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Hornbeck Offshore Services 10-K 2013
Form 10-K
Table of Contents

 

 

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, 2012

OR

 

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

For the Transition Period from                 to

Commission File Number 001-32108

 

 

Hornbeck Offshore Services, Inc.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware    72-1375844

(State or other jurisdiction of

incorporation or organization)

  

(I.R.S. Employer

Identification Number)

103 Northpark Boulevard, Suite 300

Covington, 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  x   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 $1,324,496,502.

The number of outstanding shares of Common Stock as of January 31, 2013 is 35,484,231 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive 2013 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.

 

 

 


Table of Contents

HORNBECK OFFSHORE SERVICES, INC. AND SUBSIDIARIES

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012

TABLE OF CONTENTS

 

PART I

     1   
  Item 1—Business      1   
  Item 1A—Risk Factors      19   
  Item 1B—Unresolved Staff Comments      32   
  Item 2—Properties      33   
  Item 3—Legal Proceedings      33   
  Item 4—Mine Safety Disclosures      33   

PART II

     34   
 

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

     34   
  Item 6—Selected Financial Data      35   
 

Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations

     39   
  Item 7A—Quantitative and Qualitative Disclosures About Market Risk      62   
  Item 8—Financial Statements and Supplementary Data      63   
 

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

     63   
  Item 9A—Controls and Procedures      63   
  Item 9B—Other Information      66   

PART III

     70   
  Item 10—Directors, Executive Officers and Corporate Governance      70   
  Item 11—Executive Compensation      70   
 

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

     70   
 

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

     70   
  Item 14—Principal Accounting Fees and Services      70   

PART IV

     71   
 

Item 15—Exhibits and Financial Statement Schedules

     71   
CONSOLIDATED FINANCIAL STATEMENTS      F-1   
SIGNATURES      S-1   
EXHIBIT INDEX      E-1   

 

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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,” “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 inconsistency by the United States government in the pace of issuing drilling permits and plan approvals in the GoM; the Company’s inability to successfully complete its fifth OSV newbuild program and its 200 class OSV retrofit program on-time and on-budget, which involves the construction, conversion and integration of highly complex vessels and systems; the inability to successfully market the vessels that the Company owns, is constructing or might acquire; an oil spill or other significant event in the United States or another offshore drilling region that could have a broad impact on deepwater and other offshore energy exploration and production activities, such as the suspension of activities or significant regulatory responses; the imposition of laws or regulations that result in reduced exploration and production activities or that increase the Company’s operating costs or operating requirements, including any such laws or regulations that may yet arise as a result of the Deepwater Horizon incident or the resulting drilling moratoria and regulatory reforms, as well as the outcome of pending litigation brought by environmental groups challenging exploration plans approved by the Department of Interior; less than anticipated success in marketing and operating the Company’s MPSVs; bureaucratic, administrative or operating barriers that delay vessels chartered in foreign markets from going on-hire or result in contractual penalties or deductions imposed by foreign customers; renewed weakening of demand for the Company’s services; unplanned customer suspensions, cancellations, rate reductions or non-renewals of vessel charters or failures to finalize commitments to charter vessels; the impact of planned sequester of federal spending pursuant to the Budget Control Act of 2011; industry risks; reductions in capital spending budgets by customers; a material reduction of Petrobras’ announced plans for administrative barriers to exploration and production activities in Brazil; sustained 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 in the GoM and other markets; the level of fleet additions by the Company and its competitors that could result in over capacity in the markets in which the Company competes; economic and political risks; weather-related risks; the shortage of or the inability to attract and retain qualified personnel, including vessel personnel for active, unstacked and newly constructed vessels; regulatory risks; the repeal or administrative weakening of the Jones Act, including any changes in the interpretation of the Jones Act

 

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related to the U.S. citizenship qualification; drydocking delays and cost overruns and related risks; vessel accidents or pollution incidents resulting in lost revenue or expenses that are unrecoverable from insurance policies or other third parties; unexpected litigation and insurance expenses; fluctuations in foreign currency valuations compared to the U.S. dollar and risks associated with expanded foreign operations, such as non-compliance with or the unanticipated effect of tax laws, customs laws, immigration laws, or other legislation that result in higher than anticipated tax rates or other costs or the inability to repatriate foreign-sourced earnings and profits. In addition, the Company’s future results may be impacted by adverse economic conditions, such as inflation, deflation, or lack of liquidity in the capital markets, that may negatively affect it or parties with whom it does business resulting in their non-payment or inability to perform obligations owed to the Company, such as the failure of customers to fulfill their contractual obligations or the failure by individual banks to provide funding under the Company’s credit agreement, if required. Should one or more of the foregoing risks or uncertainties materialize in a way that negatively impacts the Company, or should the Company’s underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated in its forward-looking statements, and its business, financial condition and results of operations could be materially and adversely affected. Additional factors that you should consider are set forth in detail in the “Risk Factors” section of 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, which is 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 67.

 

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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 select 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 primarily operating in three core geographic markets: the GoM, Brazil and Mexico. As discussed below, we commenced our fifth OSV newbuild program in late-2011, which also includes the construction of MPSVs. Upon completion of the vessels currently contracted or approved to be constructed under this newbuild program, our expected Upstream fleet will increase to 73 OSVs and six MPSVs, provided that, as previously announced, in lieu of building two of these OSVs, we may elect to construct additional Jones Act-qualified MPSVs. 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. We have also developed a specialized application of our new generation OSVs for use by the U.S. military. All of our OSVs and MPSVs 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. We believe we are one of the top 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. Upon completion of our current newbuild program, we believe that our Upstream fleet will have an average vessel age of nine years at the end of 2015.

We have historically operated our Upstream segment predominately in the U.S. GoM. Since 2010, we have sought to diversify our market presence by also operating in overseas markets. We have focused our international efforts in Mexico, Brazil and the Middle East region. As of December 31, 2012, we had 19 new generation OSVs working in foreign markets compared to 24 vessels and 16 vessels as of December 31, 2011 and 2010, respectively. Our Upstream segment also includes a shore-base support facility located in

 

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Port Fourchon, Louisiana. See Item 2-Properties for a listing of our shoreside support facilities. 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 an active fleet of nine ocean-going tugs and nine double-hulled tank barges that transport petroleum products, primarily in the northeastern United States and the GoM. For the twelve months ended December 31, 2012, our Upstream and Downstream segments contributed 97% and 3% 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. All of the vessels being constructed under our fifth newbuild program will qualify for Jones Act coastwise trading privileges. 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. From time to time we may elect to reflag certain of our U.S.-flag vessels to the flag of another nation. For instance, since 2009 we have reflagged five Upstream vessels to Mexican flag. Once a Jones Act qualified vessel is reflagged, it permanently loses its right to return to the U.S. coastwise trade. All of our Downstream vessels are Jones Act-qualified.

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

 

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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 24 of the vessels currently contracted or approved to be constructed under our fifth OSV newbuild program are expected to be DP-2. In September 2012, the Company commenced a vessel retrofit program intended to convert six Super 200 class DP-1 vessels into 240 class DP-2 vessels. We expect to incur approximately 762 vessel-days of aggregate commercial downtime for these vessels (127 days each) and these vessels will be redelivered to the Company in their larger new DP-2 configurations on various dates between April and December 2013.

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 75% 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 2010 Deepwater Horizon incident in the GoM. 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 with such capabilities. These MPSVs have approximately double the deadweight and three times the liquid mud barrel-capacity of

 

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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 Jones Act-qualified 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.

During 2012, in recognition of the significant transformational modification of these vessels, the United States reclassified the year-of-build for these vessels to 2008, as opposed to the sulfur-carriers’ original build date of 1992.

In 2007 and 2008, we expanded our MPSV program to include the HOS Iron Horse and HOS Achiever which 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.

We recently announced our intentions to ultimately build up to eight Jones Act-qualified MPSVs as a subset of our growing fifth OSV newbuild program to service the subsea construction and IRM market. The first two vessel commitments to be reconfigured as a new class of domestic MPSVs will be based upon the HOSMAX 310 vessel design, with expected delivery in 2015. We are currently evaluating plans to either exercise our next two options to build additional HOSMAX OSVs for delivery in 2015; or (in lieu of building those vessels) constructing one or more additional new Jones Act-qualified MPSVs. We are currently negotiating with shipyards regarding these new vessels and how these new vessels will impact our outstanding contractual options.

 

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The following table provides information, as of February 15, 2013, regarding our Upstream fleet of 51 new generation OSVs, four MPSVs and the 22 new generation OSVs and two MPSVs contracted or approved 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)   Venezuela     Nov 2009        9,000        n/a        8,000        DP-3   

HOS Achiever

  430   Multi-Purpose (FF)   GoM     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   

HOS Newbuild #21

  310   Multi-Purpose   TBD     TBD        TBD        TBD        TBD        DP-2   

HOS Newbuild #22

  310   Multi-Purpose   TBD     TBD        TBD        TBD        TBD        DP-2   

OSVs

               

300 class (Over 5,000 DWT)

               

HOS Commander

  320   Supply   TBD     4Q2013 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Carolina

  320   Supply   TBD     4Q2013 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Claymore

  320   Supply   TBD     1Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Captain

  320   Supply   TBD     1Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Clearview

  320   Supply   TBD     2Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Crockett

  320   Supply   TBD     2Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Caledonia

  320   Supply   TBD     2Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Crestview

  320   Supply   TBD     3Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Cedar Ridge

  320   Supply   TBD     4Q2014 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Carousel

  320   Supply   TBD     1Q2015 est.(3)        6,200 est.        20,900 est.        6,000 est.        DP-2   

HOS Newbuild #23(4)

  TBD   Supply   TBD     TBD        TBD        TBD        TBD        DP-2   

HOS Newbuild #24(4)

  TBD   Supply   TBD     TBD        TBD        TBD        TBD        DP-2   

HOS Bayou

  310   Supply   TBD     1Q2014 est.(3)        6,100 est.        22,700 est.        6,700 est.        DP-2   

HOS Black Foot

  310   Supply   TBD     2Q2014 est.(3)        6,100 est.        22,700 est.        6,700 est.        DP-2   

HOS Black Rock

  310   Supply   TBD     3Q2014 est.(3)        6,100 est.        22,700 est.        6,700 est.        DP-2   

HOS Black Watch

  310   Supply   TBD     4Q2014 est.(3)        6,100 est.        22,700 est.        6,700 est.        DP-2   

HOS Brass Ring

  310   Supply   TBD     4Q2014 est.(3)        6,100 est.        22,700 est.        6,700 est.        DP-2   

HOS Briarwood

  310   Supply   TBD     1Q2015 est.(3)        6,100 est.        22,700 est.        6,700 est.        DP-2   

HOS Red Dawn

  300   Supply   TBD     2Q2013 est.(3)        5,600 est.        21,100 est.        6,700 est.        DP-2   

HOS Red Rock

  300   Supply   TBD     3Q2013 est. (3)      5,600 est.        21,100 est.        6,700 est.        DP-2   

HOS Renaissance

  300   Supply   TBD     4Q2013 est.(3)        5,600 est.        21,100 est.        6,700 est.        DP-2   

HOS Riverbend

  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(5)

  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   GoM     Aug 2002        3,756        10,400        6,700        DP-2   

HOS Sandstorm

  265   Supply   GoM     Oct 2002        3,756        10,400        6,700        DP-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

  250 EDF   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   Mexico     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   

 

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Name(1)

  Design   Current
Service
Function
  Current
Location
  In-Service
Date
  Deadweight
(long tons)
  Liquid Mud
Capacity
(barrels)
  Brake
Horsepower
  DP
Class(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-2

HOS Hope(6)

  200   Supply   Mexico   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(6)

  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(6)

  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(6)

  200   Supply   GoM   Oct 2000   2,250   4,100   4,200   DP-1

HOS St. James(6)

  200   Supply   GoM   Oct 1999   2,246   4,100   4,200   DP-1

HOS St. John(6)

  200   Supply   GoM   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   GoM   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

HOS Mariner

  220   Supply   GoM   Sep 1999   1,607   3,100   3,900   DP-1

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

Inactive:(7)

               

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

             

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 2015.
(4) In lieu of these two OSVs, we may build one or more additional Jones Act-qualified MPSVs.
(5) The HOS Ridgewind was formerly known as (f/k/a) the BJ Blue Ray and the Independence.
(6) These six DP-1 vessels are included in our 200 class OSV retrofit program to be converted into 240 class DP-2 OSVs. Upon re-delivery from the shipyard on various dates in 2013, these upgraded vessels will be re-named the HOS Boudin (f/k/a HOS Davis), HOS Beignet (f/k/a HOS North), HOS Coquille (f/k/a HOS St. James), HOS Bourre’ (f/k/a HOS Byrd), HOS Chicory (f/k/a HOS St. John), and the HOS Cayenne (f/k/a HOS Hope). See Note 5 to our Consolidated Financial Statements for further discussion regarding our OSV retrofit program.
(7) In response to weak market conditions during the drilling moratoria in the GoM, 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 all but one of our new generation OSVs as of December 31, 2012. That vessel is expected to remain inactive until there is sustainable demand for the vessel.

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 two 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.

 

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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 91 floating rigs under construction or on order on January 31, 2013 and, as of that date, there were options outstanding to build 38 additional floating rigs. In addition, on that date, there were 84 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 31 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. In Brazil, transit time for a new generation vessel to some of the newer, more logistically remote deepwater drilling rig locations are more appropriately measured in days, not hours. In addition to drilling rig support, deepwater and ultra-deepwater exploration and production activities will result in the expansion of other specialty-service offerings for our vessels. These markets include subsea construction support, installation, IRM work, and life-of-field services, which include well-stimulation, workovers and decommissioning.

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

 

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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 significantly and adversely disrupted oil and gas exploration activities in the GoM. Shortly after the explosion, the DOI imposed a moratorium effectively suspending all deepwater drilling activity in the GoM. Although this formal moratorium was lifted in October 2010, related delays in permitting and uncertainty regarding new safety regulations had a lingering effect on OSV fundamentals through mid-2011. In response to these events and in order to lessen our exposure to a single market, we expanded our international presence by mobilizing additional vessels out of the GoM into foreign markets such as Latin America, West Africa, and other regions during 2011 and 2012. We have since concentrated our international efforts on Mexico, Brazil and, to a lesser extent, the Middle East. During 2012, we experienced a significant improvement in market conditions in the GoM and determined to repatriate some of our vessels to the GoM from Brazil, including four of the six DP-1 vessels that we have since selected to retrofit into DP-2 vessels.

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 offshore support vessel 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 56 Upstream vessels are U.S.-flagged vessels, which are qualified under the Jones Act to engage in domestic coastwise trade. The Jones Act restricts the ability

 

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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 and the HOSMAX MPSVs to be constructed under our recently expanded fifth OSV newbuild program will 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 have, for some time, observed a clear preference by our customers for a “one-stop” Jones Act solution, which would provide improved efficiencies, derived from a single U.S.-flagged vessel as well as greater regulatory certainty as compliance questions continue to arise from the use of foreign-flagged vessels in the subsea GoM. In the post-Macondo GoM, we see this Jones Act preference as a long-term trend, not only for construction vessels but for vessels of all types working offshore.

In the wake of the Deepwater Horizon incident, we have observed intensified scrutiny by our customers placed on the safety and environmental management systems of vessel operators. As a consequence, we believe that deepwater customers are increasingly biased towards companies that have demonstrated a financial and operational commitment and capacity to employ such systems. We believe this trend will, over time, make it difficult for small enterprises to compete effectively in the deepwater OSV market. Additionally, we have observed less willingness by operators to utilize DP-1 vessels in deepwater operations, in the GoM. This trend will likely result in the retirement of non-DP vessels and a migration of DP-1 vessels to non-deepwater regions, such as the shelf, and certain international regions.

 

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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 financial strength, 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 two years to 15 years. In fact, approximately 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 35 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 moratoria in the GoM. Upon completion of our fifth OSV newbuild program and the retrofit of six DP-1 vessel to DP-2, we will own a fleet of 79 Upstream vessels of which 77% are DP-2 or DP-3 with an average age of nine years in 2015.

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. In order to maintain our competitiveness for qualified licensed vessel personnel, we increased our Upstream crew wages in April 2012 by roughly $5.0 million per quarter.

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. Recently, with the increased amount of domestically produced shale oil, the need to transport crude oil between locations in the GoM and other U.S. points has increased the demand for tank barge services

 

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in regions outside of the northeastern United States. We have observed greater demand for our vessels in the gulf coast region than previously and currently the majority of our vessels are now positioned in the GoM.

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 five 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.

The following tables provide information, as of February 15, 2013, regarding our Downstream fleet of 14 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

     169         126       1982/2005      6,140       GoM

Liberty Service

     169         126       1982/2005      6,140       Northeast

Patriot Service

     195         124       1996/2006      6,140       GoM

Eagle Service

     195         124       1996/2006      6,140       GoM

Gulf Service

     182         126       1979      3,900       GoM

Erie Service

     147         105       1981/2008      3,620       Puerto Rico

Superior Service

     147         105       1981/2008      3,620       GoM

Huron Service

     107         105       1981/2007      3,000       Northeast

Michigan Service

     107         105       1981/2007      3,000       GoM

Inactive:(2)

              

Caribe Service

     190         111       1970      3,900       Laid Up

Brooklyn Service

     198         109       1975      3,900       Laid Up

Atlantic Service

     198         109       1978      3,900       Laid Up

Tradewind Service

     183         105       1975      2,820       Laid Up

Sea Service

     177         109       1975      2,820       Laid Up

 

(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 five lower-horsepower tugs on various dates since April 1, 2008. These inactive vessels are currently being marketed for sale.

 

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Ocean-Going Double-Hulled Tank Barges

 

Name

   Barrel
Capacity
     Length
(feet)
     Year
Built
     Current
Service(1)
     Current
Location

Energy 13501

     135,380         450         2005         DPP       GoM

Energy 13502

     135,380         450         2005         DPP       GoM

Energy 11103

     111,699         390         2005         DPP       GoM

Energy 11104

     111,699         390         2005         DPP       GoM

Energy 11105

     111,699         390         2005         CPP       Northeast

Energy 8001

     81,063         350         1996         DPP       Puerto Rico

Energy 6506

     64,282         362         2007         CPP       Northeast

Energy 6507

     64,282         362         2007         DPP       GoM

Energy 6508

     64,282         362         2008         CPP       GoM

 

(1) All of our double-hulled tank barges, except the Energy 8001, are equipped with vapor recovery systems. This allows the vessels to carry a wider range of both CPP and DPP products.

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.

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, 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.

 

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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 mariners that crew 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 14 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, 2012, Petrobras and Chevron Corporation each accounted for more than 10% of our total revenues. Our contracts with Petrobras and Chevron Corporation are subject to cancellation at the election of such entities. Additionally, our contract with Chevron Corporation contains penalties in the event we are not able to perform under such contract. For a discussion of significant customers in prior periods, see Note 13 to our consolidated financial statements.

 

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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 amend and augment the oil spill provisions of the Clean Water Act and impose a variety of duties and liabilities on “responsible parties” related to the prevention and/or reporting of oil spills and damages resulting from such spills in or threatening U.S. Waters, including the Outer Continental Shelf or adjoining shorelines. 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 containment and oil removal costs, as well as a variety of public and private damages including the costs of responding to a release of oil, natural resource damages, damages for injury to, or economic losses resulting from, destruction of real or personal property of persons who own or lease such affected property. 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

 

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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. Because all our tank vessels were built in compliance with OPA 90, none of our vessels are subject to this OPA 90 phase-out period.

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 treatment, storage and 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 published its final Ballast Rule on March 23, 2012, which became effective on June 21, 2012 requiring all our existing vessels to meet certain

 

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standards pertaining to ballast water discharges, 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 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 “greenhouse gases” 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. The EPA has adopted regulations under the Clean Air Act that require new and existing industrial facilities to obtain permits for carbon dioxide equivalent emissions above emission thresholds. In addition, the EPA adopted rules that mandate reporting of greenhouse gas data and other information by i) industrial sources, ii) suppliers of certain products, and iii) facilities that inject carbon dioxide underground. To the extent that these regulations may apply, we could be responsible for costs associated with complying with such regulations. 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 GoM in particular. We are currently unable to predict the manner or extent of any such effect.

EMPLOYEES

On December 31, 2012, we had 1,263 employees, including 997 operating personnel and 266 corporate, administrative and management personnel. Excluded from these personnel totals are 327 third-country nationals, or TCNs, that we contracted to serve on our

 

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vessels as of December 31, 2012. 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. Periodically, we also update our investor presentations which can be viewed on our website. 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,

 

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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.

 

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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, our OSV retrofit program 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 20 new generation, high-spec OSVs and have options with the shipyards to build additional vessels. In February 2013, we announced plans to expand our fifth OSV newbuild program by four vessels, as well as our intentions to ultimately build up to eight Jones Act-qualified MPSVs as a subset of the newbuild program. We are currently negotiating with shipyards with regard to these new vessels and how these new vessels will impact our outstanding contractual options. In September 2012, the Company announced its OSV retrofit program for the upgrading and stretching of six 200 class DP-1 OSVs and converting them into 240 class DP-2 OSVs. We routinely engage shipyards to drydock our vessels for regulatory compliance and to provide repair and maintenance. Our vessel newbuild program, retrofit 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:

 

   

local and international political and economic conditions and policies;

 

   

changes in capital spending budgets by our customers;

 

   

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

 

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

 

   

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

 

   

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

 

   

worldwide demand for oil and natural gas;

 

   

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

 

   

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

 

   

technological advances affecting energy production and consumption;

 

   

weather conditions;

 

   

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

 

   

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

As discussed herein, oil and gas exploration, development and production activity in the GoM declined sharply in the wake of the federal government’s drilling 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 negatively impact the pace of 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 $142 billion on exploration and production activities from 2012 through 2016 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 continued 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

 

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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 fifth OSV Newbuild Program, 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 200 class OSV retrofit program, our 1.625% convertible senior notes due 2026, our 8.000% senior notes due 2017, our 5.875% senior notes due 2020 or our 1.500% convertible senior notes due 2019.

Under our recently expanded fifth OSV newbuild program, we will be required to spend approximately $1,160 million, excluding capitalized construction period interest, for the construction of vessels currently under contract or approved, of which $274.6 million has been paid as of December 31, 2012. 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 2015, based on construction milestones. During 2013, we anticipate spending approximately $47.7 million related to our ongoing 200 class OSV retrofit program. In November 2013, holders of the 1.625% convertible senior notes may require us to purchase their notes for cash. At that time we intend to use a portion of the proceeds from the sale of our 1.500% convertible senior notes, along with other available sources of cash, to retire these 1.625% convertible senior

 

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notes. Our 8.000% senior notes, our 5.875% senior notes and our 1.500% senior notes mature in August 2017, April 2020 and September 2019, respectively. In addition, upon the occurrence of certain change of control events, as defined in the indentures governing the 8.000% senior notes and 5.875% 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. Further, upon certain fundamental changes as defined in the indentures governing the 1.625% convertible senior notes due 2026 and the 1.500% convertible senior notes due 2019, holders of such notes would have the right to require us to repurchase such notes at 100% of their principal amount, plus any 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. Failure to meet our obligations related to our fifth OSV newbuild program, our 200 class OSV retrofit program, our 1.625% convertible senior notes, our 8.000% senior notes, our 5.875% senior notes and our 1.500% convertible 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:

 

   

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

 

   

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;

 

   

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

 

   

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

 

   

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

 

   

dilution of stock ownership of existing stockholders;

 

   

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

 

   

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 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 could adversely affect the revenues of our Downstream business. This reduction 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

 

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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.

Our contracts with the United States Government may be impacted by sequester of federal spending.

Pursuant to the Budget Control Act of 2011, the United States will implement sequester of federal spending commencing March 1, 2013, unless the sequestration trigger is postponed or removed by legislation. The sequestration will require elimination of approximately $85 billion in federal spending during 2013, including a significant amount of Department of Defense spending. It is possible that our long-term contracts with the government may be impacted in the event sequestration occurs or as a result of legislation implemented to avoid the sequester. Included among the possible impacts are contractual terminations, the exercise by the government of purchase options on certain of our vessels, the non-renewal of contracts or the non-exercise of extension options.

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 EPA 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, and/or operational changes. While we endeavor to comply with all applicable laws, circumstances might exist where we might not come into complete compliance with applicable laws and regulations which could result in administrative and civil penalties, criminal sanctions, imposition of remedial obligations or the suspension or termination of our operations. Some environmental laws

 

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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.

 

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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:

 

   

catastrophic marine disaster;

 

   

adverse weather and sea conditions;

 

   

mechanical failure;

 

   

collisions or allisions;

 

   

oil and hazardous substance spills;

 

   

navigation errors;

 

   

acts of God; and

 

   

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

 

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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.

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

In crewing our vessels, we require skilled employees who can perform physically demanding work. As a result of the volatility of the oil and gas industry and the demanding nature of the work, potential vessel employees may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. Further, we face strong competition within the broader oilfield industry for potential employees, including competition from drilling rig operators for our fleet personnel. As the vessels being constructed in our OSV Newbuild Program #5 are delivered and placed in service, we may not be able to hire 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

 

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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 8.000% senior notes due 2017, our 5.875% senior notes due 2020, 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 indenture governing our 8.000% senior notes due 2017, in the indenture governing our 5.875% senior notes due 2020 and in the agreement governing our revolving credit facility require us to meet certain financial tests, which may limit or otherwise restrict:

 

   

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

 

   

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

 

   

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 from 2009 to 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

 

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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 current global economic downturn may adversely impact our ability to issue additional debt and equity in the future on acceptable terms. 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 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

 

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new interpretations of existing regulations regarding operations in the GoM 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.

 

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The fundamental change purchase feature of our 1.625% convertible senior notes, our 1.500% 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% and 1.500% 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 transactions may affect the value of our common stock.

In connection with the original issuance of our 1.625% convertible senior notes and our 1.500% convertible senior notes, we entered into convertible note hedge transactions with counterparties that include the initial purchasers or their affiliates. The convertible note hedge transactions cover, subject to customary anti-dilution adjustments, the aggregate number of shares of our common stock that will initially underlie the notes, and are expected to reduce the potential equity dilution, and/or offset cash payments due, upon conversion of the notes in the event the volume-weighted average price of our common stock on each trading day of the relevant conversion period or other relevant valuation period is greater than the strike price of the convertible note hedge transactions. Concurrently with entering into the convertible note hedge transactions, we also entered into separate warrant transactions with the same counterparties relating to the same number of shares of our common stock, subject to customary anti-dilution adjustments, pursuant to which we sold warrants to the counterparties. If the warrants are exercised, such exercise would mitigate some of the reduction upon exercise of the convertible note hedge transactions, and could have a dilutive effect on our earnings per share to the extent that the volume-weighted average price of our common stock during the measurement period at maturity of the warrants exceeds the strike price of the sold warrants.

In connection with establishing their initial hedges of these transactions, such counterparties or their affiliates entered into various cash-settled over-the-counter derivative transactions with respect to our common stock. The counterparties or their affiliates may modify their hedge positions by unwinding these derivative transactions, entering into or unwinding additional cash-settled over-the-counter derivative transactions and/or purchasing or selling our common stock or other of our securities in secondary market transactions from time to time following the pricing of the notes and prior to maturity of the notes (and are likely to do so during any conversion period related to any conversion of the notes).

The potential 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 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.

 

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We do not make any representation or prediction as to the direction or magnitude of any potential effect that the transactions described above may have on the price of our common stock. In addition, we do not make any representation that the counterparties to those transactions will engage in these transactions or activities or that these transactions and activities, once commenced, will not be discontinued without notice; the counterparties or their affiliates may choose to engage in, or discontinue engaging in, any of these transactions or activities with or without notice at any time, and their decisions will be in their sole discretion and not within our control.

We are subject to counterparty risk with respect to the convertible note hedge transactions.

The counterparties to the convertible note hedge transactions are financial institutions, and we will be subject to the risk that any or all of them might default under the convertible note hedge transactions. Our exposure to the credit risk of the counterparties will not be secured by any collateral. Recent global economic conditions have resulted in the actual or perceived failure or financial difficulties of many financial institutions. If a counterparty becomes subject to insolvency proceedings, we will become an unsecured creditor in those proceedings, with a claim equal to our exposure at that time under our transactions with that counterparty. Our exposure will depend on many factors but, generally, an increase in our exposure will be correlated to an increase in the market price and in the volatility of our common stock. In addition, upon a default by a counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of the counterparties to the convertible note hedge transactions.

Conversion of the 1.625% convertible senior notes or the 1.500% 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 the 1.500% 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 our convertible 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 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.

 

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ITEM 2—Properties

Our principal executive offices are in Covington, Louisiana, where we lease approximately 61,000 square feet of office space under a lease with an initial term expiring in September 2025 and three additional five-year renewal periods. 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, 2012 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

The Company has made presentment of a claim to BP in the class action lawsuit arising from the Deepwater Horizon tragedy. Doing so has allowed the Company to preserve claims against BP under OPA 90 assuming the Company has claims that are compensable under the court-approved settlement reached between BP and class action plaintiffs.

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

Item 4—Mine Safety Disclosures

None.

 

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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 2012 and 2011.

 

     2012      2011  
     High      Low      High      Low  

First Quarter

   $ 43.47       $ 31.26       $ 31.77       $ 19.87   

Second Quarter

   $ 43.83       $ 31.68       $ 31.38       $ 23.65   

Third Quarter

   $ 43.78       $ 34.00       $ 29.39       $ 19.80   

Fourth Quarter

   $ 38.06       $ 31.96       $ 36.24       $ 21.96   

On January 31, 2013, we had 26 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 8.000% senior notes, our 5.875% 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.

 

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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, 2012, 2011, 2010, 2009, and 2008 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 Managements 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,  
     2012     2011     2010     2009     2008  

Statement of Operations Data:

          

Revenues

   $ 512,738      $ 381,627      $ 420,804      $ 385,948      $ 432,084   

Operating expenses

     255,398        211,201        196,771        161,188        164,532   

Depreciation and amortization(1)

     87,808        81,587        77,055        93,369        52,002   

General and administrative expenses

     48,499        35,363        36,774        30,844        37,155   

Gain on sale of assets

     274        1,539        2,025        1,147        8,402   

Operating income

     121,307        55,015        112,229        101,694        186,797   

Loss on early extinguishment of debt

     (6,048     —          —          —          —     

Interest income

     2,167        829        528        482        1,525   

Interest expense

     57,869        59,649        55,183        21,024        8,331   

Other income (expenses)(2)

     186        442        344        (597     190   

Income (loss) before income taxes

     59,743        (3,363     57,918        80,555        180,181   

Income tax expense (benefit)

     22,726        (802     21,502        30,155        64,379   

Net income (loss)

     37,017        (2,561     36,416        50,400        115,802   

Per Share Data:

          

Basic net income (loss)

   $ 1.05      $ (0.09   $ 1.38      $ 1.94      $ 4.48   

Diluted net income (loss)

   $ 1.03      $ (0.09   $ 1.34      $ 1.87      $ 4.29   

Weighted average basic shares outstanding

     35,311        27,876        26,396        26,040        25,840   

Weighted average diluted shares outstanding(3)

     36,080        27,876        27,176        26,975        27,020   

Balance Sheet Data (at period end):

          

Cash and cash equivalents

   $ 576,678      $ 356,849      $ 126,966      $ 51,019      $ 20,216   

Working capital

     388,004        401,216        162,156        85,736        66,069   

Property, plant, and equipment, net

     1,812,110        1,605,785        1,606,121        1,602,663        1,405,340   

Total assets

     2,631,731        2,136,346        1,878,425        1,786,348        1,595,743   

Total short-term debt(4)

     238,907        —          —          —          —     

Total long-term debt(5)

     850,530        770,648        758,233        746,674        618,519   

Total stockholders’ equity

     1,165,845        1,072,988        841,877        797,063        736,900   

Statement of Cash Flows Data:

          

Net cash provided by (used in):

          

Operating activities

   $ 145,440      $ 65,651      $ 131,732      $ 183,244      $ 206,832   

Investing activities

     (259,777     (62,299     (56,987     (263,050     (487,293

Financing activities

     334,345        226,914        1,147        110,590        127,109   

Other Financial Data (unaudited):

          

EBITDA(6)

   $ 203,253      $ 137,044      $ 189,628      $ 194,466      $ 238,989   

Capital expenditures

     264,099        73,638        61,643        273,646        505,105   

Other Operating Data (unaudited)(7):

          

Offshore Supply Vessels:

          

Average number of new generation OSVs(8)

     51.0        51.0        49.9        43.2        36.4   

Average number of active new generation OSVs(9)

     48.3        41.8        42.4        39.2        36.4   

Average new generation OSV fleet capacity (DWT)

     128,190        128,190        124,965        105,858        84,892   

Average new generation OSV vessel capacity (DWT)

     2,514        2,514        2,507        2,448        2,329   

Average new generation OSV utilization rate(10)

     83.2     71.5     71.6     79.9     95.4

Effective new generation OSV utilization rate(11)

     87.8     87.2     84.3     88.0     95.4

Average new generation OSV dayrate(12)

   $ 23,445      $ 21,121      $ 21,561      $ 21,348      $ 22,939   

Effective dayrate(13)

   $ 19,506      $ 15,102      $ 15,438      $ 17,057      $ 21,884   

Double-hulled Tank Barges(14):

          

Average number of tank barges(15)

     9.0        9.0        9.0        9.0        8.8   

Average fleet capacity (barrels)(15)

     884,621        884,621        884,621        884,621        872,347   

Average barge capacity (barrels)

     98,291        98,291        98,291        98,291        98,824   

Average utilization rate(10)

     88.2     88.1     80.5     71.5     85.0

Average dayrate(16)

   $ 17,012      $ 17,557      $ 17,502      $ 21,138      $ 21,806   

Effective dayrate(13)

   $ 15,005      $ 15,468      $ 14,089      $ 15,114      $ 18,535   

 

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(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.
(2) Represents other operating income and expenses, including equity in income from investments and foreign currency transaction gains or losses.
(3) For the year ended December 31, 2012, the Company had no anti-dilutive stock options. 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, and 2008 stock options representing rights to acquire 400, 414, and 3 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 1.625% convertible senior notes in the amount of $11,093 as of December 31, 2012. These notes are putable by the holders to the Company on November 15, 2013 and therefore are classified as short-term debt. In addition, these notes are callable by the Company on November 15, 2013, and the Company intends to do so.
(5) Excludes original issue discount associated with our 6.125% senior notes in the amount of $215, $279, $341, and $398 as of December 31, 2011, 2010, 2009, and 2008, respectively; original issue discount associated with our 8.000% senior notes in the amount of $4,771, $5,571, $6,305, and $6,980 as of December 31, 2012, 2011, 2010 and 2009, respectively; imputed 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, and 2008, respectively; and imputed original issue discount associated with our 1.500% convertible senior notes in the amount of $69,699 as of December 31, 2012.
(6) See our discussion of EBITDA as a non-GAAP financial measure immediately following these footnotes.
(7) Excluded from the Other Operating Data are the results of operations for our MPSVs, our shore-base facility, and vessel management services. 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.
(8) We owned 51 new generation OSVs as of December 31, 2012. Our average number of new generation OSVs for the years ended December 31, 2012, 2011, 2010, 2009 and 2008 reflect the deliveries of certain 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 5 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 also acquired in August 2007, nine of which have been sold on various dates in 2008, 2009, and 2010. Our sole remaining conventional OSV, which is stacked, is considered a non-core asset.
(9) 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 all but one of our stacked new generation OSVs as of December 31, 2012. That vessel is expected to remain inactive until there is sustainable demand for the vessel.
(10) Utilization rates are average rates based on a 365-day year. Vessels are considered utilized when they are generating revenues.
(11) 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.
(12) 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.
(13) Effective dayrate represents the average dayrate multiplied by the average utilization rate.
(14) Other Operating Data for tugs and tank barges reflects our active Downstream fleet of nine double-hulled barges and nine ocean-going tugs. We also own five older, lower-horsepower tugs, which we consider to be non-core assets and are marketed for sale. We previously owned a fleet of single-hulled tank barges; however, all of these non-OPA 90 compliant vessels have been sold as they were also considered non-core assets.
(15) The tank barge averages for the years ended December 31, 2012, 2011, 2010, 2009, and 2008 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, 2012, our double-hulled tank barge fleet consisted of nine vessels.
(16) 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

 

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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, 2012, 2011, 2010, 2009, and 2008 respectively (in thousands).

 

     Year Ended December 31,  
     2012     2011     2010     2009     2008  

Components of EBITDA:

          

Net income (loss)

   $ 37,017      $ (2,561   $ 36,416      $ 50,400      $ 115,802   

Interest, net:

          

Debt obligations

     57,869        59,649        55,183        21,024        8,331   

Interest income

     (2,167     (829     (528     (482     (1,525
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total interest, net

     55,702        58,820        54,655        20,542        6,806   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense (benefit)

     22,726        (802     21,502        30,155        64,379   

Depreciation

     60,482        60,960        58,509        69,461        33,498   

Amortization

     27,326        20,627        18,546        23,908        18,504   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

   $ 203,253      $ 137,044      $ 189,628      $ 194,466      $ 238,989   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table reconciles EBITDA to cash flows provided by operating activities for the years ended December 31, 2012, 2011, 2010, 2009, and 2008 respectively (in thousands).

 

    Year Ended December 31,  
    2012     2011     2010     2009     2008  

EBITDA Reconciliation to GAAP:

         

EBITDA

  $ 203,253      $ 137,044      $ 189,628      $ 194,466      $ 238,989   

Cash paid for deferred drydocking charges

    (44,223     (19,704     (22,510     (19,234     (19,773

Cash paid for interest

    (38,597     (43,811     (44,178     (24,201     (24,981

Cash paid for taxes

    (1,332     (1,272     (2,809     (15,520     (6,119

Changes in working capital

    7,899        (12,111     5,036        41,117        15,406   

Stock-based compensation expense

    10,891        6,525        8,710        8,704        10,815   

Loss on early extinguishment of debt

    6,048        —         —         —         —    

Changes in other, net

    1,501        (1,020     (2,145     (2,088     (7,505
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows provided by operating activities

  $ 145,440      $ 65,651      $ 131,732      $ 183,244      $ 206,832   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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, 2012, 2011, 2010, 2009, and 2008, respectively (in thousands).

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

 

     Year Ended December 31,  
     2012      2011      2010      2009      2008  

Loss on early extinguishment of debt

   $ 6,048         —           —           —           —     

Stock-based compensation expense

     10,891         6,525         8,710         8,704         10,815   

Interest income

     2,167         829         528         482         1,525   

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.

 

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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 GoM continues to be considered a world-class basin by exploration and production companies. As of May 2012, BOEM estimated that the GoM contains 48 billion barrels of recoverable oil equivalent. While the Deepwater Horizon incident negatively impacted our operations in the GoM during 2010 and 2011, we observed considerable improvement in market conditions during 2012 which were driven by 1) an increased amount of exploration and production activities; and 2) a reduced amount of OSVs in the GoM due to decisions by vessel owners to deploy vessels in other markets following the Deepwater Horizon incident. According to IHS-Petrodata as of January 31, 2013, the number of floating rigs available in the GoM region is currently 42, which has increased from the pre-Macondo level of 34, because the 12 floaters that either left the region or were removed from service, have since been replaced by 20 similar or more advanced rigs. Of the 42 rigs available in the GoM, 33 were actively drilling as of January 31, 2013. For the five pre-Macondo years of 2005 through 2009, the historical average level of floating rigs actively drilling was 29 rigs with a peak of 35 rigs. We expect at least one additional deepwater drilling unit to arrive in the GoM during 2013. During 2012, the rate of deepwater drilling permit approvals improved significantly over 2011, however, the pace of permitting was inconsistent. We believe that, while the pace of permit issuance will be uneven for some time to come, the overall number of permits issued in 2013 should not be less than 2012 levels.

Improvements in dayrates and utilization for our high-spec Upstream vessels continued through the fourth quarter of 2012. Leading-edge spot market OSV dayrates in the GoM for our 240 and 265 class DP-2 equipment are in the $38,000 to $42,000 range. Whether these rates can be sustained will depend, among other things, on the future rig-count and the pace of permitting in the GoM. Market conditions for high-spec DP-2 vessels may be impacted during 2013 by the anticipated delivery of 27 additional Jones Act-qualified DP-2 vessels from U.S. shipyards, including five being constructed by the Company. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs increased about $4,404, or

 

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roughly 29%, from $15,102 for 2011 to $19,506 for 2012. During the year ended December 31, 2012, we had an average stacked new generation OSV fleet of 2.7 vessels compared to 9.2 vessels for the same period in 2011. As of December 31, 2012, we had only one DP-1 new generation OSV stacked. We expect that our DP-1 vessels will experience continued softness as our deepwater customers are increasingly biased towards using only DP-2 vessels in deepwater operations. The Company is considering whether to convert additional DP-1 vessels to DP-2, as is the case with six such vessels being converted under our 200 class OSV retrofit program during 2013.

The recent recovery in the GoM could be adversely affected by an increasing shortage of, and competition for, qualified mariners. This shortage is being exacerbated by customer and regulatory driven requirements that increase the manning levels on many vessels, including drilling units that operate in the GoM. Mariner shortages have driven up labor costs, which comprise the greatest portion of our operating costs. To address intense competition for licensed mariners, we increased our Upstream crew wages in April 2012 by roughly $5.0 million per quarter. We expect these increased wage levels to continue into 2013 and beyond. We will also have incremental expenses due to the expansion of our fleet personnel and shoreside support staff in anticipation of the vessels that will be delivered under our fifth OSV newbuild program.

Brazil

Brazil is experiencing a dramatic increase in activity related to its large deepwater and pre-salt oilfield basins. This increase in activity is driven primarily by the state-owned oil company, Petroleo Brasileiro S.A., or Petrobras, and other producers, including BP p.l.c., Chevron Corporation, Exxon Mobil Corporation, OGX Petroleo e Gas Participacoes and Royal Dutch Shell plc. Petrobras has publicly announced plans to spend approximately $142 billion on exploration and production activities from 2012 through 2016 and has stated that its offshore supply vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Brazilian operators plan to add one new floating rig by the end of 2013. Since the beginning of 2010, we have increased our presence in Brazil from zero to a high of 14 vessels. During 2012, four of our OSVs operating in Brazil which had been operating under long-term charters were mobilized back to the GoM at the conclusion of those contracts. As of December 31, 2012, we had eight vessels working in Brazil under long-term contracts for Petrobras. Current high operating costs as well as regulatory complexity and bureaucratic inefficiency are impacting our ability to generate operating margins commensurate with those we have historically generated in the GoM. Moreover, Petrobras is the single largest consumer of our services in Brazil and, for 2012, the Company overall. As is typical with large state-owned national oil companies, contracts with Petrobras are onerous and contain multiple provisions that allow Petrobras to impose penalties and deduct payments for performance issues even if we disagree with the basis of those penalties or deductions. Petrobras has exercised these kinds of measures in our contract and we expect that we will continue to confront similar issues with Petrobras going forward. In addition to regulatory complexity and the inherent difficulties associated with the Petrobras contracting regime, there is an acute shortage of mariners in Brazil, which we are required by law to employ on our vessels. This shortage is a significant contributor to escalating costs in Brazil and could present a barrier to our near-term growth in that market. We declined the opportunity to renew, with Petrobras, four 240 class vessels whose charters expire during the summer of 2013. We see Petrobras making significant investments intended to stem the

 

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logistical bottlenecks that have hampered its ability to take full advantage of its offshore fleet. As those chokepoints get worked out over the next few years, we expect to bid on additional contracts in Brazil.

Mexico

The primary customer in the Mexican market is the state-owned oil company, PEMEX. Production from the Cantarell field, which according to the EIA is PEMEX’s largest offshore oilfield, has declined from approximately 2.14 million barrels per day to 500,000 barrels per day. In 2010, 54% of Mexico’s total crude oil production came from the Cantarell field and the Ku-Maloob-Zaap field, both of which are located in the Bay of Campeche. In its July 2011 Outlook, PEMEX highlighted that 60% of its prospective resources, or 29.5 billion barrels of oil equivalent, are in the deepwater Gulf of Mexico. However, in order to develop this resource, PEMEX will likely need to tap the expertise of non-Mexican international oil companies. Under Article 27 of the Mexican constitution, private persons or companies (other than the state-owned PEMEX) are not allowed to carry out exploration for petroleum, and solid, liquid, or gaseous hydrocarbons. As a result, while we believe that Mexico could develop into a large market for deepwater activity, we do not expect this to occur until the Mexican government has found a solution to their constitutional constraints. We believe that this situation may be improved by the election of President Peña Nieto in July 2012, who campaigned on constitutional reform to reinvigorate the Mexican oil industry. Currently, there are four floating rigs and 33 jack-up rigs drilling offshore Mexico. PEMEX has announced plans to add another floating rig and three more high-spec jack-up rigs during the remainder of 2013. We began working in Mexico in 2002 and currently have seven vessels working there under long-term contracts. We will continue to actively bid additional vessels into Mexico as tenders are issued by PEMEX.

Market conditions

As of January 31, 2013, we had 49% of our new generation OSV vessel-days contracted for the fiscal year ending December 31, 2013. Our forward OSV contract coverage for the fiscal year ending December 31, 2014 currently stands at 15%. Included within our new generation contract coverage are five vessels on long-term charters with the United States government in defense capacities. It is possible that these contracts could be impacted in the event that the scheduled sequestration of $85 billion in federal defense spending goes forward commencing March 1, 2013 or as a result of legislation implemented to avoid the sequester. Our MPSV contract coverage has also increased as a result of the improving market conditions in the GoM. On the strength of long-term contracts awarded to two of our MPSVs during 2011 and recent spot market activity, MPSV contract coverage for the fiscal years ending December 31, 2013 and 2014 is currently 77% and 31%, respectively.

A sustained market recovery will depend upon several factors outside of our control including 1) the ability of operators and drilling contractors to comply with the new regulatory requirements; 2) the pace at which regulators approve plans and permit applications required by operators to drill; 3) the content of additional as yet unpromulgated rules that are expected to be issued; 4) the outcome of pending litigation brought by environmental groups challenging recent exploration plans approved by the DOI and 5) general economic conditions.

 

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Our 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, 2012, our 50 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:

 

Operating Areas

  

Domestic

  

GoM

     29   

Other U.S. coastlines(1)

     5   
  

 

 

 
     34   
  

 

 

 

Foreign

  

Brazil

     8   

Mexico

     10   

Middle East

     2   
  

 

 

 
     20   
  

 

 

 

Total Active Upstream Vessels(2)

     54   
  

 

 

 

 

(1) Includes five vessels that are currently supporting the military.
(2) Excluded from this table is one of our new generation OSVs and one conventional OSV that were stacked as of December 31, 2012. This vessel is expected to remain inactive until there is sustainable demand for the vessel.

OSV Newbuild Program #5. As of January 31, 2013, our fifth OSV newbuild program consisted of vessel construction contracts with two domestic shipyards to build four 300 class OSVs, six 310 class OSVs, and ten 320 class OSVs. On February 7, 2013, we announced that our fifth OSV newbuild program was expanded to include two 310 class Jones Act-qualified MPSVs and either two additional HOSMAX OSVs or, in lieu of building those vessels, one or more additional Jones Act-qualified MPSVs. We are currently negotiating with shipyards regarding these new vessels and how these new vessels will impact our outstanding contractual options. Delivery of the vessels to be constructed under this program is expected to occur on various dates during 2013 through 2015. As a result of this expansion of our fifth OSV newbuild program, assuming the Company opts to build two additional OSVs in lieu of one or more Jones Act-qualified MPSVs, we expect to own and operate 56, 69 and 73 new generation OSVs as of December 31, 2013, 2014, and 2015, respectively. These aggregate vessel additions result in a projected average new generation OSV fleet complement of 52.2, 63.0, and 72.5 vessels for the fiscal years 2013, 2014, and 2015, respectively. With the addition of the two MPSVs, we expect to own and operate four, four and six MPSVs as of December 31, 2013, 2014 and 2015, respectively. These MPSV additions result in a projected average MPSV fleet complement of 4.0, 4.0 and 4.8 vessels for the fiscal years 2013, 2014 and 2015, respectively. Assuming we build two MPSVs and two new OSVs as a result of the latest newbuild program expansion, the aggregate cost of our fifth OSV newbuild program, excluding construction period interest, is expected to be approximately $1,160 million. For further information regarding our fifth OSV newbuild program, please refer to the Capital Expenditures and Related Commitments section.

Our Downstream Segment

As of December 31, 2012, our Downstream fleet was comprised of nine double-hulled tank barges and 14 ocean-going tugs, five of which are older, lower-horsepower tugs that are

 

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stacked. Although Downstream results have improved from the prior year, recent dayrate trends are below the Downstream dayrates that existed from 2006 to 2008. Driven by demand in the GoM resulting from the Eagle Ford shale trend, we outfitted three additional vessels with vapor-recovery systems during the second quarter of 2012 to allow them to work in the trans-Gulf crude oil trade. We feel as if these developments will have a positive impact on our Downstream vessels operating in the GoM during 2013. With the ongoing expansion of our Upstream fleet, we expect our Downstream segment to continue to represent a much smaller portion of our consolidated operating results compared to historical trends.

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 disproportionately 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

 

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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, 17 to 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. 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 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 presently review our vessels for impairment using the following asset groups: New Generation OSVs, MPSVs, Conventional OSVs, Active Downstream Vessels and Stacked Downstream Vessels (the latter being evaluated on an individual basis, not as a group). Management has concluded that these groupings are currently appropriate because our vessels are highly mobile and are consistent based on the operating and marketing characteristics desired by our customers. When analyzing asset groups for impairment, we consider both historical and projected operating cash flows, operating income, and EBITDA based on current operating environment and future conditions that we can reasonably anticipate, such as inflation or prospective wage costs. These projections are based on, but not limited to, job location, current market dayrates included in recent sales proposals, utilization and contract coverage; along with anticipated market drivers, such as drilling rig movements, results of offshore lease sales and discussions with our customers regarding their ongoing drilling plans. When evaluating stacked vessels that are not expected to return to service, we use recent vessel sales and/or independent third-party appraisers to determine our estimate of undiscounted future cash flow. The vessel appraisers used for these assets are the same ones that are used by our lenders when vessels are appraised in secured financing arrangements. We have executed financing transactions in the ordinary course of our business, such as our revolving credit facility requiring third-party appraisals for collateralized assets. Such appraisals are reviewed and considered in assessing whether an impairment exists.

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. 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 significant 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.

 

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We reviewed ASC 360 regarding triggering events and considered whether the temporary reduction in the level of drilling activity in the GoM in 2010 and 2011 related to the Deepwater Horizon incident and resulting drilling moratoria represented an indicator of impairment for any of our asset groups and concluded that it did not. For our Upstream vessels operating in the GoM, we anticipated that the reduced drilling activity in that market was temporary in nature, as evidenced by the return of market conditions to pre-Macondo levels in 2012. While the Company has historically operated its Upstream segment predominately in the GoM, we will continue to deploy vessels to international markets as conditions warrant. Our technologically advanced vessels are capable of working in and are effectively mobilized to different markets so neither the geographic location of vessels, nor reduced drilling activity in a particular exploration area is considered on its own as an impairment trigger. It is Management’s opinion that the fair values of all of our asset groups exceed their carrying values. In order for the fair values of any of our assets to be below their respective carrying values, current and projected effective dayrates would have to be significantly below the lowest levels experienced in our Company’s history. In addition, those market conditions would have to be sustained for the remaining economic useful lives of each vessel class, which is also unlikely.

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

 

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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 the relative age of receivable balances, 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, 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 and foreign tax credit 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 prior to their expiration. 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. 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.

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 portion of our revenues and operating profit. Excluded from the OSV information below is the results of operations for our MPSVs, conventional vessels, our shore-base facility, and vessel management services. The Company does not provide average or effective dayrates for its

 

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MPSVs. MPSV dayrates are impacted by highly variable customer-required cost-of-sales associated with ancillary equipment and services, such as ROVs and cranes, which are typically recovered through higher dayrates charged to the customer. Due to the fact that each of our MPSVs have a workload capacity and significantly higher income generating potential than each of the Company’s new generation OSVs, the utilization and dayrate levels of our MPSVs could have a very large impact on our results of operations. For this reason, our consolidated operating results, on a period-to-period basis, are disproportionately impacted by the level of dayrates and utilization achieved by our four MPSVs.

 

     Years Ended December 31,  
     2012     2011     2010  

Offshore Supply Vessels:

      

Average number of new generation OSVs(1)

     51.0        51.0        49.9   

Average number of active new generation OSVs(2)

     48.3        41.8        42.4   

Average new generation OSV fleet capacity (DWT)

     128,190        128,190        124,965   

Average new generation vessel capacity (DWT)

     2,514        2,514        2,507   

Average new generation OSV utilization rate(3)

     83.2     71.5     71.6

Effective new generation OSV utilization rate(4)

     87.8     87.2     84.3

Average new generation OSV dayrate(5)

   $ 23,445      $ 21,121      $ 21,561   

Effective dayrate(6)

   $ 19,506      $ 15,102      $ 15,438   

Double-hulled Tank Barges:

      

Average number of double-hulled tank barges(7)

     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)

     88.2     88.1     80.5

Average dayrate(8)

   $ 17,012      $ 17,557      $ 17,502   

Effective dayrate(6)

   $ 15,005      $ 15,468      $ 14,089   

 

(1) We owned 51 new generation OSVs as of December 31, 2012. Our average number of new generation OSVs for the years ended December 31, 2012, 2011, and 2010 reflect the deliveries of certain vessels under our fourth OSV newbuild program. During 2010, we placed in service four OSVs. Please refer to the New Generation OSVs table on page 5 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 sole 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 all but one of our stacked new generation OSVs as of December 31, 2012. That vessel is expected to remain inactive until there is substantial demand for the vessel. Active new generation OSVs represent vessels that are immediately available for service during each respective period.
(3) Utilization rates are average rates based on a 365-day year. Vessels are considered utilized when they are generating revenues.
(4) Effective utilization rate is based on a denominator comprised only of vessel-days available for service by the active fleet, which excludes the impact of stacked vessel days.
(5) Average dayrates represent average revenue per day, which includes charter hire, crewing services and net brokerage revenues, based on the number of days during the period that the OSVs generated revenue.
(6) Effective dayrate represents the average dayrate multiplied by the average utilization rate.
(7) Other operating data for tugs and tank barges reflects our active Downstream fleet of nine double-hulled barges and nine ocean-going tugs. We also own five older, lower-horsepower tugs, which we consider to be non-core assets and are marketed for sale. We previously owned a fleet of single-hulled tank barges; however, all of those vessels have been sold as they were also considered non-core assets.
(8) Average dayrates represent average revenue per day, including time charters, brokerage revenue, revenues generated on a per-barrel-transported basis, demurrage, shipdocking and fuel surcharge revenue, based on the number of days during the period that the tank barges generated revenue. For purposes of brokerage arrangements, this calculation excludes that portion of revenue that is equal to the cost paid by customers of in-chartering third-party equipment.

 

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YEAR ENDED DECEMBER 31, 2012 COMPARED TO YEAR ENDED DECEMBER 31, 2011

Summarized financial information concerning our reportable segments for the years ended December 31, 2012 and 2011, respectively, is shown below in the following table (in thousands, except percentage changes):

 

     Year Ended
December 31,
    Increase (Decrease)  
     2012     2011     $ Change     % Change  

Revenues:

        

Upstream

        

Domestic

   $ 301,430      $ 182,226      $ 119,204        65.4

Foreign

     161,879        148,610        13,269        8.9   
  

 

 

   

 

 

   

 

 

   

 

 

 
     463,309        330,836        132,473        40.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Downstream

        

Domestic

     39,182        42,866        (3,684     (8.6 )% 

Foreign(1)

     10,247        7,925        2,322        29.3   
  

 

 

   

 

 

   

 

 

   

 

 

 
     49,429        50,791        (1,362     (2.7
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 512,738      $ 381,627      $ 131,111        34.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

        

Upstream

   $ 226,462      $ 177,868      $ 48,594        27.3

Downstream

     28,936        33,333        (4,397     (13.2
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 255,398      $ 211,201      $ 44,197        20.9
  

 

 

   

 

 

   

 

 

   

 

 

 

Depreciation and amortization:

        

Upstream

   $ 73,675      $ 67,910      $ 5,765        8.5

Downstream

     14,133        13,677        456        3.3   
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 87,808      $ 81,587      $ 6,221        7.6
  

 

 

   

 

 

   

 

 

   

 

 

 

General and administrative expenses:

        

Upstream

   $ 44,785      $ 32,170      $ 12,615        39.2

Downstream

     3,714        3,193        521        16.3   
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 48,499      $ 35,363      $ 13,136        37.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Gain (Loss) on sale of assets:

        

Upstream

   $ (350   $ 980      $ (1,330     >(100.0 )% 

Downstream

     624        559        65        11.6   
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 274      $ 1,539      $ (1,265     (82.2 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income:

        

Upstream

   $ 118,037      $ 53,868      $ 64,169        >100.0

Downstream

     3,270        1,147        2,123        >100.0   
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 121,307      $ 55,015      $ 66,292        >100.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss on early extinguishment of debt

   $ 6,048      $ —        $ 6,048        >100.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest expense

   $ 57,869      $ 59,649      $ (1,780     (3.0 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest income

   $ 2,167      $ 829      $ 1,338        >100.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense (benefit)

   $ 22,726      $ (802   $ 23,528        >100.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 37,017      $ (2,561   $ 39,578        >100.0
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

 

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Revenues. Revenues for 2012 increased by $131.1 million, or 34.4%, to $512.7 million compared to $381.6 million for 2011 due to improved Upstream market conditions. Our weighted-average active operating fleet for 2012 was approximately 70 vessels compared to 64 vessels for 2011, entirely due to the reactivation of previously Upstream stacked vessels.

Revenues from our Upstream segment increased by $132.5 million, or 40.1%, to $463.3 million for 2012 compared to $330.8 million for 2011. These higher revenues primarily resulted from increased demand for our high-spec OSVs and MPSVs, and the reactivation of 14 new generation OSVs that were returned to service during 2011 and 2012. Revenue from our four-vessel MPSV fleet increased by $49.6 million, or 109% for 2012 compared to 2011. Our new generation OSV average dayrates were $23,445 for 2012 compared to $21,121 for 2011, an increase of $2,324, or 11.0%. Our new generation OSV utilization was 83.2% for 2012 compared to 71.5% for 2011. 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. The deepwater drilling moratoria in the GoM also contributed to the lower Upstream utilization in 2011. We had an average of 2.7 new generation OSVs stacked during 2012 compared to an average of 9.2 stacked vessels during the prior year. Domestic revenues for our Upstream segment increased by $119.2 million during 2012 due to increased drilling activity in the GoM. Foreign revenues for our Upstream segment increased by $13.3 million due to additional vessels deployed to Latin America since early 2011. Foreign revenues comprised 34.9% of our total Upstream revenues for 2012 compared to 44.9% for 2011.

Revenues from our Downstream segment decreased by $1.4 million, or 2.8%, to $49.4 million for 2012 compared to $50.8 million for 2011. This slight revenue decrease was primarily due to a shift in contract mix from COA arrangements to time charters. When operating under a time charter arrangement we typically earn lower dayrates that are generally offset by lower fuel expense. Our double-hulled tank barge average dayrates were $17,012 for 2012 compared to $17,557 for 2011, a decrease of $545 or 3.1%. Our double-hulled tank barge utilization was 88.2% for 2012 in-line with 88.1% for 2011.

Operating expenses. Operating expenses for 2012 increased by $44.2 million, or 20.9%, to $255.4 million. This increase was primarily associated with the increase of our active operating fleet compared to the year-ago period, higher operating costs for vessels operating in Latin America and higher crew wages.

Operating expenses for our Upstream segment were $226.5 million, an increase of $48.6 million, or 27.3%, for 2012 compared to $177.9 million for 2011. Operating expenses for our Upstream segment were driven higher by an increased number of vessels that had been re-activated since early 2011 and, to a lesser extent, higher costs for our vessels operating in Latin America and higher crew wages. Market-driven mariner wage increases that commenced in April 2012 drove our Upstream operating expenses higher by approximately $5 million per quarter for the last three quarters of 2012. Aggregate cash operating expenses for our Upstream segment are projected to be in the range of $253.0 million to $263.0 million for 2013. Our cash operating expense estimate is exclusive of any additional repositioning expenses we may incur that are not recoverable through charter hire in connection with the potential relocation of more of our vessels to or from international markets; or any customer-required cost-of-sales related to future contract fixtures that are typically recovered through higher dayrates.

 

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Operating expenses for our Downstream segment were $28.9 million, a decrease of $4.4 million, or 13.2%, for 2012 compared to $33.3 million for 2011. The decrease in operating expenses is largely the result of having lower fuel expense due to a greater mix of Downstream vessels operating under time charter agreements rather than COAs in 2012. Under time charter arrangements, the charterer bears the cost of fuel. Under COA arrangements, the vessel owner bears the cost of fuel, which is typically recovered through higher dayrates. Our contracts during 2011 were primarily comprised of COA voyages.

Depreciation and Amortization. Depreciation and amortization expense was $6.2 million higher for 2012 compared to 2011. This increase is primarily due to higher costs for vessel regulatory drydockings and incremental amortization expense related to the vessels that were previously stacked and required recertification prior to being re-activated. Depreciation and amortization expense is expected to increase from current levels when any newly constructed vessels are delivered or undergo their initial 30-month and 60-month recertifications.

General and Administrative Expenses. General and administrative expenses of $48.5 million, or 9.5% of revenues, increased by $13.1 million during 2012 compared to 2011. This increase in G&A expenses was primarily the result of higher shoreside incentive compensation, fleet recruiting and training expenses. Our general and administrative expenses are expected to increase to the approximate annual range of $53 million to $55 million for 2013, commensurate with our pending fleet growth and continuing 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 2012, we sold one older, lower-horsepower tug, and certain non-vessel shoreside assets for net cash proceeds of $4.3 million, which resulted in aggregate gains of approximately $0.3 million ($0.2 million after-tax or $0.01 per diluted share). During 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).

Operating Income. Operating income increased by $66.3 million to $121.3 million during 2012 compared to 2011 for the reasons discussed above. Operating income as a percentage of revenues for our Upstream segment was 25.5% for 2012 compared to 16.3% for 2011. Operating income as a percentage of revenues for our Downstream segment was 6.7% for 2012 compared to 2.2% for 2011.

Loss on Early Extinguishment of Debt. On March 2, 2012, we commenced a cash tender offer for all of the outstanding $300.0 million in aggregate principal amount of our 6.125% senior notes due 2014. Senior notes representing approximately $252.2 million, or 84% of such notes outstanding, were validly tendered during the designated tender period, which ended on March 29, 2012. The remaining $47.8 million of our 6.125% senior notes were redeemed on April 30, 2012. During 2012, we recorded an aggregate loss on early extinguishment of debt of approximately $6.0 million ($3.7 million or $0.11 per diluted share after-tax), which was comprised of the tender offer costs, the write-off of unamortized financing costs and original issue discount, and a bond redemption premium. We did not retire any debt during 2011.

Interest Expense. Interest expense decreased $1.8 million during 2012 compared to 2011. Higher capitalized interest attributable to vessels under construction was the primary reason that our interest expense decreased from 2011. During 2012, we capitalized interest of $11.0 million, or roughly 16% of our total interest costs compared to capitalized interest of

 

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$0.4 million, or roughly 1% of our total interest costs, for 2011. See “Liquidity and Capital Resources” for further discussion.

Interest Income. Interest income increased by $1.3 million to $2.2 million for 2012 compared to $0.8 million for 2011. Our average cash balance increased to $500.8 million for 2012 compared to $189.5 million for 2011. The average interest rate earned on our invested cash balances was approximately 0.4% during the fiscal years ended December 31, 2012 and December 31, 2011, respectively.

Income Tax Expense (Benefit). Our effective tax rate was 38.0% and (23.8)% for 2012 and 2011, respectively. The tax rate for 2012 is higher than the benefit rate used in 2011 due to the effect of items not deductible for federal tax purposes. The benefit rate for 2011 is lower than our historical rate due to the amplified effect of our permanent book-tax differences on the relatively smaller pre-tax book loss for 2011. 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 increased year-over-year by $39.6 million for reported net income of $37.0 million for 2012 compared to a net loss of $2.6 million for 2011. The improved net income for 2012 was primarily due to the increase in operating income based on improved market conditions discussed above and a $3.1 million pre-tax decrease in net interest expense. Net income for 2012 was adversely impacted by a $6.0 million pre-tax loss on early extinguishment of debt.

 

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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

 

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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. Revenue for our MPSV fleet declined by $41.0 million, or 47% 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 moratoria 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 U.S. 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 an increased number of 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

 

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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.

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 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 expense 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.

General and Administrative Expenses. 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 was primarily the result of lower shoreside incentive compensation.

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.

 

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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.

Liquidity and Capital Resources

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

We have reviewed all of our debt agreements as well as our liquidity position and projected future cash needs. Despite volatility in financial and commodity markets, we remain confident in our current financial position, the strength of our balance sheet and the short- and long-term viability of our business model. To date, our liquidity has not been materially impacted and we do not expect that it will be materially impacted in the near-future due to such volatility. We believe that our cash on-hand, projected operating cash flow and available borrowing capacity under our revolving credit facility will be more than sufficient to operate the Company and meet all of its near-term obligations, including milestone construction payments for both the contracted or approved vessels under our expanded fifth OSV newbuild program and our 200 class OSV retrofit program.

As of December 31, 2012, we had total cash and cash equivalents of $576.7 million. We also have a $300 million revolving credit facility, expandable up to $500 million, which is undrawn as of January 31, 2013. Excluding any cash requirements for potential new growth opportunities that may arise, our current cash on-hand and our internal cash flow projections indicate that our $300 million revolving credit facility should be sufficient to meet our liquidity needs for the foreseeable future. As of December 31, 2012, we had posted letters of credit for $0.9 million and had $299.1 million of credit available under our revolving credit facility. The full undrawn credit amount of such facility is available for all uses of proceeds, including working capital, if necessary. However, the intended uses of the facility are the acquisition of assets that generate additional EBITDA and the potential repayment of existing long-term debt, if necessary.

Although we expect to continue generating positive working capital through our operations, events beyond our control, such as renewed regulatory-driven delays in the issuance of drilling plans and permits in the GoM, declines in expenditures for exploration,

 

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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 at which time we expect to retire our 1.625% convertible notes in full with cash on-hand today. Our currently undrawn revolving credit facility matures in November 2016. 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 flows from operations or use our revolving credit facility to meet our obligations under our recently expanded fifth OSV newbuild program, our OSV retrofit program, and scheduled recertifications of vessels. We also 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 from operating activities or draw on our revolving credit facility 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 included 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 are using the net proceeds from the offering to partially fund our fifth OSV newbuild program. The aggregate cost of this expanded program, excluding construction period interest, is expected to be approximately $1,160.0 million, of which $498.8 million, $327.6 million and $59.0 million is expected to be incurred in 2013, 2014 and 2015, respectively. From the inception of our fifth OSV newbuild program through December 31, 2012, we have incurred $274.6 million, or 23.7%, 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.

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 $145.4 million in 2012, $65.7 million in 2011, and $131.7 million in 2010. Operating cash flows in 2012 were favorably affected by an increase in our weighted-average operating fleet and improved market conditions in both our Upstream and Downstream segments. Operating cash flows decreased in 2011 compared to 2010 due to a decrease in demand for our Upstream equipment, including our MPSVs, primarily due to regulatory-driven market weakness in the GoM. Cash flows from operations for 2012 reflect partial-period contributions from four new generation OSVs that were stacked during the prior year and were re-activated

 

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in 2012. Cash flows from operations for 2011 reflect full- and partial-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.

Investing Activities. Net cash used in investing activities was $259.8 million in 2012, $62.3 million in 2011, and $57.0 million in 2010. Cash utilized during 2012 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 $4.3 million in aggregate net cash proceeds from the sale of one older, lower-horsepower tug, and shoreside assets. 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.

Financing Activities. Net cash provided by financing activities was $334.3 million in 2012, $226.9 million in 2011, and $1.1 million in 2010. Net cash provided by financing activities for 2012 primarily resulted from the issuance of our 5.875% senior notes due 2020, or 2020 senior notes, and the issuance of our 1.500% convertible senior notes due 2019, or the 2019 convertible senior notes. 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.

On March 2, 2012, we commenced a tender offer and solicitation of consents relating to the repurchase of our existing 2014 senior notes. The tender offer expired on March 29, 2012. On March 2, 2012, we also completed the private placement of our 2020 senior notes, resulting in offering proceeds of approximately $367.4 million, net of estimated transaction costs. In connection with the tender offer and related consent solicitation, we used $259.9 million of such proceeds to repurchase approximately 84% of our outstanding $300 million aggregate principal amount of 2014 senior notes. The $47.8 million of remaining 2014 senior notes were redeemed on April 30, 2012. The remaining net proceeds will be used for general corporate purposes, which may include retirement of other debt or funding of the acquisition, construction or retrofit of vessels. As a result of the repurchase of the 2014 senior notes, we recorded a pre-tax loss on early extinguishment of debt of approximately $6.0 million ($3.7 million after-tax or $0.11 per diluted share).

On August 13, 2012, we completed the private placement of $300.0 million in aggregate principal amount of 2019 convertible senior notes, which generated net cash proceeds of $266.0 million. These 2019 convertible senior notes have a cash coupon of 1.500% and a conversion price of 37.5% higher than the closing stock price on August 7, 2012 of $39.16. In conjunction with this offering, we also entered into separate convertible senior note hedge

 

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transactions that increased the conversion price to $68.53. After funding the 2019 convertible senior note hedge transactions, the remaining proceeds, along with other available sources of cash, will be used to retire the outstanding 2026 convertible senior notes that are callable by the Company in November 2013.

Commitments and Contractual Obligations

The following table sets forth our aggregate contractual obligations as of December 31, 2012 (in thousands).

 

Contractual Obligations

   Total      Less than
1 Year
    

1-3 Years

    

3-5 Years

    

Thereafter

 

Vessel construction commitments(1)

   $ 885,425       $ 498,828       $ 386,597       $ —        $ —     

OSV retrofit program

     47,694         47,694         —          —          —     

8.000% senior notes(2)

     250,000         —          —          250,000         —     

1.625% convertible senior notes(3)

     250,000         250,000         —          —          —     

5.875% senior notes(4)

     375,000         —          —          —          375,000   

1.500% convertible senior notes(5)

     300,000         —          —          —          300,000   

Interest payments(6)

     327,211         52,319         99,938         79,938         95,016   

Operating leases(7)

     47,496         3,327         5,836         4,477         33,856   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 2,482,826       $ 852,168       $ 492,371       $ 334,415       $ 803,872   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Vessel construction commitments reflect contractual milestone payments for our fifth OSV newbuild program. The total project costs for the currently contracted or approved 24-vessel program are expected to be $1,160.0 million, excluding capitalized construction period interest. From the inception of this program through December 31, 2012, we have incurred $274.6 million, or 23.7%, of total expected project costs.
(2) Our 8.000% senior notes mature on September 1, 2017 and include $4,771 of original issue discount.
(3) 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 $11,093 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 we will call these notes on November 15, 2013.
(4) Our 5.875% senior notes mature on April 1, 2020.
(5) Our 1.500% convertible senior notes, with a fixed interest rate of 1.500% per year, mature on September 1, 2019 and currently include $69,699 of non-cash original issue discount. Holders of the convertible senior notes may require that such notes be repurchased at their option pursuant to certain types of corporate transactions described in Note 6 or 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 September 2019.
(6) Interest payments relate to our 8.000% senior notes due September 1, 2017, our 1.625% convertible senior notes due November 15, 2026, our 5.875% senior notes due April 1, 2020 and our 1.500% convertible senior notes due September 1, 2019 with semi-annual interest payments of $10.0 million payable March 1 and September 1, $2.0 million payable May 15 and November 15, $11.0 million payable April 1 and October 1, $4.0 million payable March 1, and $2.3 million payable September 1, respectively. The semi-annual interest payments for our 1.625% 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.
(7) Included in operating leases are commitments for 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, 2012, we had total debt of $1,089.4 million, net of original issue discount of $85.6 million. Our debt, net of original issue discount, is comprised of $245.2 million of our 8.000% senior notes due 2017, or 2017 senior notes, $238.9 million of our 1.625% convertible senior notes due 2026, or 2026 convertible senior notes, $375.0 million of our 2020 senior notes and $230.3 million of our 1.500% convertible senior notes due 2019, or 2019 convertible senior notes. 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

 

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face amount, of 2026 convertible senior notes bear interest at an annual coupon of 1.625% with semi-annual cash interest payments of $2.0 million due May 15 and November 15, declining to 1.375%, or $1.7 million semi-annually, beginning on November 15, 2013. The effective interest rate on such notes is 6.36%. The effective interest rate on the 2020 senior notes is 6.08% with semi-annual cash interest payments of $11.0 million due and payable each April 1 and October 1. The $300.0 million, in face amount, of 2019 convertible senior notes bear interest at an annual coupon of 1.500% with semi-annual cash interest payments of $2.3 million due March 1 and September 1, beginning on March 1, 2013. The effective interest rate on such notes is 6.23%. The senior notes do not require any payments of principal prior to their stated maturity dates, but pursuant to each indenture under which the 2017 senior notes and 2020 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, 2013. 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 2017 senior notes, our 2020 senior notes, our 2026 convertible senior notes, and our 2019 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 2017 senior notes and 2020 senior notes impose certain operating and financial restrictions on us. Such restrictions affect, and in many cases limit or prohibit, among other things, our ability to incur additional indebtedness, make capital expenditures, redeem equity, create liens, sell assets and make dividend or other restricted payments. For the quarter ended December 31, 2012, 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.

 

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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, 2012 and since each program’s inception, respectively, as well as the estimated total project costs for each of our current expansion programs (in millions):

 

    For the Year
Ended
December  31,
2012
    Incurred
Since
    Inception    
       Estimated   
Program
Totals(1)
        Projected    
Delivery
Dates(1)
 

Growth Capital Expenditures:

       

OSV Newbuild Program #5(2)

  $    232.2      $    274.6      $ 1,160.0        2Q2013-3Q2015   
 

 

 

   

 

 

   

 

 

   

 

(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 represent estimated cash outlays and do not include any allocation of capitalized construction period interest. Projected delivery dates correspond to the first and last vessels that are contracted with shipyards for construction and delivery under our currently active program, respectively.
(2) Our fifth OSV newbuild program consists of vessel construction contracts with two domestic shipyards to build four 300 class OSVs, six 310 class OSVs, and ten 320 class OSVs. In February 2013, we announced that our fifth OSV newbuild program was expanded to include two 310 class Jones Act-qualified MPSVs and either two HOSMAX OSVs or, in lieu of building those vessels, one or more additional Jones Act-qualified MPSVs. Delivery of the vessels to be constructed under this program is expected to occur on various dates during 2013 through 2015. We expect to own and operate 56, 69 and 73 new generation OSVs as of December 31, 2013, 2014, and 2015, respectively. These vessel additions result in a projected average new generation OSV fleet complement of 52.2, 63.0, and 72.5 vessels for the fiscal years 2013, 2014, and 2015, respectively. The Company expects to own and operate four, four and six MPSVs as of December 31, 2013, 2014 and 2015, respectively. These vessel additions result in a projected average MPSV fleet complement of 4.0, 4.0 and 4.8 vessels for the fiscal years 2013, 2014 and 2015, respectively.

The following table summarizes the costs incurred, prior to the allocation of construction period interest, for the purposes set forth below for the years ended December 31, 2012, 2011, and 2010, and a forecast for 2013 (in millions):

 

     Year Ended December 31,  
     2013      2012      2011      2010