of 51.0, 52.2 and 62.8 vessels for the fiscal years 2012, 2013 and 2014, respectively. The aggregate cost of the Company’s fifth OSV newbuild program, excluding construction period interest, is expected to be approximately $720.0 million. From the inception of this program through December 31, 2011, the Company has incurred $42.4 million, or 5.9%, of total expected project costs.

During 2010, the Company completed its fourth OSV newbuild program and its MPSV program. The Company’s fourth OSV newbuild program consisted of vessel construction contracts with three domestic shipyards to build six 240 ED class OSVs, nine 250 EDF class OSVs and one 290 class OSV. These vessels were delivered on various dates from 2008 to 2010. The aggregate cost, prior to the allocation of construction period interest, of the fourth OSV newbuild program was approximately $431.6 million. The Company’s MPSV program consisted of the conversion of two coastwise sulfur tankers into U.S.-flagged, proprietary 370 class DP-2 new generation MPSVs at domestic shipyards, and the newbuild construction of two 430 class DP-3 new generation MPSVs at foreign shipyards. These vessels were delivered on various dates from 2008 to 2010. The aggregate cost of the MPSV program, prior to the allocation of construction period interest, was approximately $491.1 million.

6. Long-Term Debt

Senior Notes

On November 23, 2004, the Company issued in a private placement $225.0 million in aggregate principal amount of 6.125% senior unsecured notes due 2014, or senior notes, governed by an indenture, or the 2004 indenture. The effective interest rate on the senior

F-13

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

notes is 6.38%. On October 4, 2005, the Company issued in a private placement an additional $75.0 million in aggregate principal amount of 6.125% senior unsecured notes, or additional notes, governed by the 2004 indenture. The additional notes were priced at 99.25% of principal amount to yield 6.41%. The senior notes and additional notes, collectively, the 2014 senior notes, mature on December 1, 2014 and require semi-annual interest payments at a fixed annual rate of 6.125%, or approximately $9.2 million semi-annually, on June 1 and December 1 of each year until maturity. No principal payments are due until maturity. Pursuant to registered exchange offers, the 2014 senior notes issued in November 2004 and October 2005 that were initially sold pursuant to private placements were exchanged by the holders for 6.125% senior notes with substantially the same terms, except that the issuance of the senior notes issued in the exchange offers was registered under the Securities Act of 1933, as amended, or the Securities Act. Both series of 2014 senior notes were issued under and are entitled to the benefits of the same 2004 indenture.

On August 17, 2009, the Company issued in a private placement $250.0 million in aggregate principal amount of 8.000% senior unsecured notes due 2017, or 2017 senior notes, governed by an indenture, or the 2009 indenture. The net proceeds to the Company from the offering were approximately $237.3 million, net of original issue discount and estimated transaction costs. The Company used $200.0 million of proceeds to repay debt under its revolving credit facility, which may be reborrowed. The remaining proceeds were available for general corporate purposes, which include partial funding of the construction of vessels under existing newbuild programs. The 2017 senior notes mature on September 1, 2017 and require semi-annual interest payments at a fixed annual rate of 8.000%, or $10.0 million semi-annually, on March 1 and September 1 of each year until maturity, with the first interest payment made on March 1, 2010. The effective interest rate on the 2017 senior notes is 8.63% and no principal payments are due until maturity. Pursuant to a registered exchange offer, the 2017 senior notes issued in August 2009 that were initially sold pursuant to a private placement were exchanged by the holders for 8.000% senior notes with substantially the same terms, except that the issuance of the senior notes issued in the exchange offer was registered under the Securities Act of 1933, as amended, or the Securities Act. The original 2017 senior notes and the similar notes exchanged therefor were issued under and are entitled to the benefits of the same 2009 indenture.

The 2014 senior notes and 2017 senior notes are senior unsecured obligations and rank equally in right of payment with other existing and future senior indebtedness and senior in right of payment to any subordinated indebtedness that may be incurred by the Company in the future. These senior notes are guaranteed by certain of the Company’s subsidiaries. The guarantees are full and unconditional, joint and several, and all of the Company’s non-guarantor subsidiaries are minor as defined in the Securities and Exchange Commission, or Commission, regulations. Hornbeck Offshore Services, Inc., as the parent company issuer of these senior notes, has no independent assets or operations other than its ownership interest in its subsidiaries and affiliates. There are no significant restrictions on the Company’s ability or the ability of any guarantor to obtain funds from its subsidiaries by such means as a dividend or loan, except for certain restrictions contained in the Company’s revolving credit facility restricting the payment of dividends by the Company’s two principal subsidiaries. The

F-14

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Company may, at its option, redeem all or part of the 2014 senior notes or 2017 senior notes from time to time at specified redemption prices and subject to certain conditions required by the indentures. The Company is permitted under the terms of the indentures to incur additional indebtedness in the future, provided that certain financial conditions set forth in the indentures are satisfied by the Company.

Convertible Senior Notes

On November 13, 2006, the Company issued in a private placement $250.0 million in aggregate principal amount of 1.625% convertible senior notes due 2026, or the convertible notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act. During the first quarter of 2007, the Company registered the resale of the convertible notes by the holders thereof. The convertible notes bear interest at a fixed annual rate of 1.625%, declining to 1.375% beginning on November 15, 2013, payable semi-annually on May 15 and November 15 of each year, with the first interest payment made on May 15, 2007. The effective interest rate on such notes is 6.36%. The convertible notes are convertible into shares of the Company’s common stock based on the applicable conversion rate only under the following circumstances:

•

during any calendar quarter (and only during such calendar quarter), if the closing price of the Company’s shares of common stock for at least 20 trading days in the 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is more than 135% of the conversion price per share, which is $1,000 divided by the then applicable conversion rate;

•

prior to November 15, 2013, during the five business day period after a 10 consecutive trading day period in which the trading price per $1,000 principal amount of senior convertible notes for each day of that period was less than 95% of the product of the closing price for the Company’s shares of common stock for each day of that period and the number of shares of common stock issuable upon conversion of $1,000 principal amount of the convertible notes;

•

if the convertible notes have been called for redemption, or

•

upon the occurrence of specified corporate transactions, as defined by the convertible note agreement.

The initial conversion rate of 20.6260 shares per $1,000 principal amount of notes, which corresponds to a conversion price of approximately $48.48 per share, is based on the last reported sale price of the Company’s common shares on the New York Stock Exchange of $35.26 on November 7, 2006. As of December 31, 2011, the Company’s closing share price was $31.02.

The convertible senior notes are guaranteed by certain of the Company’s subsidiaries. The guarantees are full and unconditional, joint and several, and all of the Company’s non-guarantor subsidiaries are minor as defined in Commission regulations. Hornbeck Offshore Services, Inc., as the parent company issuer of the convertible senior notes, has no independent assets or operations other than its ownership interest in its subsidiaries and

F-15

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

affiliates. There are no significant restrictions on the Company’s ability or the ability of any guarantor to obtain funds from its subsidiaries by such means as a dividend or loan, except for certain restrictions contained in the Company’s revolving credit facility restricting the payment of dividends by the Company’s two principal subsidiaries. The convertible notes are general unsecured, senior obligations of the Company, ranking equally in right of payment with all of its existing and future senior indebtedness, including its outstanding 6.125% senior notes due 2014, 8.000% new senior notes due 2017, and indebtedness under its revolving credit facility.

If, upon the occurrence of certain events, the holders of the convertible notes exercise the conversion provisions of the convertible notes, the Company may need to remit the principal balance of the convertible notes to them in cash as discussed below. In such case, the Company would classify the entire amount of the outstanding convertible notes as a current liability in the respective quarter. This evaluation of the classification of amounts outstanding associated with the convertible notes will occur every calendar quarter. Upon conversion, a holder will receive, in lieu of common stock, an amount of cash equal to the lesser of (i) the principal amount of the convertible note, or (ii) the conversion value, determined in the manner set forth in the indenture governing the convertible notes, of a number of shares equal to the conversion rate. If the conversion value exceeds the principal amount of the convertible note on the conversion date, the Company will also deliver, at the Company’s election, cash or common stock or a combination of cash and common stock with respect to the conversion value upon conversion. If conversion occurs in connection with a change of control, the Company may be required to deliver additional shares of its common stock by increasing the conversion rate with respect to such convertible notes.

In connection with the sale of the convertible notes, the Company is a party to convertible note hedge transactions with respect to its common stock with Jefferies & Company, Inc., JP Morgan Chase and AIG-FP Structured Finance (Cayman) Limited, or the counterparties. Each of the convertible note hedge transactions involves the purchase of call options with exercise prices equal to the conversion price of the convertible notes, and are intended to mitigate dilution to the Company’s stockholders upon the potential future conversion of the convertible notes. Under the convertible note hedge transactions, the counterparties are required to deliver to the Company the number of shares of the Company’s common stock that the Company is obligated to deliver to the holders of the convertible notes with respect to the conversion. The convertible note hedge transactions cover approximately the same number of shares of the Company’s common stock underlying the convertible notes, subject to customary anti-dilution adjustments, at a strike price of $48.48 per share of common stock, which represented a 37.5% premium over the closing price of the Company’s shares of common stock on November 7, 2006. The convertible note hedge transactions expire at the close of trading on November 15, 2013, which is the date that the convertible notes are first putable by the convertible noteholders, although the counterparties will have ongoing obligations with respect to convertible notes properly converted on or prior to that date of which the counterparty has been timely notified. In addition, on November 15, 2016 and November 15, 2021, holders of the 1.625% convertible senior notes may require the Company to purchase their notes for cash.

F-16

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company also entered into separate warrant transactions, whereby the Company sold to the counterparties warrants to acquire approximately the same number of shares of its common stock underlying the convertible notes, subject to customary anti-dilution adjustments, at a strike price of $62.59 per share of common stock, which represented a 77.5% premium over the closing price of the Company’s shares of common stock on November 7, 2006. If the counterparties exercise the warrants, the Company will have the option to settle in cash or shares of its common stock equal to the difference between the then market price and strike price. The convertible note hedge and warrant transactions are separate and legally distinct instruments that bind the Company and the counterparties and have no binding effect on the holders of the convertible notes.

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

Revolving Credit Facility

On September 27, 2006, the Company closed on a five-year senior secured $100.0 million revolving credit facility with an accordion feature that allowed for the expansion of the facility up to an aggregate of $250.0 million. On February 20, 2008, the Company exercised its accordion feature in full and increased the then-undrawn borrowing base of its revolving credit facility from $100.0 million to $250.0 million. In accordance with the terms of the expanded facility, the Company pledged an additional 16 new generation OSVs as collateral commensurate with the higher borrowing base. On November 4, 2009, the Company amended and extended its revolving credit facility, which maintained its $250.0 million borrowing base but included an accordion feature that allowed for the expansion of the facility up to an aggregate of $350.0 million. The amended facility, among other changes, also extended the maturity from September 2011 to March 2013. With the amended facility, the Company had 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 were payable quarterly at the annual rate of 50.0 basis points of the unused portion of the borrowing base of the amended facility. The Company also exchanged certain vessels pledged as collateral under the amended revolving credit facility such that the total number of vessels pledged as collateral was 19 new generation OSVs. None of the Company’s Downstream vessels were pledged under the November 2009 amended and extended facility or any subsequent amendments.

F-17

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On March 14, 2011, the Company amended the credit agreement governing its revolving credit facility to favorably adjust certain financial ratios and provide for additional new maintenance covenants. The key changes to the Company’s revolving credit facility were effective commencing with the fiscal quarter ended December 31, 2010 and are noted below:

•

The maximum leverage ratio, as defined in the previous credit agreement, was eliminated as a maintenance covenant and was only used to determine the pricing grid.

•

A maximum secured debt leverage ratio of 2.00 to 1.00, as defined in the March 2011 amendment, was added as a new maintenance covenant.

•

The minimum interest coverage ratio was reduced from 3.00 to 1.00 to 2.00 to 1.00.

•

A maximum total debt to capitalization ratio of 55.0%, as defined in the March 2011 amendment, was added as a new maintenance covenant.

On November 2, 2011, the Company further 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 effective commencing with the fiscal quarter ended September 30, 2011 and are noted below:

•

The amended facility extended 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 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 unused commitment fee under the amended facility is payable quarterly at an annual rate ranging from 37.5 to 50.0 basis points of the unused portion of the borrowing base of the amended facility, 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.

•

The Company increased 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

F-18

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

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

As of December 31, 2011, there were no amounts drawn under the Company’s $300.0 million revolving credit facility and $0.9 million posted in letters of credit. As of December 31, 2011, the Company was in compliance with all financial covenants contained in its amended revolving credit facility.

The credit agreement governing the amended revolving credit facility and the indentures governing the Company’s 2014 senior notes and 2017 senior notes impose certain operating and financial restrictions on the Company. Such restrictions affect, and in many cases limit or prohibit, among other things, the Company’s ability to incur additional indebtedness, make capital expenditures, redeem equity, create liens, sell assets and make dividend or other restricted payments.

The Company estimates the fair value of its 6.125% senior notes due 2014, its 8.000% senior notes due 2017 and its 1.625% convertible senior notes due 2026 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, $770.6 million and $810.3 million, respectively, as of December 31, 2011.

Interest expense excludes capitalized interest related to the construction or conversion of vessels in the approximate amount of $0.4 million, $3.7 million, and $23.8 million, for the years ended December 31, 2011, 2010, and 2009, respectively.

F-19

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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


	December 31,
	2011		2010
6.125% senior notes due 2014, net of original issue discount of $215 and $279	$	299,785	$	299,721
8.000% senior notes due 2017, net of original issue discount of $5,571 and $6,305		244,429		243,695
1.625% convertible senior notes due 2026, net of original issue discount of $23,566 and $35,183⁽¹⁾		226,434		214,817
Revolving credit facility		—		—

		770,648		758,233
Less current maturities		—		—

	$	770,648	$	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.

Annual maturities of debt, excluding the potential effects of conditions discussed in Convertible Senior Notes, during each year ending December 31, are as follows (in thousands):


2012		—
2013		—
2014		299,785
2015		—
2016		—
Thereafter⁽¹⁾		470,863

	$	770,648

(1)	The convertible notes mature on November 15, 2026; however, the date that the convertible notes are first putable by the convertible noteholders to the Company is November 15, 2013.

7. Stockholders’ Equity

Preferred Stock

The Company’s certificate of incorporation authorizes 5.0 million shares of preferred stock. The Board of Directors has the authority to issue preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, conversion rights, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of such series, without further vote or action by the Company’s stockholders.

F-20

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Stockholder Rights Plan

The Company’s Board of Directors previously implemented a stockholder rights plan, as amended, establishing one right for each outstanding share of common stock. The rights become exercisable, and transferable apart from the Company’s common stock, 10 business days following a public announcement that a person or group has acquired beneficial ownership of, or has commenced a tender or exchange offer for, 10% or more of the Company’s common stock.

Public Offerings of Common Stock

On November 16, 2011, the Company completed an underwritten public offering of 8.1 million shares of its common stock at $30.00 per share, for total gross proceeds of $241.5 million before underwriting discounts, commissions and offering expenses. This includes 1,050,000 additional shares of common stock purchased pursuant to the exercise in full of the underwriters’ over-allotment option. Underwriting discounts, commissions and offering expenses of approximately $11.4 million were recorded as a reduction of additional paid-in capital. The Company intends to use net proceeds from the offering to partially fund its fifth OSV newbuild program. In addition, offering proceeds may be used in connection with possible future acquisitions and additional new vessel construction, as well as for general corporate purposes.

8. Stock-Based Compensation

Incentive Compensation Plan

During the Company’s Annual Meeting of Stockholders in June 2010, the Company’s stockholders approved an increase in the number of shares available to issue under its stock-based incentive compensation plan by 700,000. The Company’s stock-based incentive compensation plan now 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. The issuance of shares of common stock under the incentive compensation plan has been registered on Form S-8 with the Securities and Exchange Commission.

The table below reflects selected financial captions and the related impact stock-based compensation expense charges have on the Company’s operating results (in thousands, except per share data):


	Year Ended December 31,
	2011		2010		2009
Income before taxes	$	6,525	$	8,710	$	8,704

Net income	$	4,972	$	5,479	$	5,449

Earnings per common share:
Basic	$	0.18	$	0.21	$	0.21

Diluted	$	0.18	$	0.20	$	0.20

F-21

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the years ended December 31, 2010, and 2009, approximately $0.4 million, and $1.1 million of stock-based compensation expense, respectively, was capitalized as part of the Company’s newbuild construction programs and general corporate projects. No such stock-based compensation expense was capitalized during the year ended December 31, 2011. The accounting rules also require the benefits of tax deductions in excess of recognized compensation expense to be reported as financing cash flows, rather than as operating cash flows. The Company recorded financing cash flows for such excess tax deductions of approximately $0.4 million, $0.4 million, and $0.2 million for the years ended December 31, 2011, 2010, and 2009, respectively. Net cash proceeds from the exercise of stock options were $0.6 million, $0.6 million, and $1.0 million for the years ended December 31, 2011, 2010, and 2009, respectively. The income tax benefit from stock option exercises and restricted stock vesting was $2.0 million, $2.7 million, and $1.3 million for the respective periods. As of December 31, 2011, the Company has approximately 0.8 million shares available for future grants of stock options, restricted stock, stock appreciation rights or other awards to officers, employees and directors under the incentive compensation plan.

Stock Options

The Company is authorized to grant stock options under its incentive compensation plan in which the purchase price of the stock subject to each option is established as the closing price on the New York Stock Exchange of the Company’s common stock on the date of grant and accordingly is not less than the fair market value of the stock on the date of grant. All options granted during the year ended December 31, 2011 expire ten years after the date of grant, have an exercise price equal to or greater than the actual or estimated market price of the Company’s stock on the date of grant and vest over a three-year period. Stock options were granted to executive officers of the company during 2011. No stock options were granted during 2010 and 2009.

The fair value of the options granted under the Company’s incentive compensation plan during the year ended December 31, 2011 was estimated using the Black-Scholes pricing model with the following weighted-average assumptions for the respective option periods.


	For the Year Ended December 31,
	2011
Dividend yield		0	%
Expected volatility		57.3	%
Risk-free interest rate		2.0	%
Expected term (years)		4.7
Weighted-average grant-date fair value per share	$	12.21

F-22

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table represents the Company’s stock option activity for the year ended December 31, 2011 (in thousands, except per share data and years):


	Number of Shares			Weighted Average Exercise Price		Weighted- Average Remaining Contractual Term (years)		Aggregate Intrinsic Value
Options outstanding at January 1, 2011		765		$	19.85		3.5	$	3,502
Grants		205			24.86		9.1		1,261
Exercised		(77	)		7.99		n/a		1,414
Forfeited		(5	)		33.13		n/a		n/a

Options outstanding at December 31, 2011		888		$	21.96		4.2	$	8,411

Exercisable options outstanding at December 31, 2011		683		$	21.09		2.8	$	7,149

The following table represents the Company’s nonvested stock option activity for the year ended December 31, 2011 (in thousands, except per share data):


	Number of Shares		Weighted-Average Grant-Date Fair Value
Nonvested stock options at January 1, 2011		—	$	—
Grants		205		12.21
Vested		—		—
Forfeited		—		—

Nonvested stock options at December 31, 2011		205	$	12.21

As of December 31, 2011, the Company had unamortized stock-based compensation expense of $1.8 million that will be recognized on a straight-line basis over the remaining vesting period, or 1.5 years, and has recorded approximately $0.7 million of compensation expense during 2011, respectively, associated with stock options.

Restricted Stock

The Company’s incentive compensation plan allows the Company to issue restricted stock units, with either performance-based or time-based vesting provisions. The Company has issued two types of performance-based restricted stock unit awards whose vesting is determined by achieving either external or internal performance criteria. For the first type of performance-based restricted stock unit award, the number of shares that will ultimately be received by the award recipients at the end of the performance period is dependent upon the Company’s performance relative to a peer group, as defined by the restricted stock unit agreements governing such awards. Performance for such types of awards has historically been measured by the change in the Company’s stock price measured against the peer group during the measurement period, generally three years. 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. This type of performance-based restricted stock unit was granted in 2011. The second type of performance-based restricted stock unit award, calculates the shares to be received based on the Company’s achievement of certain performance criteria over a three-year period as defined by the restricted stock unit agreement governing such awards. Performance for

F-23

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

these types of awards has historically been measured by a number of factors, including the Company achieving a targeted return on invested capital, return on equity, Upstream operating profit margin and growth in earnings (net income) before interest, income taxes, depreciation and amortization or EBITDA. The actual number of shares that could be received by these award recipients can range from 0% to 100% of the Company’s base share awards depending on the number of performance goals attained by the Company. Compensation expense related to restricted stock unit awards is recognized over the period the restrictions lapse, from one to three years. The fair value of the Company’s performance-based restricted stock unit awards, which is determined using a Monte Carlo simulation, is applied to the base shares and is amortized over the vesting period based on either their relative performance compared to peers or internal performance goals attained. The compensation expense related to time-based restricted stock unit awards, which is amortized over a one to four-year vesting period, 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. As of December 31, 2011, the Company had unamortized stock-based compensation expense of $7.5 million, which will be recognized on a straight-line basis over the remaining vesting period, or 1.5 years. In addition, the Company has recorded approximately $5.4 million of compensation expense during the year ended December 31, 2011 associated with restricted stock unit awards.

The following table summarizes the restricted stock awards activity during the year ended December 31, 2011 (in thousands, except per share data):


	Number of Shares			Weighted Avg. Fair Value Per Share⁽¹⁾
Restricted stock awards:
Restricted stock awards as of January 1, 2011		1,021		$	26.86
Granted during the period⁽²⁾		289			24.97
Cancellations during the period⁽²⁾		(169	)		38.55
Vested		(341	)		33.87

Outstanding, as of December 31, 2011		800		$	20.72

(1)	The weighted average fair value per share is determined by the stock price on the date of grant for time-based shares and is determined using a Monte Carlo simulation for performance-based shares, of which the fair value is applied to both the base and bonus share awards.

(2)	Includes the full amount of both base and bonus share awards granted or cancelled during the period, which represents up to 200% of the aggregate total of the base share awards.

Employee Stock Purchase Plan

On May 3, 2005, the Company established the Hornbeck Offshore Services, Inc. 2005 Employee Stock Purchase Plan, or ESPP, which was adopted by the Company’s Board of Directors and approved by the Company’s stockholders. Under the ESPP, the Company is authorized to issue up to 700,000 shares of common stock to eligible employees of the Company and its designated subsidiaries. Employees have the opportunity to purchase shares of the Company’s common stock at periodic intervals through accumulated payroll deductions that will be applied at semi-annual intervals to purchase shares of common stock at a discount from the market price as defined by the ESPP. The ESPP is designed to satisfy

F-24

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the requirements of Section 423 of the Internal Revenue Code of 1986, as amended, and thereby allows participating employees to defer recognition of taxes when purchasing the shares of common stock at a 15% discount under the ESPP. The Company has an effective Registration Statement on Form S-8 with the Commission registering the issuance of shares of common stock under the ESPP. As of December 31, 2011, there were 358,666 shares available for future issuance to employees under the ESPP. The Company has recorded approximately $0.4 million of compensation expense during the year ended December 31, 2011 associated with the ESPP.

The fair value of the employees’ stock purchase rights granted under the ESPP was estimated using the Black-Scholes model with the following assumptions for years ended December 31, 2011 and 2010:


	2011			2010
Dividend yield		0	%		0	%
Expected volatility		43.7	%		51.3	%
Risk-free interest rate		0.2	%		0.2	%
Expected term (months)		6.0			6.0
Weighted-average grant-date fair value per share	$	5.70		$	5.66

9. Income Taxes

The net long-term deferred tax liabilities in the accompanying consolidated balance sheets include the following components (in thousands):


	December 31,
	2011			2010			2009
Deferred tax liabilities:
Fixed assets	$	408,842		$	343,023		$	249,698
Deferred charges and other liabilities		12,100			11,982			12,313

Total deferred tax liabilities		420,942			355,005			262,011
Deferred tax assets:
Net operating loss carryforwards		(164,623	)		(98,914	)		(29,603	)
Allowance for doubtful accounts		(455	)		(266	)		(311	)
Stock-based compensation expense		(4,353	)		(5,766	)		(6,554	)
Alternative minimum tax credit carryforward		(20,863	)		(20,863	)		(20,863	)
Foreign tax credit carryforward		(5,405	)		(4,558	)		(3,462	)
Other		(4,786	)		(4,440	)		(2,284	)

Total deferred tax assets		(200,485	)		(134,807	)		(63,077	)
Valuation allowance		—			—			—

Total deferred tax liabilities, net	$	220,457		$	220,198		$	198,934

F-25

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


	December 31,
	2011		2010		2009
Current deferred tax assets, net	$	3,221	$	2,215	$	—
Long-term deferred tax liabilities, net		223,678		222,413		198,934

Total deferred tax liabilities, net	$	220,457	$	220,198	$	198,934

The components of the income tax expense follow (in thousands):


	December 31,
	2011			2010		2009
Current tax expense (benefit):
U.S.	$	(299	)	$	—	$	(448	)
Foreign		1,154			943		3,096

Total current tax expense		855			943		2,648

Deferred tax expense (benefit):
U.S.		(1,657	)		20,559		27,507

Total tax expense (benefit)	$	(802	)	$	21,502	$	30,155

Income (loss) before income taxes, based on jurisdiction earned, was as follows (in thousands):


	December 31,
	2011			2010		2009
U.S.	$	(15,744	)	$	56,800	$	58,016
Foreign		12,381			1,118		22,539

Total income (loss) before income taxes	$	(3,363	)	$	57,918	$	80,555

At December 31, 2011, the Company had federal tax net operating loss carryforwards of approximately $452.9 million, which will expire in 2029 through 2031 and foreign tax credit carryforwards of approximately $5.4 million, which will expire in 2019 through 2021. The Company has state tax net operating loss carryforwards of approximately $129.9 million, which will expire in 2019 through 2031 and can only be utilized if the Company generates taxable income in particular tax jurisdictions. Based on historical and projected operating results, the Company believes that no valuation allowance is necessary for its deferred tax assets.

The Company is no longer subject to tax audits by state, local or foreign taxing authorities for years prior to 2005. The Company has ongoing examinations by various state and foreign tax authorities and does not believe that the results of these examinations will have a material adverse effect on the Company’s financial position or results of operations.

F-26

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table reconciles the difference between the Company’s income tax provision calculated at the federal statutory rate of 35% and the actual income tax provision (in thousands):


	Year Ended December 31,
	2011			2010		2009
Statutory rate	$	(1,177	)	$	20,271	$	28,194
State taxes, net		(44	)		753		1,047
Non-deductible expense		135			80		71
Foreign taxes and other		284			398		843

	$	(802	)	$	21,502	$	30,155

10. Commitments and Contingencies

Operating Leases

The Company is obligated under certain operating leases for marine vessels, office space, shore-base facilities and vehicles. The Covington facility lease, which commenced on September 1, 2003, provides for an initial term of five years with two five-year renewal options. In September 2008, the Company exercised its first five-year renewal option. A shore-base facility lease in Port Fourchon commenced on December 20, 2005 and provides for an initial term of seven years with four additional five-year periods upon the terms and conditions contained in the lease agreement. On January 30, 2008, the Company purchased a leasehold interest in a parcel of improved real estate as an adjacent addition to HOS Port, its existing shore-base facility located in Port Fourchon, Louisiana. At December 31, 2011, the new facility lease had approximately three years remaining on its initial term, with four additional five-year renewal periods.

Future minimum payments under noncancelable leases for years subsequent to 2011 are as follows (in thousands):


Year Ended December 31,
2012	$	3,176
2013		2,607
2014		1,620
2015		1,512
2016		957
Thereafter		24,077

Total	$	33,949

In addition, the Company leases marine vessels used in its operations under long-term and month-to-month operating lease agreements. Total rent expense related to such leases was approximately $0.2 million during the year ended December 31, 2009. The Company did not have any rent expense related to such vessels during the years ended December 31, 2010 and 2011.

F-27

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 or results of operations. 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 2011 and 2010, the terms of entry for our Downstream segment contained an annual aggregate deductible, or AAD, for which the Company remains responsible. The P&I Club is responsible for covered amounts that exceed the AAD, after payment by the Company of an additional individual claim deductible. The Company provides reserves for those portions of the AAD and any individual claim deductibles for which the Company remains responsible by using an estimation process that considers Company-specific and industry data, as well as management’s experience, assumptions and consultation with outside counsel. As additional information becomes available, the Company will assess the potential liability related to its pending claims and revise its estimates. Although 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. As of December 31, 2011, the Company’s claims incurred under its P&I Club policies have not exceeded the AAD for the 2011 or 2010 policy years.

During 2010 and 2011, the Company mobilized 12 vessels, in the aggregate, to Brazil to operate under long-term contracts for Petrobras. These vessels required a significant amount of modifications to comply with requirements of the contracts. The Company has been assessed penalties by Petrobras for late-deliveries. In addition, these vessel charters with Petrobras include limitations regarding fuel consumption. Petrobras has asserted claims against the Company relating to excess fuel consumption. The Company’s exposure for these assessments, net of amounts accrued, is in the range of approximately $0.5 million to $8.0 million. The Company disagrees with a majority of these assessments. In addition, the Company also has claims against Petrobras for their contributory actions related to the vessels’ late deliveries. Such claims exceed the maximum exposure noted above. The Company is not able to predict the ultimate outcome of these claims and counterclaims with Petrobras as of December 31, 2011. While the Company cannot currently estimate the amounts or timing of the resolution of these matters, the Company believes that the outcome will not have a material impact on its liquidity or financial position, but the ultimate resolution could have material impact on its interim or annual results of operations.

F-28

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

11. Deferred Charges

Deferred charges include the following (in thousands):


	Year Ended December 31,
	2011		2010
Deferred financing costs, net of accumulated amortization of $11,634 and $12,220, respectively	$	13,488	$	14,013
Deferred drydocking costs, net of accumulated amortization of $22,772 and $23,252, respectively		28,722		23,260
Prepaid lease expense, net of amortization of $909 and $751, respectively		3,479		3,637
Other deferred charges		2,092		148

Total	$	47,781	$	41,058

12. Related Party Transactions

During 2010 and 2009, the Company received aggregate payments of approximately $4.3 million and $9.9 million, respectively, for charter of its OSVs and rental of its shore-base port facility from a customer whose Chairman of the Board served on the Company’s Board of Directors. From October 2007 until his retirement on May 7, 2009, such customer’s Chairman also served as its President and Chief Executive Officer. This Board member stepped down as Chairman of such customer and ceased to serve as a director of the customer effective May 7, 2010. This Board member also resigned from the Company’s Board effective February 15, 2011.

13. Major Customers

In the years ended December 31, 2011, 2010, and 2009, revenues from the following customers exceeded 10% of total revenues:


	Year Ended December 31,
	2011			2010			2009
Customer A⁽¹⁾		19	%		—			—
Customer B⁽¹⁾		14	%		13	%		11	%
Customer C⁽²⁾		—			21	%		—
Customer D⁽²⁾		—			—			18	%

(1)	Upstream segment.

(2)	Upstream segment and Downstream segment.

14. Asset and Goodwill Impairment Assessment

In the second quarter of 2009, triggering events occurred that resulted in the Company performing impairment tests on its Downstream segment assets, as well as the conventional OSVs in its Upstream Segment. This analysis resulted in the Company recording a non-cash asset impairment charge of $25.8 million, included in depreciation expense, related to ten single-hulled tank barges and six ocean-going tugs, and a $0.9 million non-cash charge, included in amortization expense, for the write-off of remaining goodwill associated with the Company’s Downstream segment. Based on the analysis performed, no impairment existed for any of the Company’s conventional OSVs. The specific triggering events were the

F-29

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Downstream segment operating loss for the quarter ended June 30, 2009, the lack of any material new contracts for the Downstream segment since March 31, 2009, and the lack of any expected change in performance in that segment in the near term. As of June 30, 2009, the Company had stacked all of its conventional OSVs, which it considered to be a triggering event for those specific assets.

The impairment assessment compared the net book values of the Company’s Downstream marine assets, as well as Downstream segment goodwill that was booked upon the Company’s formation in June 1997, to their respective fair values. The analysis performed during the second quarter of 2009 included considering recent vessel sales, quoted market prices and past third-party appraisals.

No further impairment for the Company’s vessels was deemed necessary as of December 31, 2011, 2010, and 2009. No new triggering events have occurred since June 30, 2009. The Company considered whether the curtailed level of drilling activity in the GoM represented an indicator of impairment for any of its asset groups and concluded it did not. Some factors that the Company considered were the anticipated temporary nature of the reduced drilling activity, projected operating results for assets groups, the significant remaining operating useful life, mobility and flexibility of the Company’s vessels. The Company did not record any impairment losses related to its long-lived assets during 2010 or 2011. As of December 31, 2011 and 2010, the Company’s Other Assets included approximately $1.7 million of goodwill related to its Upstream segment.

15. Segment Information

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

F-30

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table shows reportable segment information for the years ended December 31, 2011, 2010, and 2009, reconciled to consolidated totals and prepared on the same basis as the Company’s consolidated financial statements (in thousands).


	Year Ended December 31,
	2011		2010		2009
Revenues:
Upstream
Domestic	$	182,226	$	298,400	$	274,782
Foreign⁽¹⁾		148,610		76,127		51,875

		330,836		374,527		326,657

Downstream
Domestic		42,866		42,854		58,050
Foreign⁽¹⁾⁽²⁾		7,925		3,423		1,241

		50,791		46,277		59,291

Total	$	381,627	$	420,804	$	385,948

Operating Expenses:
Upstream	$	177,868	$	166,349	$	121,488
Downstream		33,333		30,422		39,700

Total	$	211,201	$	196,771	$	161,188

Depreciation and Amortization:
Upstream	$	67,910	$	64,685	$	50,740
Downstream		13,677		12,370		42,629

Total	$	81,587	$	77,055	$	93,369

General and Administrative Expenses:
Upstream	$	32,170	$	33,956	$	25,641
Downstream		3,193		2,818		5,203

Total	$	35,363	$	36,774	$	30,844

Gain on Sale of Assets:
Upstream	$	980	$	986	$	111
Downstream		559		1,039		1,036

Total	$	1,539	$	2,025	$	1,147

Operating Income:
Upstream	$	53,868	$	110,523	$	128,899
Downstream		1,147		1,706		(27,205	)

Total	$	55,015	$	112,229	$	101,694

Capital Expenditures:
Upstream	$	70,862	$	58,282	$	272,147
Downstream		1,377		1,840		391
Corporate		1,399		1,521		1,108

Total	$	73,638	$	61,643	$	273,646

F-31

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


	As of December 31,
	2011		2010		2009
Identifiable Assets:
Upstream	$	1,915,137	$	1,647,561	$	1,552,974
Downstream		197,876		205,782		204,850
Corporate		23,333		25,082		28,524

Total	$	2,136,346	$	1,878,425	$	1,786,348

Long-Lived Assets:
Upstream
Domestic	$	965,535	$	1,203,136	$	1,295,100
Foreign⁽¹⁾		460,099		211,488		108,335

		1,425,634		1,414,624		1,403,435

Downstream
Domestic		146,027		166,673		191,627
Foreign⁽¹⁾⁽²⁾		28,344		18,297		—

		174,371		184,970		191,627
Corporate		5,780		6,527		7,601

Total	$	1,605,785	$	1,606,121	$	1,602,663

(1)

The Company’s vessels conduct operations in international areas. Vessels will routinely move to and from international and domestic 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 December 31, 2011, 2010, and 2009, respectively.

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

16. Employment Agreements

The Company has employment agreements with certain members of its executive management team. These agreements include, among other things, contractually stated base level salaries and a structured cash incentive compensation program dependent upon the Company achieving certain targeted financial results. The agreements contain an EBITDA target, as well as a discretionary component, established by the Compensation Committee of the Company’s Board of Directors, in setting the cash incentive compensation for such executives under this program. Notwithstanding the agreement terms, for the year ended December 31, 2011, cash incentive compensation was determined solely on a discretionary basis by the Compensation Committee of the Company’s Board of Directors. In the event such a member of the executive management team is terminated due to certain events as defined in such officer’s agreement, the employee will continue to receive salary, bonus and other payments for the full remaining term of the agreement. The current term of these employment agreements expires on December 31, 2014 and automatically extends each year thereafter on January 1st, for an additional year.

F-32

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

17. Supplemental Selected Quarterly Financial Data (Unaudited) (in thousands, except per share data):

The following table contains selected unaudited quarterly financial data from the consolidated statements of operations for each quarter of fiscal years 2011 and 2010. The operating results for any quarter are not necessarily indicative of results for any future period.


	Quarter Ended
	Mar 31			Jun 30			Sep 30			Dec 31
Fiscal Year 2011⁽¹⁾⁽²⁾⁽³⁾
Revenues	$	72,267		$	80,817		$	105,827		$	122,716
Operating income		739			3,813			14,629			35,834
Net income (loss)		(9,036	)		(7,025	)		(741	)		14,241
Earnings (loss) per common share⁽⁴⁾ :
Basic	$	(0.34	)	$	(0.26	)	$	(0.03	)	$	0.46
Diluted		(0.34	)		(0.26	)		(0.03	)		0.45
Fiscal Year 2010⁽¹⁾⁽²⁾⁽⁵ ⁾
Revenues	$	86,245		$	111,885		$	125,351		$	97,321
Operating income		15,673			34,517			43,315			18,722
Net income		2,552			13,043			18,203			2,614
Earnings per common share:
Basic	$	0.10		$	0.49		$	0.69		$	0.10
Diluted		0.09			0.48			0.67			0.10

(1)	The sum of the four quarters may not equal annual results due to rounding.

(2)

Results for the quarters ended March 31, June 30, September 30, and December 31, 2011 included approximately $0.2 million, $1.0 million, $6.5 million and $1.8 million of operating costs, respectively, related to mobilization and pre-positioning vessels to foreign markets. Results for the quarters ended March 31, June 30, September 30, and December 31, 2010 included approximately $2.4 million, $2.6 million, $3.2 million and $1.5 million of operating costs, respectively, related to mobilization and pre-positioning vessels to foreign markets.

(3)

Results for the quarters ended March 31, and June 30, 2011 were significantly impacted by regulatory-driven weak market conditions in the GoM. The lack of Upstream vessel demand, led to the Company’s decision to stack certain new generation OSVs. Market conditions improved significantly during the quarters ended September 30 and December 31, 2011 and the Company was able to re-activate most of its stacked vessels.

(4)	On November 16, 2011 the Company issued 8.1 million shares of common stock that increased diluted weighted average shares outstanding from 26.9 million as of September 30, 2011 to 31.8 million as of December 31, 2011.

(5)	Results for the quarters ended June 30, September 30, and December 31, 2010 included approximately $22.1 million, $57.1 million and $23.0 million of revenues, respectively, related to oil spill response efforts in the GoM that were completed by December 31, 2010.

F-33

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Covington, the State of Louisiana, on February 29, 2012.


HORNBECK OFFSHORE SERVICES, INC.

By:		/S/ TODD M. HORNBECK
		Todd M. Hornbeck President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ TODD M. HORNBECK (Todd M. Hornbeck)	Chairman of the Board, President, and Chief Executive Officer (Principal Executive Officer)	February 29, 2012

/s/ JAMES O. HARP, JR. (James O. Harp, Jr.)	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 29, 2012

/s/ LARRY D. HORNBECK (Larry D. Hornbeck)	Director	February 29, 2012

/s/ BRUCE W. HUNT (Bruce W. Hunt)	Director	February 29, 2012

/s/ STEVEN W. KRABLIN (Steven W. Krablin)	Director	February 29, 2012

/s/ PATRICIA B. MELCHER (Patricia B. Melcher)	Director	February 29, 2012

/s/ KEVIN O. MEYERS (Kevin O. Meyers)	Director	February 29, 2012

/s/ JOHN T. RYND (John T. Rynd)	Director	February 29, 2012

/s/ BERNIE W. STEWART (Bernie W. Stewart)	Director	February 29, 2012

/s/ NICHOLAS L. SWYKA JR. (Nicholas L. Swyka)	Director	February 29, 2012

S-1

Exhibit Index


Exhibit Number			Description of Exhibit
	1.1	—	Underwriting Agreement, dated as of November 9, 2011 among Barclays Capital Inc., J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, Global Hunter Securities, LLC, Johnson Rice & Company L.L.C., Pritchard Capital Partners LLC, Simmons & Company International, Capital One Southcoast, Inc. CIS Capital Markets LLC, Howard Weil Incorporated, IBERIA Capital Partners, L.L.C. and Hornbeck Offshore Services, Inc. (incorporated by reference to Exhibit 1.1 to the Company’s Current Report on Form 8-K filed November 16, 2011).

	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).

	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).

E-1


Exhibit Number			Description of Exhibit
	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).

	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	—	Facilities Use Agreement effective January 1, 2006, and incorporated Indemnification Agreement and amendments thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed February 21, 2006).

	*10.2^†	—	Director & Advisory Director Compensation Policy, effective January 1, 2012.

	10.3^†	—	Hornbeck Offshore Services, Inc. Deferred Compensation Plan dated as of July 10, 2007 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the period ended June 30, 2007).

	10.4^†	—	Second Amended and Restated Hornbeck Offshore Services, Inc. Incentive Compensation Plan, dated effective May 2, 2006 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 4, 2006).

	10.5^†	—	Amendment to the Second Amended and Restated Hornbeck Offshore Services, Inc Incentive Compensation Plan, dated effective May 12, 2008 (incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q for the period ended March 31, 2008).

E-2


Exhibit Number			Description of Exhibit
	10.6^†	—	Second Amendment to the Second Amended and Restated Hornbeck Offshore Services, Inc Incentive Compensation Plan, dated effective June 24, 2010 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 30, 2010).

	10.7^†	—	Amended and Restated Senior Employment Agreement dated May 7, 2007 by and between Todd M. Hornbeck and the Company (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the period ended March 31, 2007).

	10.8^†	—	Amended and Restated Employment Agreement dated May 7, 2007 by and between Carl G. Annessa and the Company (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the period ended March 31, 2007).

	10.9^†	—	Amended and Restated Employment Agreement dated May 7, 2007 by and between James O. Harp, Jr. and the Company (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q for the period ended March 31, 2007).

	10.10^†	—	Amendment to Amended and Restated Senior Employment Agreement dated effective May 12, 2008 by and between Todd M. Hornbeck and the Company (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the period ended March 31, 2008).

	10.11^†	—	Amendment to Amended and Restated Employment Agreement dated effective May 12, 2008 by and between Carl G. Annessa and the Company (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the period ended March 31, 2008).

	10.12^†	—	Amendment to Amended and Restated Employment Agreement dated effective May 12, 2008 by and between James O. Harp, Jr. and the Company (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q for the period ended March 31, 2008).

	10.13^†	—	Second Amendment to Amended and Restated Senior Employment Agreement dated effective December 31, 2009 by and between Todd M. Hornbeck and the Company (incorporated by reference to Exhibit 10.12 to the Company’s Form 10-K for the period ended December 31, 2009).

	10.14^†	—	Second Amendment to Amended and Restated Employment Agreement dated effective December 31, 2009 by and between Carl G. Annessa and the Company (incorporated by reference to Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 2009).

	10.15^†	—	Second Amendment to Amended and Restated Employment Agreement dated effective December 31, 2009 by and between James O. Harp, Jr. and the Company (incorporated by reference to Exhibit 10.14 to the Company’s Form 10-K for the period ended December 31, 2009).

	10.16^†	—	Employment Agreement dated effective January 1, 2011 by and between Samuel A. Giberga and the Company (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the period ended June 30, 2011).

E-3


Exhibit Number			Description of Exhibit
	10.17^†	—	Change in Control Agreement dated effective August 5, 2008 by and between Samuel A. Giberga and the Company (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended June 30, 2008).

	10.18^†	—	Change in Control Agreement dated effective August 5, 2008 by and between John S. Cook and the Company (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended June 30, 2008).

	10.19^†	—	Change in Control Agreement dated effective August 4, 2009 by and between Kimberly S. Patterson and the Company (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended June 30, 2009).

	10.20^†	—	Amendment to Change in Control Agreement dated effective December 31, 2009 by and between Samuel A. Giberga and the Company (incorporated by reference to Exhibit 10.18 to the Company’s Form 10-K for the period ended December 31, 2009).

	10.21^†	—	Amendment to Change in Control Agreement dated effective December 31, 2009 by and between John S. Cook and the Company (incorporated by reference to Exhibit 10.19 to the Company’s Form 10-K for the period ended December 31, 2009).

	10.22^†	—	Amendment to Change in Control Agreement dated effective December 31, 2009 by and between Kimberly S. Patterson and the Company (incorporated by reference to Exhibit 10.20 to the Company’s Form 10-K for the period ended December 31, 2009).

	10.23	—	Senior Secured Revolving Credit Facility dated effective September 27, 2006 by and among the Company and two of its subsidiaries, Hornbeck Offshore Services, LLC and Hornbeck Offshore Transportation, LLC, and Wells Fargo Bank, N.A., as administrative agent, Comerica Bank, as syndication agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed October 3, 2006).

	10.24	—	First Amendment to Senior Secured Revolving Credit Facility and Second Amendment to Guaranty and Collateral Agreement dated as of November 4, 2009 by and among the Company and two of its subsidiaries, Hornbeck Offshore Services, LLC and Hornbeck Offshore Transportation, LLC, each of the lenders and guarantors signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 6, 2009).

	10.25	—	Second Amendment to Senior Secured Revolving Credit Facility dated as of March 14, 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 guarantors signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010).

E-4


Exhibit Number			Description of Exhibit
	10.26	—	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 guarantors signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).

	10.27	—	Form of Amended and Restated Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended June 30, 2009).

	10.28^†	—	Form of Executive Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 2004).

	10.29^†	—	Form of Director Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.17 to the Company’s Form 10-K for the period ended December 31, 2004).

	10.30^†	—	Form of Employee Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.18 to the Company’s Form 10-K for the period ended December 31, 2004).

	10.31^†	—	Form of Restricted Stock Unit Agreement for Executive Officers (Time Vesting) (incorporated by reference to Exhibit 10.7 to the Company’s Form 10-Q for the quarter ended March 31, 2008).

	10.32^†	—	Form of Restricted Stock Unit Agreement for Non-Employee Directors (Time Vesting) (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-Q for the quarter ended March 31, 2008).

	10.33^†	—	Form of Restricted Stock Unit Agreement for Executive Officers (Performance Based) (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q for the quarter ended March 31, 2008).

	10.34^†	—	Form of Restricted Stock Unit Agreement for Executive Officers (Performance Based) (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2009).

	10.35^†	—	Form of Restricted Stock Unit Agreement for Executive Officers (Time Vesting) (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended March 31, 2009).

	10.36^†	—	Form of Restricted Stock Unit Agreement for Executive Officers (Performance Based) (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2010).

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

E-5


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

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

	10.40	—	Purchase Agreement dated August 12, 2009 by and among Hornbeck Offshore Services, Inc., the guarantors named therein, and J.P. Morgan Securities Inc. as representative of the several Purchasers named in Schedule I thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 18, 2009).

	*10.41	—	Vessel Construction Agreement dated November 14, 2011 by and between Hornbeck Offshore Services, Inc. and VT Halter Marine, Inc. (portions of this exhibit have been omitted pursuant to a request for confidential treatment filed with the Securities and Exchange Commission).

	*10.42	—	Form of Amended Appendix A to Employment Agreements for Executive Officers.

	*10.43	—	Consulting Agreement dated February 14, 2012 by and between Hornbeck Offshore Services, Inc. and Larry D. Hornbeck.

	*21	—	Subsidiaries of the Company

	*23.1	—	Consent of Ernst & Young LLP

	*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.

†	Compensatory plan or arrangement under which executive officers or directors of the Company may participate.

E-6