Edgar Filing: GULFMARK OFFSHORE INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

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

Commission file number 001-33607

GulfMark Offshore, Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0526032
(State or other jurisdiction of		(I.R.S. Employer Identification No.)
incorporation or organization)

10111 Richmond Avenue, Suite 340		77042
Houston, Texas		77042
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 963-9522

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


Class A Common Stock, $0.01 Par Value		New York Stock Exchange
(Title of each class)		(Name of each exchange on which registered)

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 þ 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 þ

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 filings requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (§229.405 of this chapter) 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. ¨

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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2012, the last business day of the registrant’s most recently completed second fiscal quarter was $785,112,928, calculated by reference to the closing price of $33.11 for the registrant’s common stock on the New York Stock Exchange on that date.

Number of shares of Class A common stock outstanding as of February 25, 2013: 26,624,877

DOCUMENTS INCORPORATED BY REFERENCE

The information called for by Part III, Items 10, 11, 12, 13 and 14, will be included in a

definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after the end of

the fiscal year covered by this Form 10-K, and is incorporated herein by reference.

Exhibit Index Located on Page 79

TABLE OF CONTENTS


		Page
PART I
Items 1 and 2.	Business and Properties		3
	General Business		3
	Worldwide Fleet		4
	Operating Segments		10
	Other		13
Item 1A.	Risk Factors		17
Item 1B.	Unresolved Staff Comments		23
Item 3.	Legal Proceedings		23
Item 4.	Mine Safety Disclosures		24

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		24
Item 6.	Selected Consolidated Financial Data		26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		43
Item 8.	Financial Statements and Supplementary Data		45
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		76
Item 9A.	Controls and Procedures		76
Item 9B.	Other Information		78

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		78
Item 11.	Executive Compensation		78
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		78
Item 13.	Certain Relationships and Related Transactions, and Director Independence		78
Item 14.	Principal Accounting Fees and Services		78

PART IV
Item 15.	Exhibits, Financial Statement Schedules		79

PART I

ITEMS 1. and 2. Business and Properties

GENERAL BUSINESS

The Company

GulfMark Offshore, Inc., a Delaware corporation, was incorporated in 1996. On February 24, 2010, GulfMark Offshore, Inc., (“Old GulfMark”) merged with and into its wholly owned subsidiary, New GulfMark Offshore, Inc., a Delaware corporation (‘‘New GulfMark”), pursuant to an agreement and plan of reorganization, with New GulfMark as the surviving corporation (such transaction, the “Reorganization”). The Reorganization was adopted by the stockholders and New GulfMark changed its name from “New GulfMark Offshore, Inc.” to “GulfMark Offshore, Inc”. The business, operations, assets and liabilities of New GulfMark after the Reorganization are the same as business, operations, assets and liabilities of Old GulfMark immediately prior to the Reorganization. The Reorganization was effected primarily to better position us to benefit from and adhere to U.S. maritime laws and regulations.

We provide offshore marine services primarily to companies involved in the offshore exploration and production of oil and natural gas. Our vessels transport materials, supplies and personnel to offshore facilities, as well as move and position drilling structures. The majority of our operations are conducted in the North Sea, offshore Southeast Asia and offshore in the Americas. We also contract vessels into other regions to meet our customers’ requirements. We currently operate a fleet of 78 offshore supply vessels (“OSVs”) in the following regions: 33 vessels in the North Sea, 16 vessels offshore Southeast Asia, and 29 vessels offshore the Americas. Our fleet is one of the world’s youngest, largest and most geographically balanced, high specification OSV fleets. Our owned vessels have an average age of approximately ten years.

We have the following operating segments: the North Sea (“N. Sea”), Southeast Asia (“SEA”) and the Americas. Our chief operating decision maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate our performance. The business within each of these geographic regions has similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” For financial information about our operating segments and geographic areas, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Segment Results” included in Part II, Item 7, and Note 13 to our Consolidated Financial Statements included in Part II, Item 8.

Unless otherwise indicated, references to “we”, “us”, “our” and the “Company” refer to GulfMark Offshore, Inc., its subsidiaries and its predecessors.

Our principal executive offices are located at 10111 Richmond Avenue, Suite 340, Houston, Texas 77042, and our telephone number at that address is (713) 963-9522. We file annual, quarterly, and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). This annual report on Form 10-K for the year ended December 31, 2012 includes as exhibits all required Sarbanes-Oxley Act Section 302 certifications by our CEO and CFO regarding the quality of our public disclosure. In addition, our CEO certifies annually to the New York Stock Exchange (“NYSE”) that he is not aware of any violation by the Company of the NYSE corporation governance listing standards. Our SEC filings are available free of charge to the public over the internet on our website at http://www.gulfmark.com and at the SEC’s website at http://www.sec.gov. Filings are available on our website as soon as reasonably practicable after we electronically file or furnish them to the SEC. You may also read and copy any document we file at the SEC’s Public Reference Room at the following location: 100 F Street, NE, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Offshore Marine Services Industry Overview

Our customers employ our vessels to provide services supporting the construction, positioning and ongoing operation of offshore oil and natural gas drilling rigs and platforms and related infrastructure, and substantially all of our revenue is derived from providing these services. This industry employs various types of OSVs that are used to transport materials, supplies and personnel, and to move and position drilling structures. Offshore marine service providers are employed by oil and natural gas companies that are engaged in the offshore exploration and production of oil and natural gas and related services. Services provided by companies in this industry are performed in numerous locations worldwide. The North Sea, offshore Southeast Asia, offshore West Africa, offshore Middle East, offshore Brazil and the U.S. Gulf of Mexico are each major markets that employ a large number of vessels. Vessel usage is also significant in other international markets, including offshore India, offshore Australia and offshore Trinidad, the Persian Gulf, the Mediterranean Sea, offshore Russia and emerging East Africa. The industry is relatively fragmented with a combination of multi-national and regional competitors.

Our business is directly impacted by the level of activity in worldwide offshore oil and natural gas exploration, development and production, which in turn is influenced by trends in oil and natural gas prices. In addition, oil and natural gas prices are affected by a host of geopolitical and economic forces, including the fundamental principles of supply and demand. The characteristics and current marketing environment in each region are discussed later in greater detail. Each of the major geographic offshore oil and natural gas production regions has unique characteristics that influence the economics of exploration and production and, consequently, the market demand for vessels in support of these activities. While there is some vessel interchangeability between geographic regions, barriers such as mobilization costs, vessel suitability and cabotage restrict migration of some vessels between regions. This is most notable in the North Sea, where vessel design requirements dictated by the harsh operating environment restrict relocation of vessels into that market and in the U.S. Gulf of Mexico, where entry into the market is subject to the Jones Act restrictions. Conversely, these same design characteristics make North Sea capable vessels unsuitable for other areas where draft restrictions and, to a lesser degree, higher operating costs, restrict migration.

WORLDWIDE FLEET

In addition to the vessels we own, we manage a number of vessels for third-party owners, providing support services ranging from chartering assistance to full operational management. Although these managed vessels provide limited direct financial contribution, the added market presence can provide a competitive advantage for the manager. The following table summarizes the overall owned, managed and total fleet changes since December 31, 2011:


	Owned Vessels			Managed Vessels			Total Fleet
December 31, 2011		73			17			90

New-Build Program		—			—			—
Vessel Additions		2			0			2
Vessel Dispositions		(5	)		(4	)		(9	)

December 31, 2012		70			13			83

New-Build Program		—			—			—
Vessel Additions		—			—			—
Vessel Dispositions		—			(5	)		(5	)

February 25, 2013		70			8			78

Vessel Classifications

Offshore supply vessels generally fall into seven functional classifications derived from their primary or predominant operating characteristics or capabilities. However, these classifications are not rigid, and it is not unusual for a vessel to fit into more than one of the categories. These functional classifications are:

•

Anchor Handling, Towing and Support Vessels (“AHTSs”) are used to set anchors for drilling rigs and to tow mobile drilling rigs and equipment from one location to another. In addition, these vessels typically can be used in supply roles when they are not performing anchor handling and towing services. They are characterized by shorter after decks and special equipment such as towing winches. Vessels of this type with less than 10,000 brake horsepower, or BHP, are referred to as small AHTSs (“SmAHTSs”) while AHTSs in excess of 10,000 BHP are referred to as large AHTSs (“LgAHTSs”). The most powerful North Sea class AHTSs have upwards of 25,000 BHP. All of our AHTSs can also function as PSVs.

•

Platform Supply Vessels (“PSVs”) serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other offshore supply vessels by their cargo handling capabilities, particularly their large capacity and versatility. PSVs utilize space on deck and below deck and are used to transport supplies such as fuel, water, drilling fluids, equipment and provisions. PSVs range in size from 150 to 200 feet. Large PSVs (“LgPSVs”) typically range up to 300 feet in length, with a few vessels somewhat larger, and are particularly suited for supporting large concentrations of offshore production locations because of their large, clear after deck and below deck capacities. The majority of the LgPSVs we operate function primarily in this classification but are also capable of servicing construction support.

•

Fast Supply or Crew Vessels (“FSVs/Crewboat”) transport personnel and cargo to and from production platforms and rigs. Older crewboats (early 1980s build) are typically 100 to 120 feet in length, and are designed for speed and to transport personnel. Newer crewboat designs are generally larger, 130 to 185 feet in length, and can be longer with greater cargo carrying capacities. Vessels in the larger category are also called fast supply vessels. They are used primarily to transport cargo on a time-sensitive basis.

•

Specialty Vessels (“SpVs”) generally have special features to meet the requirements of specific jobs. The special features can include large deck spaces, high electrical generating capacities, slow controlled speed and varied propulsion thruster configurations, extra berthing facilities and long-range capabilities. These vessels are primarily used to support floating production storing and offloading (FPSOs); diving operations; remotely operated vehicles (“ROVs”); survey operations and seismic data gathering; as well as oil recovery, oil spill response and well stimulation. Some of our owned vessels frequently provide specialty functions.

•

Standby Rescue Vessels (“Stby”) perform a safety patrol function for an area and are required for all manned locations in the North Sea and in some other locations where oil and natural gas exploitation occurs. These vessels typically remain on station to provide a safety backup to offshore rigs and production facilities and carry special equipment to rescue personnel. They are equipped to provide first aid, shelter and, in some cases, function as support vessels.

•

Construction Support Vessels are vessels such as pipe-laying barges, diving support vessels or specially designed vessels, such as pipe carriers, used to transport the large cargos of material and supplies required to support the construction and installation of offshore platforms and pipelines. A large number of our LgPSVs also function as pipe carriers.

•

Utility Vessels are typically 90 to 150 feet in length and are used to provide limited crew transportation, some transportation of oilfield support equipment and, in some locations, standby functions.

The following table summarizes our owned vessel fleet by classification and by region as February 25, 2013:


Owned Vessels by Classification
	AHTS		PSV		FSV/Crewboat
Region	AHTS	SmAHTS	LgPSV	PSV	FSV	Crew	SpV	Total
North Sea	3	—	21	—	—	—	1	25
Southeast Asia	9	3	3	1	—	—	—	16
Americas	2	—	18	5	3	0	1	29

	14	3	42	6	3	0	2	70

Vessel Construction / Acquisitions / Divestitures

In the third quarter of 2011, our Board of Directors approved the initiation of a new-build construction program. We began the program in the North Sea region where we contracted with three shipyards to build a total of six PSVs. The estimated total cost of these initial six vessels is $228.0 million. In late 2011, we exercised an option with one of the shipyards to build an additional vessel at an estimated cost of $60.0 million. The first of these vessels is scheduled to be delivered in the second quarter of 2013 and the last is scheduled to be delivered in the first quarter of 2014.

In June 2012, we signed an agreement with a U.S. shipyard to build two U.S. flagged PSVs for the U.S. Gulf of Mexico at an estimated total cost of $72.0 million. We expect deliveries of these two vessels in the third and fourth quarters of 2013. In July 2012, we signed agreements with another U.S. shipyard to build an additional two U.S. flagged PSVs at an estimated total cost of $96.0 million. We expect delivery of these vessels in the third quarter of 2014 and the first quarter of 2015.

During the third quarter of 2012, we placed $52.4 million in escrow related to the two Thoma-Sea new-builds (U.S. flagged PSVs) described in the table below. Progress payments will be drawn from escrow as they become due. The amount held in escrow, $47.0 million at December 31, 2012, is segregated from cash and cash equivalents and is presented in long-term assets on the December 31, 2012 balance sheet.

We did not take delivery of any new-build vessels in 2012. In the first quarter of 2012, we purchased a vessel for operation in the Americas region for a total price of $22.5 million. In the fourth quarter of 2012, we purchased a vessel for operation in the North Sea region for a total price of $28.6 million.

During 2012, we sold four crew boats and one fast supply vessel previously operating in our Americas region for an aggregate price of $40.6 million. Prior to December 31, 2012, we had one vessel that was held for sale and not included in our active fleet numbers. In January 2013, we sold this vessel for a sale price of $0.7 million. As of February 25, 2013, we did not have any vessels classified as held for sale.

The following tables illustrate the details of the vessels under construction, the vessels acquired and vessels disposed of:


Vessels Under Construction as of December 31, 2012
Construction Yard	Region		Type⁽¹⁾		Expected Delivery	Length (feet)	BHP⁽²⁾	DWT⁽³⁾	Expected Cost
									(millions)
Remontowa		N. Sea		LgPSV	Q2 2013	292	9,574	5,100	$37.0
Remontowa		N. Sea		LgPSV	Q3 2013	292	9,574	5,100	37.0
Remontowa		N. Sea		LgPSV	Q3 2013	261	9,574	4,000	34.0
Rosetti Marino		N. Sea		LgPSV	Q4 2013	246	8,457	3,000	31.0
Rosetti Marino		N. Sea		LgPSV	Q1 2014	246	8,457	3,000	31.0
Simek		N. Sea		LgPSV	Q2 2013	304	11,935	4,700	58.0
Simek		N. Sea		LgPSV	Q4 2013	304	11,935	4,700	60.0
Thoma-Sea		Americas		LgPSV	Q3 2013	271	9,990	3,600	36.0
Thoma-Sea		Americas		LgPSV	Q4 2013	271	9,990	3,600	36.0
BAE Systems		Americas		LgPSV	Q3 2014	288	10,960	5,300	48.0
BAE Systems		Americas		LgPSV	Q1 2015	288	10,960	5,300	48.0

Note: Final cost may differ due to foreign currency fluctuations

Vessels Acquired Since December 31, 2011
Vessel	Region		Type⁽¹⁾		Year Built	Length (feet)	BHP⁽²⁾	DWT⁽³⁾	Month Aquired
Thomas Wainwright		Americas		LgPSV	2010	242	5,472	2,700	Jan-12
F.D. Invincible		North Sea		LgPSV	2006	236	5,450	3,200	Nov-12

Vessels Disposed of Since December 31, 2011
Vessel	Region		Type⁽¹⁾		Year Built	Length (feet)	BHP⁽²⁾	DWT⁽³⁾	Month Disposed
Bluefin		Americas		Crew	2008	165	7,200	337	Jan-12
Sailfish		Americas		Crew	2007	176	7,200	307	May-12
Swordfish		Americas		Crew	2009	176	7,200	307	May-12
Albacore		Americas		Crew	2008	165	7,200	337	Jul-12
Blacktip		Americas		FSV	2009	181	7,200	543	Aug-12
Clwyd Supporter		North Sea		SpV	1984	266	10,700	1,350	Jan-13

⁽¹⁾

LgPSV - Large Platform Supply Vessel

PSV

- Platform Supply Vessel

FSV

- Fast Vessel Supply

SpV

- Specialty Vessel

Crew

- Crewboat

⁽²⁾

BHP - Brake Horsepower

⁽³⁾

DWT - Deadweight Tons

Maintenance of Our Vessels and Drydocking Obligations

In addition to repairs, we are required to make expenditures for the certification and maintenance of our vessels, and those expenditures typically increase with age. The demands of the market, the expiration of existing contracts, the start of new contracts, and customer preferences influence the timing of drydocks. Our drydocking expenditures for 2012 totaled $33.3 million. We anticipate approximately $25.5 million in drydocking expenditures in 2013. We had 35 drydocks in 2012 and anticipate 27 drydocks in 2013.

Vessel Listing

Currently, we operate a fleet of 78 vessels. Of these vessels, 70 are owned by us (see table below, which excludes the 8 vessels we manage for other owners).


Owned Vessel Fleet
Vessel	Region	Type (a)	Year Built	Length (feet)	BHP (b)		DWT (c)		Flag
Highland Bugler	N. Sea	LgPSV	2002	221		5,450		3,115	UK
Highland Champion	N. Sea	LgPSV	1979	265		4,800		3,910	UK
Highland Citadel	N. Sea	LgPSV	2003	236		5,450		3,200	UK
Highland Eagle	N. Sea	LgPSV	2003	236		5,450		3,200	UK
Highland Fortress	N. Sea	LgPSV	2001	236		5,450		3,200	Malta
Highland Monarch	N. Sea	LgPSV	2003	221		5,450		3,115	UK
Highland Navigator	N. Sea	LgPSV	2002	275		9,600		4,250	Malta
Highland Prestige	N. Sea	LgPSV	2007	284		10,767		4,993	UK
Highland Pride	N. Sea	LgPSV	1992	265		6,600		3,080	UK
Highland Rover(d)	N. Sea	LgPSV	1998	236		5,450		3,200	Malta
Highland Star	N. Sea	LgPSV	1991	265		6,600		3,075	UK
North Challenger	N. Sea	LgPSV	1997	221		5,450		3,115	Norway
North Mariner	N. Sea	LgPSV	2002	275		9,600		4,400	Norway
North Promise	N. Sea	LgPSV	2007	284		10,767		4,993	Norway
North Stream	N. Sea	LgPSV	1998	276		9,600		4,585	Norway
North Truck	N. Sea	LgPSV	1983	265		6,120		3,370	Norway
North Vanguard	N. Sea	LgPSV	1990	265		6,600		4,000	Norway
North Purpose	N. Sea	LgPSV	2010	284		10,738		4,850	Norway
Highland Trader	N. Sea	LgPSV	1996	221		5,450		3,115	UK
Highland Courage	N. Sea	AHTS	2002	260		16,320		2,750	UK
Highland Valour	N. Sea	AHTS	2003	260		16,320		2,750	UK
Highland Endurance	N. Sea	AHTS	2003	260		16,320		2,750	UK
Highland Prince	N. Sea	LgPSV	2009	284		10,738		4,850	UK
Highland Spirit	N. Sea	SpV	1998	202		6,000		1,800	UK
F.D. Invincible	N. Sea	LgPSV	2006	236		5,450		3,200	UK

Highland Guide	SEA	LgPSV	1999	218		4,640		2,800	Panama
Highland Legend	SEA	PSV	1986	194		3,600		1,442	Panama
Highland Drummer	SEA	LgPSV	1997	221		5,450		3,115	Panama
Highland Piper	SEA	LgPSV	1996	221		5,450		2,700	Panama
Sea Apache	SEA	AHTS	2008	250		10,700		2,700	Panama
Sea Cheyenne	SEA	AHTS	2007	250		10,700		2,700	Panama
Sea Guardian	SEA	SmAHTS	2006	191		5,150		1,500	Panama
Sea Intrepid	SEA	SmAHTS	2005	191		5,150		1,500	Panama
Sea Sovereign	SEA	SmAHTS	2006	230		5,500		1,800	Panama
Sea Supporter	SEA	AHTS	2007	225		7,954		2,360	Panama
Sea Choctaw	SEA	AHTS	2008	250		10,700		2,700	Panama
Sea Kiowa	SEA	AHTS	2008	250		10,700		2,700	Panama
Sea Cherokee	SEA	AHTS	2009	250		10,700		2,700	Panama
Sea Comanche	SEA	AHTS	2009	250		10,700		2,700	Panama
Sea Valiant	SEA	AHTS	2010	213		10,188		2,301	Panama
Sea Victor	SEA	AHTS	2010	213		10,188		2,301	Panama

Austral Abrolhos(e)	Americas	SpV	2004	215		7,100		2,000	Brazil
Highland Scout	Americas	LgPSV	1999	218		4,640		2,800	Panama
Highland Warrior	Americas	LgPSV	1981	265		5,300		2,450	Panama
Coloso	Americas	AHTS	2005	199		5,916		1,674	Mexico
Titan	Americas	AHTS	2005	199		5,916		1,674	Mexico


Owned Vessel Fleet
Vessel	Region	Type (a)	Year Built	Length (feet)	BHP (b)		DWT (c)		Flag
Orleans	Americas	LgPSV	2004	210		6,342		2,586	USA
Bourbon	Americas	LgPSV	2004	210		6,342		2,586	USA
Royal	Americas	LgPSV	2004	210		6,342		2,586	USA
Chartres	Americas	LgPSV	2004	210		6,342		2,586	USA
Iberville	Americas	LgPSV	2004	210		6,342		2,586	USA
Bienville	Americas	LgPSV	2005	210		6,342		2,586	USA
Conti	Americas	LgPSV	2005	210		6,342		2,586	USA
St. Louis	Americas	LgPSV	2005	210		6,342		2,586	USA
Toulouse	Americas	LgPSV	2005	210		6,342		2,586	USA
Esplanade	Americas	LgPSV	2005	210		6,342		2,586	USA
First and Ten	Americas	PSV	2007	190		3,894		1,860	USA
Double Eagle	Americas	PSV	2007	190		3,894		1,860	USA
Triple Play	Americas	PSV	2007	190		3,894		1,860	USA
Grand Slam	Americas	LgPSV	2007	225		3,894		2,371	USA
Slam Dunk	Americas	LgPSV	2008	225		3,894		2,371	USA
Touchdown	Americas	PSV	2008	190		3,894		1,860	USA
Hat Trick	Americas	PSV	2008	190		3,894		1,860	USA
Jermaine Gibson	Americas	LgPSV	2008	225		3,894		2,371	USA
Homerun	Americas	LgPSV	2008	225		3,894		2,371	USA
Knockout	Americas	LgPSV	2008	225		3,894		2,371	USA
Hammerhead	Americas	FSV	2008	181		7,200		543	USA
Mako	Americas	FSV	2008	181		7,200		543	USA
Tiger	Americas	FSV	2009	181		7,200		543	USA
Thomas Wainwright	Americas	LgPSV	2010	242		5,472		2,700	USA

The table above does not include the managed vessels.

(a)	Legend: LgPSV - Large platform supply vessel

PSV - Platform supply vessel

AHTS - Anchor handling, towing and supply vessel

SmAHTS - Small anchor handling, towing and supply vessel

SpV - Specialty vessel, including towing and oil spill response

FSV - Fast Supply Vessel

(b)	Brake horsepower.

(c)	Deadweight tons.

(d)

The Highland Rover is subject to a purchase option on the part of the charterer, pursuant to terms of an amendment to the original charter which was executed in late 2007 and amended in 2008. The charterer may purchase the vessel based on a stipulated formula on each of April 1, 2015 and October 1, 2016 provided 120 days notice has been given by the charterer.

(e)

The Austral Abrolhos is subject to an annual right of its charterer to purchase the vessel during the term of the charter, which commenced May 2, 2003 and, subject to the charterer’s right to extend, terminates April 29, 2016, at a purchase price in the first year of approximately $26.8 million declining to an adjusted purchase price of approximately $12.9 million in the thirteenth year.

OPERATING SEGMENTS

The North Sea Operating Segment


	Owned Vessels		Managed Vessels			Total Fleet
December 31, 2011		24		16			40

New-Build Program		—		—			—
Vessel Additions		1		—			1
Vessel Dispositions		—		(4	)		(4	)
Regional Transfers		—		—			—

December 31, 2012		25		12			37

New-Build Program		—		—			—
Vessel Additions		—		—			—
Vessel Dispositions		—		(4	)		(4	)

February 25, 2013		25		8			33

Market and Segment Overview

We define the North Sea market as offshore Norway, Great Britain, the Netherlands, Denmark, Germany, Ireland, the Faeroes Islands and Greenland. Historically, this has been the most demanding of all exploration frontiers due to harsh weather, erratic sea conditions, significant water depth and some long sailing distances. Exploration and production operators in the North Sea market have typically been large and well-capitalized entities (such as major and state-owned oil and natural gas companies) in large part because of the significant financial commitment required. However, in recent years, a number of independent operators have established operations in the region, thus diversifying the customer base. Projects in the North Sea tend to be fewer in number but larger in scope, with longer planning horizons than projects in regions with less demanding environments. Due to these factors, vessel demand in the North Sea has historically been more stable and less susceptible to abrupt swings than vessel demand in other regions.

The North Sea market can be broadly divided into three service segments: exploration support; production platform support; and field development and construction (which includes subsea services). The exploration support services market represents the primary demand for AHTSs and has historically been the most volatile segment of the North Sea market. While PSVs support the exploration segment, they also support the production platform and field development and construction segments, which generally are not affected as much by the volatility in demand for the AHTSs. Our North Sea-based fleet is oriented toward supply vessels that work in the more stable segments of the market: production platform support and field development and construction.

Unless deployed to one of our operating segments under long-term contract, vessels based in the North Sea but operating temporarily out of the region are included in our North Sea operating segment statistics, and all vessels based out of the region are supported through our onshore bases in Aberdeen, Scotland and Sandnes, Norway. The region typically has weaker periods of demand for vessels in the winter months of December through February primarily due to lower construction activity and harsh weather conditions affecting the movement of drilling rigs.

Market Development

Vessel demand in the North Sea is directly related to drilling and development activities in the region, construction work required in support of these activities, as well as demands outside of the region that draw vessels to other international markets. Geopolitical events, the demand for oil and natural gas in both mature and emerging countries and a host of other factors will influence the expenditures of both independent and major oil and gas companies.

Exploration and development spending in the North Sea region increased in 2012 and is expected to continue to rise in 2013, increasing offshore drilling and subsea construction activity and demand for vessel services in this region.

The Southeast Asia Operating Segment


	Owned Vessels		Managed Vessels			Total Fleet
December 31, 2011		14		1			15

New-Build Program		—		—			—
Vessel Additions		—		—			—
Vessel Dispositions		—		—			—
Regional Transfers		2		—			2

December 31, 2012		16		1			17

New-Build Program		—		—			—
Vessel Additions		—		—			—
Vessel Dispositions		—		(1	)		(1	)

February 25, 2013		16		0			16

Market and Segment Overview

The Southeast Asia market is defined as offshore Asia bounded roughly on the west by the Indian subcontinent and on the north by China, then south to Australia and east to the Pacific Islands. This market includes offshore Brunei, Cambodia, Indonesia, Malaysia, Myanmar, the Philippines, Singapore, Thailand, Australia, New Zealand, Bangladesh, Timor-Leste, Papua New Guinea and Vietnam. Traditionally, the design requirements for vessels in this market were generally similar to the requirements of the shallow water U.S. Gulf of Mexico. However, advanced exploration technology and rapid growth in energy demand among many Pacific Rim countries have led to more remote drilling locations, which has increased both the overall demand and the technical requirements for vessels. All vessels based out of the region are supported through our primary onshore bases in Singapore and Malaysia.

Southeast Asia’s competitive environment is broadly characterized by a large number of small companies, in contrast to many of the other major offshore exploration and production areas of the world, where a few large operators dominate the market. Affiliations with local companies are generally necessary to maintain a viable marketing presence. Our management has been involved in the region since for many years and we currently maintain long-standing business relationships with a number of local companies.

Market Development

Vessels in this market are often smaller than those operating in areas such as the North Sea. However, the varying weather conditions, annual monsoons, severe typhoons and long distances between supply centers in Southeast Asia have allowed for a variety of vessel designs to compete, each suited for a particular set of operating parameters. Vessels designed for the U.S. Gulf of Mexico and other areas, where moderate weather conditions prevail, have historically made up the bulk of the vessels in the Southeast Asia market. Demand for larger, newer and higher specification vessels has developed in the region where deepwater projects occur or where oil and natural gas companies employ larger fleets of vessels. During the last five years, we have sold 11 of our older vessels serving Southeast Asia and have taken delivery of 12 new-builds significantly decreasing the age of our fleet and increasing our capabilities. During 2012, we added two vessels to the Southeast Asia fleet that were transferred from our Americas region.

Changes in supply and demand dynamics have led, at times, to an excess number of vessels in other geographic markets. It is possible that vessels currently located in the Arabian/Persian Gulf area, Africa or the U.S. Gulf of Mexico could relocate to the Southeast Asia market; however, not all vessels currently located in those regions would be able to operate in Southeast Asia and oil and natural gas operators in this region are continuing to demand newer, higher specification vessels. Overall, Southeast Asia is a dynamic market and from time to time certain types of vessels may be subject to more intense competition.

The Americas Operating Segment


	Owned Vessels			Managed Vessels		Total Fleet
December 31, 2011		35			0		35

New-Build Program		—			—		—
Vessel Additions		1			—		1
Vessel Dispositions		(5	)		—		(5	)
Regional Transfers		(2	)		—		(2	)

December 31, 2012		29			0		29

New-Build Program		—			—		—
Vessel Additions		—			—		—
Vessel Dispositions		—			—		—

February 25, 2013		29			0		29

Market and Segment Overview

We define the Americas market as offshore North, Central and South America, specifically including the United States, Mexico, Trinidad and Brazil. All vessels based in the Americas are supported from our onshore bases in Louisiana, Trinidad, Brazil, and Mexico.

U.S. Gulf of Mexico

Drilling in the U.S. Gulf of Mexico can be divided into two sectors: the shallow waters of the continental shelf and the deepwater areas. Deepwater drilling is generally considered to be in water depths in excess of 1,000 feet. The continental shelf has been explored since the late 1940s and the existing infrastructure and knowledge of this sector allows for incremental drilling costs to be on the lower end of the range of worldwide offshore drilling costs. A resurgence of deepwater drilling began in the 1990s as advances in technology made this type of drilling economically feasible. Deepwater drilling is on the higher end of the cost range, and the substantial costs and long lead times required in this type of drilling make it less susceptible to short-term fluctuations in the price of crude oil and natural gas. Most of our vessels operate in the deepwater areas of the U.S. Gulf of Mexico where we have a significant position.

In April 2010, a catastrophic fire and explosion sank a deepwater drilling rig and precipitated a major oil spill in the U.S. Gulf of Mexico (the “Macondo Incident”). Immediately thereafter, a drilling moratorium effectively shut down drilling in the U.S. Gulf of Mexico. As a result of the Macondo Incident and subsequent drilling moratorium, we transferred nine vessels in total to Brazil, Mexico and Trinidad to work on long term contracts. Although the cleanup was largely completed in August 2010 and the moratorium was officially lifted in October 2010, drilling activity began to recover slowly through early 2012. It has steadily improved since then as the pace of drilling permit approvals has continued to improve compared to 2011 and 2010. We believe we are now in the early stages of a period of growth in offshore activity in the U.S. Gulf of Mexico. This increased drilling activity has allowed us to mobilize four of the vessels sent to other Americas region locations back to the U.S. Gulf of Mexico, where they are currently on contract.

In general, the U.S. Gulf of Mexico remains a protected market. United States law requires that all vessels engaged in Coastwise Trade in the U.S. (which includes vessels servicing rigs and platforms in U.S. waters within the Exclusive Economic Zone), must be owned and managed by U.S. citizens, and be built in and registered under the laws of the United States. “Coastwise Trade”, as defined under the U.S. maritime and vessel documentation laws commonly referred to as the Jones Act, allows only those vessels that are owned and managed by U.S. citizens (as determined by those laws) and built in and registered under the laws of the United States to transport merchandise and passengers for hire between points in U.S. territorial waters.

Brazil

The Brazilian government presently permits private investment in the petroleum business and the early bid rounds for certain offshore concessions resulted in extensive commitments by major international oil companies and consortia of independents, many of whom have explored and are likely to continue to explore the offshore blocks awarded in the lease sales. This has created a demand for deepwater AHTSs and PSVs in support of the drilling and exploration activities that has been met primarily from mobilization of vessels from other regions. Petrobras, the Brazilian national oil company, as well as several international independents, continue to

expand operations and announce discoveries. This expansion has created additional demand for offshore supply vessels in the area and in 2010, we transferred four vessels from the U.S. Gulf of Mexico to work in Brazil under long term contracts. Recent political developments in Brazil have increased regulatory uncertainty, resulting in increased costs and regulatory challenges. As a result, in 2012, we mobilized two vessels out of Brazil to Southeast Asia as they completed their contracts. Looking forward, however, we expect continued growth in Brazil and we will continue to evaluate future work in the area while being selective in bidding OSV opportunities as they develop.

We currently operate seven vessels in Brazil, including a Brazilian built and flagged vessel. We have four PSVs, two LgPSVs and one SpV operating in the area under contracts of varying lengths.

Mexico

Since 2005, we have operated two AHTSs offshore Mexico on long-term contracts with Pemex, Mexico’s national oil company. In addition, during the past three years, we have moved various vessels into and out of the area from the U.S. Gulf of Mexico on long term contracts with Pemex. Mexico is potentially a large market for expanded deepwater activity, provided the government can develop a methodology for operations with non-Mexican international oil companies that works within its constitutional constraints. We will continue to actively bid into the area when opportunities arise.

Trinidad

In Trinidad, we have two LgPSVs and one FSV on term charters. During 2010, after the Macondo Incident and continuing into 2011, we mobilized four vessels into the area from the U.S. Gulf of Mexico as described above. During 2012, we mobilized several vessels whose contracts had expired back to the U.S. Gulf of Mexico. Given recent licensing and exploration activity in nearby locations, including Suriname and Guyana, we anticipate OSVs operating from a Trinidad base for the foreseeable future.

OTHER

Seasonality

Operations in the North Sea are generally at their highest levels from April through August and at their lowest levels from December through February primarily due to lower construction activity and harsh weather conditions affecting the movement of drilling rigs and deliveries to offshore platforms. Vessels operating offshore Southeast Asia are generally at their lowest utilization rates during the monsoon season, which moves across the Asian continent between September and early March. The monsoon season for a specific Southeast Asian location is generally about two months. Activity in the U.S. Gulf of Mexico is often lower during the North Atlantic hurricane season of June through November because fewer drilling rigs meet the enhanced regulatory requirements for operating in the U.S. Gulf of Mexico that are in effect during the period. Operations in any market may, however, be affected by seasonality often related to unusually long or short construction seasons due to, among other things, abnormal weather conditions, as well as market demand associated with increased drilling and development activities.

Fleet Availability

A portion of our available fleet is committed under contracts of various terms. The following table outlines the percentage of our forward days under contract and revenue backlog as of February 25, 2013 and February 22, 2012:


	As of February 25, 2013						As of February 22, 2012
	2013			2014			2012			2013
	Vessel Days			Vessel Days			Vessel Days			Vessel Days
North Sea		57.3	%		35.9	%		68.0	%		53.1	%
Southeast Asia		33.0	%		14.6	%		41.3	%		14.7	%
Americas		48.1	%		23.8	%		32.3	%		15.0	%

Overall Fleet		48.2	%		26.7	%		44.0	%		24.7	%

Revenue backlog (in thousands)	$	480,714					$	463,000

International vessel contracts are typically longer in duration and are generally only cancelable for non-performance. Domestic vessel contracts are typically shorter in duration and generally provide for other cancellation provisions, including termination for convenience.

Other Markets

From time to time, we have contracted our vessels outside of our operating segment regions principally on short-term charters in offshore Africa and the Mediterranean region. We look to our core markets for the bulk of our term contracts; however, when the economics of a contract are attractive, or we believe it is strategically advantageous, we will operate our vessels in markets outside of our core regions. The operations of vessels in those markets are generally managed through our offices in the North Sea region.

Customers, Contract Terms and Competition

Our principal customers are major integrated oil and natural gas companies, large independent oil and natural gas exploration and production companies working in international markets, and foreign government-owned or controlled oil and natural gas companies. Additionally, our customers also include companies that provide logistic, construction and other services to such oil and natural gas companies and foreign government organizations. Generally, our contracts are industry standard time charters for periods ranging from a few days or months up to ten years. Contract terms vary and often are similar within geographic regions with certain contracts containing cancellation provisions and others containing non-cancellable provisions except for unsatisfactory performance by the vessel. For the year ended December 31, 2012, we had revenue from Anadarko Petroleum Corporation in our Americas region and Chevron Corporation primarily in our Americas region, totaling $44.4 million and $42.0 million, respectively, that each accounted for 10% or more of our total consolidated revenue. For the year ended December 31, 2011, we had revenue from Petrobras Brasileiro S.A. in our Americas region, totaling $57.0 million, which exceeded 10% of our total consolidated revenue. No single customer accounted for 10 percent or more of our total consolidated revenue for 2010.

Contract or charter durations vary from single-day to multi-year in length, based upon many different factors that vary by market. Additionally, there are “evergreen” charters (also known as “life of field” or “forever” charters), and at the other end of the spectrum, there are “spot” charters and “short duration” charters, which can vary from a single voyage to charters of less than six months. Longer duration charters are more common where equipment is not as readily available or specific equipment is required. In the North Sea region, multi-year charters have been more common and constitute a significant portion of that market. Term charters in the Southeast Asia region have historically been less common than in the North Sea and generally less than two years in length. Recently, however, consistent with the change in the demand in the region, Southeast Asia contract periods are extending out further in time. In addition, charters for vessels in support of floating production are typically “life of field” or “full production horizon charters”. In the Americas, particularly in the U.S. Gulf of Mexico, charters vary in length from short term to multi-year periods, many with thirty day cancellation clauses. In Brazil, Mexico and Trinidad contracts are generally multi-year term contracts with limited cancellation provisions. We also have other contracts containing non-cancelable provisions except for unsatisfactory vessel performance. As a result of options and frequent renewals, the stated duration of charters may have little correlation with the length of time the vessel is actually contracted to a particular customer.

Bareboat charters are contracts for vessels, generally for a term in excess of one year, where the owner transfers all market exposure for the vessel to the charterer in exchange for an arranged fee. The charterer has the right to market the vessel without direction from the owner. Currently, we have no third party bareboat chartered vessels in our fleet.

Managed vessels add to the market presence of the manager but provide limited direct financial contribution. Management fees are typically based on a per diem rate and are not subject to fluctuations in the charter hire rates. The manager is typically responsible for disbursement of funds for operating the vessel on behalf of the owner. Currently, we have 8 vessels under management.

Substantially all of our charters are fixed in British Pounds, or GBP; Norwegian Kroner, or NOK; Euros; U.S. Dollars, Brazilian Reais, or BRL; or Singapore Dollars, or SGD. We attempt to reduce currency risk by matching each vessel’s contract revenue to the currency in which its operating expenses are incurred.

We compete with approximately a dozen competitors in the North Sea market and numerous small and large competitors in the Southeast Asia and Americas markets, some of which have significantly greater financial resources than we do. We compete principally on the basis of suitability of equipment, price and service. In the Americas region, we benefit from the provisions of the Jones Act which limits vessels that can operate in the U.S. Gulf of Mexico to those with U.S. ownership. Also, in certain foreign countries, preferences given to vessels owned by local companies may be mandated by local law or by national oil companies. We have attempted to mitigate some of the impact of such preferences through affiliations with local companies.

Government and Environmental Regulation

We must comply with extensive government regulation in the form of international conventions, federal, state and local laws and regulations in jurisdictions where our vessels operate and/or are registered. These conventions, laws and regulations govern matters of environmental protection, worker health and safety, vessel and port security, and the manning, construction, ownership and operation of vessels. Our operations are subject to extensive governmental regulation by the United States Coast Guard, the National Transportation Safety Board and the United States Custom and Border Protection (CBP), and their foreign equivalents, and to regulation by private industry organizations such as the American Bureau of Shipping and Det Norske Veritas. 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 CBP is authorized to inspect vessels at will. We believe that we are in substantial compliance with all applicable laws and regulations.

Maritime Regulations

We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of the United States 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 the vessels in our fleet 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, we would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our vessels.

Under the Jones Act, the privilege of transporting merchandise or passengers for hire in Coastwise Trade in U.S. territorial waters is restricted to only those Jones Act qualified vessels that are owned and managed by U.S. citizens and are built in and registered under the laws of the United States. A corporation is not considered a U.S. citizen unless:

•

the corporation is organized under the laws of the U.S. or of a state, territory or possession thereof,

•

the chief executive officer, by whatever title, and the chairman of the board of directors are U.S. citizens,

•

directors representing not more than a minority of the number of directors of such corporation necessary to constitute a quorum for the transaction of business are non-U.S. citizens, and

•

at least a majority or, in the case of an endorsement for operating in Coastwise Trade, 75 percent of the ownership and voting power of the shares of the capital stock is owned by, voted by and controlled by U.S. citizens, free from any trust or fiduciary obligations in favor of, or any contract or understanding under which voting power or control may be exercised directly or indirectly on behalf of non-U.S. citizens.

We are currently a U.S. citizen under these requirements, eligible to engage in Coastwise Trade. If we fail to comply with these U.S. citizen requirements, however, we would likely no longer be considered a U.S. citizen under the applicable laws. Such an event could result in our ineligibility to engage in Coastwise Trade, the imposition of substantial penalties against us, including seizure and forfeiture of our vessels, and the inability to register our vessels in the United States, each of which could have a material adverse effect on our financial condition and results of operations.

Environmental 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. As some environmental laws impose strict liability for remediation of spills and releases of oil and hazardous substances, we could be subject to liability even if we were not negligent or at fault. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others, including charterers.

Failure to comply with applicable environmental 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. Environmental laws and regulations may change in ways that substantially increase costs, or impose additional requirements or restrictions which could adversely affect our financial condition and results of operations. We believe that we are in substantial compliance with currently applicable environmental laws and regulations.

The International Maritime Organization, or IMO, has made the regulations of the International Safety Management Code, or ISM Code, mandatory. The ISM Code provides an international standard for the safe management and operation of ships, pollution prevention and certain crew and vessel certifications. IMO has also adopted the International Ship & Port Facility Security Code, or ISPS Code. The ISPS Code provides that owners or operators of certain vessels and facilities must provide security and security plans for their vessels and facilities and obtain appropriate certification of compliance. We believe all of our vessels presently are certificated in accordance with ISPS Code. The risks of incurring substantial compliance costs, liabilities and penalties for non-compliance are inherent in offshore marine operations.

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. 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 vessels routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. We maintain response plans as required by the Clean Water Act to address potential oil and fuel spills from either our vessels or our shore-base facilities.

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 all response costs, as well as natural resource damages and thus we could be held liable for releases of hazardous substances that resulted from operations by third parties not under our control or for releases associated with practices performed by us or others that were standard in the industry at the time.

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

Insurance

We review our insurance coverages annually. In particular, we assess our coverage levels and limits for possible marine liabilities, including pollution, personal injury or death, and property damage. Our most recent review did not result in any substantial adjustments to our coverages or limits.

Litigation

We are not a party to any material pending regulatory litigation or other proceeding and we are unaware of any threatened litigation or proceeding, which, if adversely determined, would have a material adverse effect on our financial condition or results of operations.

Employees

We have approximately 1,850 employees located principally in the United States, the United Kingdom, Norway, Southeast Asia, and Brazil. Through our contract with a crewing agency, we participate in the negotiation of collective bargaining agreements for approximately 950 contract crew members, approximately 51% of our labor force, who are members of two North Sea unions, under evergreen employment agreements. Wages are renegotiated annually in the second half of each year for the North Sea unions. We have no other collective bargaining agreements; however, we do employ crew members who are members of national unions but we do not participate in the negotiation of those collective bargaining agreements. Relations with our employees are considered satisfactory. To date, our operations have not been interrupted by strikes or work stoppages.

Properties

Our principal executive offices are leased and located in Houston, Texas. We lease offices and, in most cases, warehouse facilities for our local operations. Offices for our Southeast Asia operating segment are located in Singapore; Thailand; and Kemaman and Terengganu, Malaysia. Offices for our North Sea operating segment are located in Aberdeen, Scotland and Sandnes, Norway. Offices for our Americas operating segment are located in Macae, Brazil; Paraiso, Mexico; Trinidad; and St. Rose and Youngsville, Louisiana. Our operations generally do not require highly specialized facilities, and suitable facilities are generally available on a lease basis as required.

ITEM 1A.

Risk Factors

We rely on the oil and natural gas industry, and volatile oil and natural gas prices impact demand for our services.

Demand for our services depends on activity in offshore oil and natural gas exploration, development and production. The level of exploration, development and production activity is affected by factors such as:

•

prevailing oil and natural gas prices;

•

expectations about future prices and price volatility;

•

cost of exploring for, producing and delivering oil and natural gas;

•

sale and expiration dates of available offshore leases;

•

demand for petroleum products;

•

current availability of oil and natural gas resources;

•

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

•

local and international political, environmental and economic conditions;

•

technological advances; and

•

ability of oil and natural gas companies to obtain leases, permits, or obtain funds for capital.

The level of offshore exploration, development and production activity has historically been characterized by volatility. A decline in exploration and development of offshore areas may result in a decline in the demand for our offshore marine services. Any such decrease in activity is likely to reduce our day rates and our utilization rates and, therefore, could have a material adverse effect on our financial condition and results of operations.

An increase in the supply of offshore supply vessels would likely have a negative effect on charter rates for our vessels, which could reduce our earnings.

Charter rates for marine supply vessels depend in part on the supply of the vessels. We could experience a reduction in demand as a result of an increased supply of vessels. Excess vessel capacity in the industry or a particular offshore market may result from:

•

constructing new vessels;

•

moving vessels from one offshore market area to another;

•

converting vessels formerly dedicated to services other than offshore marine services; or

•

declining offshore oil and gas drilling production activities.

In the last ten years, construction of vessels of the types we operate has increased. The addition of new capacity of various types to the worldwide offshore marine fleet or declining offshore oil and gas drilling and production activities are likely to increase competition in those markets where we presently operate which, in turn, could reduce day rates, utilization rates and operating margins, which would adversely affect our financial condition and results of operations.

Government regulation and environmental risks can reduce our business opportunities, increase our costs, and adversely affect the manner or feasibility of doing business.

We and our customers are subject to extensive governmental regulation in the form of international conventions, federal, state and local laws and laws and regulations in jurisdictions where our vessels operate and are registered. The risks of incurring substantial compliance costs, liabilities and penalties for noncompliance are inherent in offshore marine services operations. Compliance with Jones Act, as well as with environmental, health, safety and vessel and port security laws can reduce our business opportunities and increase our costs of doing business. Additionally, these laws change frequently. Therefore, we are unable to predict with certainty the future costs or other future impact of these laws on our operations and our customers. We could also incur substantial costs, including cleanup costs, fines, civil or criminal sanctions and third party claims for property damage or personal injury as a result of violations of, or liabilities under, environmental laws and regulations. In addition, there can be no assurance that we can avoid significant costs, liabilities and penalties imposed on us as a result of government regulation in the future.

Failure to comply with the Foreign Corrupt Practices Act and similar worldwide anti-bribery laws may have an adverse effect on us.

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. In order to effectively operate in certain foreign jurisdictions, circumstances may require that we establish joint ventures with local operators or find strategic partners. As a U.S. corporation, we are subject to the regulations imposed by the Foreign Corrupt Practices Act (FCPA), which generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business or obtaining an improper business benefit. We have an ongoing program of proactive procedures to promote compliance with the FCPA and other similar anti-bribery and anti-corruption laws, but we may be held liable for actions taken by our strategic or local partners or agents even though these partners or agents may not themselves be subjected to the FCPA or other similar laws. Any determination that we have violated the FCPA or other similar laws could have a material adverse effect on our business, results of operations, and cash flows.

We are subject to hazards customary for the operation of vessels that could adversely affect our financial performance if we are not adequately insured or indemnified.

Our operations are subject to various operating hazards and risks, including:

•

catastrophic marine disaster;

•

adverse sea and weather conditions;

•

mechanical failure;

•

navigation errors;

•

collision;

•

oil and hazardous substance spills, containment and clean up;

•

labor shortages and strikes;

•

damage to and loss of drilling rigs and production facilities; and

•

war, sabotage, piracy and terrorism risks.

These risks present a threat to the safety of our personnel and to our vessels, cargo, equipment under tow and other property, as well as the environment. We could be required to suspend our operations or request that others suspend their operations as a result of these hazards. In such event, we would experience loss of revenue and possibly property damage, and additionally, third parties may have significant claims against us for damages due to personal injury, death, property damage, pollution and loss of business.

We maintain insurance coverage against substantially all of the casualty and liability risks listed above, subject to deductibles and certain exclusions. We have renewed our primary insurance program for the insurance year 2013-2014. We can provide no assurance, however, that our insurance coverage will be available beyond the renewal periods, or that it will be adequate to cover future claims that may arise.

We have a substantial amount of indebtedness. We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

We have a substantial amount of indebtedness which could:

•

increase our vulnerability to general adverse economic and industry conditions;

•

limit our ability to fund future working capital, capital expenditures, research and development costs and other general corporate financing needs;

•

require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, dividend payments, stock repurchases, capital expenditures, research and development efforts and other general corporate purposes;

•

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

place us at a competitive disadvantage compared to our competitors that have less debt; and

•

limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds or dispose of assets.

We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. If our capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, discontinue dividend payments and/or stock repurchase plans, or sell assets, seek additional capital or restructure or refinance our indebtedness. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Our facilities agreements and the indenture governing our Senior Notes restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

Changes in market conditions may impact any stock repurchases.

To the extent we engage in stock repurchases, such activity is subject to market conditions, such as the trading prices for our stock, as well as the terms of any stock purchase plans intended to comply with Rule 10b5-1 or Rule 10b-18 of the Exchange Act. Management, in its discretion, may engage in or discontinue stock repurchases at any time.

A substantial portion of our revenue is derived from our international operations and those operations are subject to foreign government regulation and operating risks.

We derive a substantial portion of our revenue from foreign sources. We therefore face risks inherent in conducting business internationally, such as:

•

foreign currency exchange fluctuations;

•

legal and government regulatory requirements;

•

difficulties and costs of staffing and managing international operations;

•

language and cultural differences;

•

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;

•

changes to shipping tax regimes;

•

imposition of currency exchange controls; and

•

potentially adverse tax consequences.

We cannot predict whether any such conditions or events might develop in the future or whether they might have a material effect on our operations. Also, our subsidiary structure and our operations are in part based on certain assumptions about various foreign and domestic tax laws, currency exchange requirements and capital repatriation laws. While we believe our assumptions are correct, there can be no assurance that taxing or other authorities will reach the same conclusions. If our assumptions are incorrect or if the relevant countries change or modify such laws or the current interpretation of such laws, we may suffer adverse tax and financial consequences, including the reduction of cash flow available to meet required debt service and other obligations.

Our tax expense and effective tax rate on our worldwide earnings could be higher should there be changes in tax legislation in countries where we operate, should we lose our tonnage tax qualifications or tax exemptions, should we increase our operations in high tax jurisdictions where we operate, and/or should we elect to repatriate cash from our foreign operations in amounts higher than recent years.

Our worldwide operations are conducted through our various domestic and foreign subsidiaries and as a result we are subject to income taxes in the United States and foreign jurisdictions. Any material changes in tax law and related regulations, tax treaties or their interpretations where we have significant operations could result in a higher effective tax rate on our worldwide earnings and a materially higher tax expense.

For example, our North Sea operations based in the U.K. and Norway have special tax incentives for qualified shipping operations, commonly referred to as tonnage tax, which provides for a tax based on the net tonnage capacity of qualified vessels, resulting in significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions. In June 2010 Norway’s Minister of Finance published revised rules related to previously enacted legislation for the taxation of pre-2007 tonnage tax profits. The revised Norwegian rules significantly reduced our tax liability on our untaxed shipping profits as of December 31, 2006. There is no guarantee that current tonnage tax regimes will not be changed or modified which could, along with any of the above mentioned factors, materially adversely affect our international operations and, consequently, our business, operating results and financial condition.

Our U.K. and Norway tonnage tax companies are subject to specific disqualification triggers, which, if we fail to manage them, could jeopardize our qualified tonnage tax status in those countries. Certain of the disqualification events or actions are coupled with one or more opportunities to cure or otherwise maintain the tonnage tax qualification but not all are curable. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017, but there is no guarantee that extensions will be granted.

In addition, our reported tax expense reflects our intention to permanently reinvest a significant portion of the current earnings from our foreign operations and therefore those earnings are not subject to U.S. taxation. In the future, we may elect to decrease the portion of annual foreign earnings we intend to permanently reinvest, and, if so, this would increase our overall effective tax rate upwards towards the U.S. federal statutory rate, which is currently 35%. Although we have neither the need nor the inclination to change our current intention, if we should change our intention with regard to our prior years accumulated unremitted foreign earnings, we would recognize a charge to current earnings to reflect the effect of U.S. taxation on those prior years’ unremitted foreign earnings and that charge could be significant and material.

Our income tax expense, or benefit, and effective tax rate are impacted by inclusion of related U.S. earnings, or losses, taxed at the combined U.S. federal and state tax rates. Additionally, our tax returns are subject to examination and review by the tax authorities in the jurisdictions in which we operate.

Our international operations and new vessel construction programs are vulnerable to currency exchange rate fluctuations and exchange rate risks.

We are exposed to foreign currency exchange rate fluctuations and exchange rate risks as a result of our foreign operations and when we construct vessels abroad. To minimize the financial impact of these risks, we attempt to match the currency of our debt and operating costs with the currency of the revenue streams. We occasionally enter into forward foreign exchange contracts to hedge specific exposures, which include exposures related to firm contractual commitments in the form of future vessel payments, but we do not speculate in foreign currencies. Because we conduct a large portion of our operations in foreign currencies, any increase in the value of the U.S. Dollar in relation to the value of applicable foreign currencies could potentially adversely affect our operating revenue or construction costs when translated into U.S. Dollars.

Vessel construction and repair projects are subject to risks, including delays, cost overruns, and ship yard insolvencies which could have an adverse impact on our results of operations.

Our vessel construction and repair projects are subject to risks, including delay and cost overruns, inherent in any large construction project, including:

•

shortages of equipment;

•

unforeseen engineering problems;

•

work stoppages;

•

lack of shipyard availability;

•

weather interference;

•

unanticipated cost increases;

•

shortages of materials or skilled labor; and

•

insolvency of the ship repairer or ship builder.

Significant cost overruns or delays in connection with our vessel construction and repair projects could adversely affect our financial condition and results of operations. Significant delays could also result, under certain circumstances, in penalties under, or the termination of, long-term contracts under which our vessels operate. The demand for vessels we construct may diminish from anticipated levels, or we may experience difficulty in acquiring new vessels or obtaining equipment to fix our older vessels due to high demand, both circumstances which may have a material adverse effect on our revenues and profitability. Recent global economic issues may increase the risk of insolvency of ship builders and ship repairers, which could adversely affect the cost of new construction and the vessel repairs and could result, under certain circumstances, in penalties under, or termination of, long-term contracts relating to vessels under construction.

Maintaining our current fleet size and configuration and acquiring vessels required for additional future growth require significant capital.

Expenditures required for the repair, certification and maintenance of a vessel typically increase with vessel age. These expenditures may increase to a level at which they are not economically justifiable and, therefore, to maintain our current fleet size we may seek to construct or acquire additional vessels. Also, customers may prefer modern vessels over older vessels, especially in weaker markets. The cost of adding a new vessel to our fleet ranges from under $10 million to $100 million and potentially higher.

While we expect our cash on hand, cash flow from operations and available borrowings under our credit facilities to be adequate to fund our existing commitments, including our new-build vessel construction program, our ability to pay these amounts is dependent upon the success of our operations. To date, we have been able to obtain adequate financing to fund all of our commitments. See “Long Term Debt” and “Liquidity and Capital Resources” in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) included in Part II, Item 7. We can give no assurance that we will have sufficient capital resources to build or acquire the vessels required to expand or to maintain our current fleet size and vessel configuration.

Our industry is highly competitive, which could depress vessel prices and utilization and adversely affect our financial performance.

We operate in a competitive industry. The principal competitive factors in the marine support and transportation services industry include:

•

price, service and reputation of vessel operations and crews;

•

national flag preference;

•

operating conditions;

•

suitability of vessel types;

•

vessel availability;

•

technical capabilities of equipment and personnel;

•

safety and efficiency;

•

complexity of maintaining logistical support; and

•

cost of moving equipment from one market to another.

In addition, an expansion in the supply of vessels in the regions in which we compete, whether through new vessel construction, the refurbishment of older vessels, or the conversion of vessels, could lower charter rates, which could adversely affect our business, financial condition and results of operations. Many of our competitors have substantially greater resources than we have. Competitive bidding and downward pressures on profits and pricing margins could adversely affect our business, financial condition and results of operations.

The operations of our fleet may be subject to seasonal factors.

Operations in the North Sea are generally at their highest levels during the months from April through August and at their lowest levels from December through February primarily due to lower construction activity and harsh weather conditions affecting the movement of drilling rigs. Vessels operating offshore Southeast Asia are generally at their lowest utilization rates during the monsoon season, which moves across the Asian continent between September and early March. The monsoon season for a specific Southeast Asian location is generally about two months. Activity in the U.S. Gulf of Mexico, like the North Sea, is often slower during the winter months when construction projects and other specialized jobs are most difficult, and during the hurricane season from June through November, although following a hurricane, activity may increase as there may be a greater demand for vessel services as repair and remediation activities take place. Operations in any market may be affected by seasonality often related to unusually long or short construction seasons due to, among other things, abnormal weather conditions, as well as market demand associated with increased drilling and development activities.

We are subject to war, sabotage, piracy, cyber attacks and terrorism risk.

War, sabotage, pirate, cyber and terrorist attacks or any similar risk may affect our operations in unpredictable ways, including changes in the insurance markets, disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, refineries, electric generation, transmission and distribution facilities, offshore rigs and vessels, and communications infrastructures, could be direct targets of, or indirect casualties of, a cyber attack or an act of piracy or terror. War or risk of war may also have an adverse effect on the economy. Insurance coverage can be difficult to obtain in areas of pirate and terrorist attacks resulting in increased costs that could continue to increase. We continually evaluate the need to maintain this insurance coverage as it applies to our fleet. Instability in the financial markets as a result of war, sabotage, piracy, cyber attacks or terrorism could also affect our ability to raise capital and could also adversely affect the oil, natural gas and power industries and restrict their future growth.

Our U.S. flagged vessels may be requisitioned or purchased by the United States in case of national emergency or a threat to security.

We are 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 our vessels were purchased or requisitioned by the federal government, 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, but we would not be entitled to be compensated for any consequential damages we suffer. 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.

The Maritime Restrictions established to comply with the Jones Act may have an adverse effect on us and our stockholders.

As a result of the Reorganization, our Class A common stock is now subject to certain transfer and ownership restrictions designed to protect our eligibility to engage in Coastwise Trade, including restrictions that limit the maximum permitted percentage of

outstanding shares of Class A common stock that may be owned or controlled in the aggregate by non-U.S. citizens to a maximum of 22 percent (collectively, the “Maritime Restrictions”). These Maritime Restrictions:

•

may cause the market price of our Class A common stock to be lower than the market price of our competitors who may not impose similar restrictions;

•

may result in transfers to non-U.S. citizens being void and ineffective and, thus, may impede or limit the ability of our stockholders to transfer or purchase shares of our Class A common stock;

•

provide for the automatic transfer of shares in excess of the maximum permitted percentage (“Excess Shares”) to a trust for sale and may result in non-U.S. citizens suffering losses from the sale of Excess Shares;

•

permit us to redeem Excess Shares, which may result in stockholders who are non-U.S. citizens being required to sell their Excess Shares of Class A common stock at an undesirable time or price or on unfavorable terms;

•

may adversely affect our financial condition if we must redeem Excess Shares or if we do not have the funds or ability to redeem the Excess Shares; and

•

may impede or discourage efforts by a third party to acquire the Company, even if doing so would benefit our stockholders.

Our business could be adversely effected if we do not comply with the Jones Act.

We are subject to the Jones Act, which requires that vessels carrying passengers or cargo between U.S. ports in Coastwise Trade be owned and managed by U.S. citizens, and be built in and registered under the laws of the United States. Violations of the Jones Act would result in our becoming ineligible to engage in Coastwise Trade, the imposition of substantial penalties against us, including seizure or forfeiture of our vessels, and/or the inability to register our vessels in the United States, each of which could have a material adverse effect on our financial condition and results of operations. Currently, we believe we meet the requirements to engage in Coastwise Trade, and the Maritime Restrictions imposed as part of the Reorganization were designed to assist us in complying with these requirements, but there can be no assurance that we will be in compliance with the Jones Act in the future.

Circumvention or repeal of the Jones Act may have an adverse impact on us.

The Jones Act’s provisions restricting Coastwise Trade to vessels controlled by U.S. citizens may from time to time be circumvented by foreign interests that seek to engage in trade reserved for vessels controlled by U.S. citizens and otherwise qualifying for Coastwise Trade. Legal challenges against such actions are difficult, costly to pursue and are of uncertain outcome. There have also been attempts to repeal or amend the Jones Act, and these attempts are expected to continue. In addition, the Secretary of Homeland Security may suspend the citizenship requirements of the Jones Act in the interest of national defense. To the extent foreign competition is permitted from vessels built in lower-cost shipyards and crewed by non-U.S. citizens with favorable tax regimes and with lower wages and benefits, such competition could have a material adverse effect on domestic companies in the offshore service vessel industry subject to the Jones Act such as us.

We depend on key personnel, and our U.S. Citizen requirements may limit our ability to recruit and retain qualified directors and executive officers.

We depend to a significant extent upon the efforts and abilities of our executive officers and other key management personnel. There is no assurance that these individuals will continue in such capacity for any particular period of time. The loss of the services of one or more of our executive officers or key management personnel could adversely affect our operations.

As long as shares of our Class A common stock remain outstanding, our chairman of the board and chief executive officer, by whatever title, must be U.S. citizens. In addition, our certificate of incorporation and bylaws specify that not more than a minority of directors comprising the minimum number of members of the Board of Directors necessary to constitute a quorum of the Board of Directors (or such other portion as the Board of Directors determines is necessary to comply with applicable law) may be non-U.S. citizens so long as shares of our Class A common stock remain outstanding. Our bylaws provide for similar citizenship requirements with regard to committees of the Board of Directors. As a result, we may be unable to allow a non-U.S. citizen, who would otherwise be qualified, to serve as a director or as our chairman of the board or chief executive officer.

The volatility in oil and gas prices and disruptions in the credit markets and general economy may adversely impact our business.

As a result of volatility in oil and natural gas prices and ongoing uncertainty of the global economic environment, we are unable to determine whether customers will reduce spending on exploration and development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. The current global economic environment may impact industry fundamentals and impact our customers’ abilities to pay for the services of our vessels. The potential resulting decrease in demand for offshore services could cause the industry to cycle into a prolonged downturn. These conditions could have a material adverse effect on our business, financial condition and results of operations.

Climate change, climate change regulations and greenhouse gas effects may adversely impact our operations and markets.

There is a concern that emissions of greenhouse gases (“GHG”) alter the composition of the global atmosphere in ways that affect the global climate. Climate change, including the impact of global warming, may create physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions. Given the maritime nature of our business, we do not believe that physical climate change is likely to have a material adverse effect on us.

Financial risks relating to climate change are likely to arise from increasing legislation and regulation, as compliance with any new rules could be difficult and costly. For example, U.S. federal legislation has been proposed in Congress to reduce GHG emissions. In addition, in the absence of federal GHG legislation, the EPA has taken several recent steps to regulate GHG emissions, which regulations have been challenged. Depending on the outcome of these or other regulatory matters, increased energy, environmental and other costs and capital expenditures could be necessary to comply with the relevant limitations. Our vessels also operate in foreign jurisdictions that are addressing climate changes by legislation or regulation. Unless and until legislation or regulations are enacted and its terms are finalized, we cannot reasonably or reliably estimate its impact on our financial condition, operating performance or ability to compete.

Adverse impacts upon the oil and gas industry relating to climate change may also effect demand for our services which in part depends on the level of activity in offshore oil and natural gas exploration, development and production. Although we do not expect that demand for oil and gas will lessen dramatically over the short term, in the long term global warming may reduce the demand for oil and gas or increased regulation of GHG may create greater incentives for use of alternative energy sources. Any long term material adverse effect on the oil and gas industry may have a material adverse effect on our financial condition and operating results.

Prior events in the U.S. Gulf of Mexico have adversely impacted and are likely to continue to adversely impact our operations and financial condition.

The Macondo Incident in April 2010 effectively caused the cessation of drilling in the U.S. Gulf of Mexico due both to oil spill cleanup efforts and a drilling moratorium. Although the cleanup was largely completed in August 2010 and the moratorium was lifted in October 2010, drilling activity did not begin to recover until April 2012. While we believe we are in the early stages of a period of growth in offshore activity in the U.S. Gulf of Mexico, various new laws and regulations and changes in laws and regulations with respect to offshore drilling activities have affected and could affect the manner and method by which our customers are doing business in the area, which could affect our financial condition or results of operations.

Further, at this time, we cannot predict with any certainty what further impact, if any, the Macondo Incident may have on the regulation of offshore drilling activities or on the cost of insurance to cover the risks of such operations. Announced and anticipated changes in laws and regulations regarding offshore oil and gas exploration and development activities, the cost or availability of insurance, and decisions by customers, governmental agencies, or other industry participants could further reduce demand for our services or increase our costs of operations. This could further increase the adverse impact on our financial condition and operating results, but we cannot reasonably or reliably estimate to what extent such changes will occur, when they will occur, or how severely they will impact us.

Although we have no knowledge of any litigation or claims against us relating to the events in the U.S. Gulf of Mexico, no assurance can be given that we will not be involved in litigation or claims in the future or that they will not have a material adverse effect on our financial condition or results of operation.

ITEM 1B. Unresolved Staff Comments

NONE

ITEM 3. Legal Proceedings

General

Various legal proceedings and claims that arise in the ordinary course of business may be instituted or asserted against us. Although the outcome of litigation cannot be predicted with certainty, we believe, based on discussions with legal counsel and in consideration of reserves recorded, that an unfavorable outcome of these legal actions would not have a material adverse effect on our consolidated financial position and results of operations. We cannot predict whether any such claims may be made in the future.

ITEM 4. Mine Safety Disclosures

NOT APPLICABLE

PART II

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

Our Class A common stock is traded on the New York Stock Exchange (NYSE) under the symbol “GLF”. The following table sets forth the range of high and low sales prices for our common stock and the amount of cash dividends per share declared per share for the periods indicated:


	2012						2011
	High		Low		Dividend		High		Low		Dividend
Quarter ended March 31,	$	55.20	$	42.21	$	0.00	$	47.00	$	30.30	$	0.00
Quarter ended June 30,	$	49.09	$	30.83	$	0.00	$	44.79	$	38.25	$	0.00
Quarter ended September 30,	$	38.56	$	32.75	$	0.00	$	49.20	$	32.97	$	0.00
Quarter ended December 31,	$	35.65	$	27.61	$	1.00	$	45.89	$	34.53	$	0.00

For the period from January 1, 2013 through February 25, 2013, the range of low and high closing prices of our common stock was $33.74 to $40.59, respectively. On February 25, 2013, the closing sale price of our Class A common stock as reported by the NYSE was $37.00 per share and there were 476 stockholders of record.

Issuer Repurchases of Equity Securities

On December 11, 2012, our Board of Directors approved a stock repurchase program for up to a total of $100 million of its issued and outstanding Class A common stock. The stock may be repurchased from time to time on the open market or in privately negotiated transactions. Repurchases can be made from time to time using a variety of methods, which may include open market purchases or purchases through a Rule 10b5-1 trading plan, all in accordance with Securities and Exchange Commission and other applicable legal requirements. The specific timing, price and size of purchases will be determined by our management based on prevailing stock prices, general economic and market conditions and other considerations. The repurchase program does not obligate us to acquire any particular amount of common stock and may be suspended or discontinued at any time.

The value of the common stock repurchased, along with number of shares repurchased, and average price paid per share for the three months ended December 31, 2012 are as follows:

Repurchase of Equity Securities


Period	Total Number of Common Shares Repurchased		Average Price Paid Per Common Share		Total Number of Common Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Common Shares that May Yet Be Purchased Under the Plans or Programs
October 1—31		—		—		—		—
November 1—30		—		—		—		—
December 1—31		35,400	$	33.93		—		—

During the period from January 1, 2013 through February 25, 2013, we repurchased 288,219 shares of common stock for an aggregate price of $10.3 million or an average price of $35.65 per share.

Dividend Program

In December 2012, our Board of Directors declared an annual cash dividend on our Class A common stock of $1.00 per share. While the declaration of dividends is at the discretion of our Board of Directors, commencing in the first quarter of 2013, we intend to pay a recurring quarterly cash dividend of $0.25 per share. The Board of Directors declared the following dividends for the years ended December 31:


	2012		2011
Dividends Declared (in thousands)	$	26,613		—
Dividend per share	$	1.00		—

Prior to December 2012, we had not declared or paid cash dividends during the past five years. Pursuant to the terms of the indenture under which the senior notes, as further described in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt” and Note 5 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 are issued, we may be restricted from declaring or paying any future dividends. Our dividend policy will be reviewed by our Board of Directors at such times as may be appropriate in light of future operating conditions, dividend restrictions of subsidiaries and investors, financial requirements, general business conditions and other factors.

Equity incentive plan information required by this item may be found in Note 8 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 herein.

Performance Graph

The following performance graph and table compare the cumulative return on our common stock to the Dow Jones Total Market Index and the Dow Jones Oilfield Equipment and Services Index for the periods indicated. The graph assumes (i) the reinvestment of dividends, if any, and (ii) the value of the investment of our common stock and each index have been $100 at December 31, 2006.

Comparison of Cumulative Total Return

LOGO


	2007		2008		2009		2010		2011		2012
GulfMark Offshore, Inc.		100		51		59		63		86		72
Dow Jones Total Market Index		100		63		79		90		90		103
Dow Jones Oilfield Equipment and Services Index		100		41		62		76		67		65

ITEM 6. Selected Consolidated Financial Data

The data that follows should be read in conjunction with our Consolidated Financial Statements and the notes thereto included in Part II, Item 8 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, included in Part II, Item 7.


	Year Ended December 31,
	2012			2011			2010			2009			2008
	(Amounts in thousands, except per share amounts)
Operating Data:
Revenue	$	389,205		$	381,870		$	359,766		$	388,871		$	411,740
Direct operating expenses		198,187			182,585			170,638			166,183			143,925
Drydock expense		33,280			15,932			22,182			15,696			11,319
General and administrative expenses		54,600			45,495			44,029			43,700			40,244
Depreciation and amortization		59,722			59,586			56,959			53,044			44,300
Impairment charge		1,152			1,750			97,665			46,247			—
Gain on sale of assets		(8,741	)		(2,018	)		(5,095	)		(5,552	)		(34,811	)

Operating income (loss)		51,005			78,540			(26,612	)		69,553			206,763
Interest expense		(23,244	)		(22,314	)		(21,693	)		(20,281	)		(14,291	)
Interest income		338			748			985			377			1,446
Loss on extinguishment of debt		(4,378	)		—			—			—			—
Foreign currency gain (loss) and other		(1,779	)		(2,346	)		(126	)		(1,153	)		1,609
Income tax (provision) benefit (a)		(2,669	)		(4,694	)		12,701			2,087			(11,743	)

Net income (loss)	$	19,273		$	49,934		$	(34,745	)	$	50,583		$	183,784

Amounts per common share (basic) (b):
Net income (loss)	$	0.73		$	1.92		$	(1.36	)	$	1.98		$	7.65

Weighted average common shares (basic)		26,208			25,828			25,519			25,151			23,737

Amounts per common share (diluted) (b):
Net income (loss)	$	0.73		$	1.91		$	(1.36	)	$	1.96		$	7.47

Weighted average common shares (diluted)		26,228			25,962			25,519			25,447			24,319

Statement of Cash Flows Data:
Cash provided by operating activities	$	102,736		$	97,471		$	91,574		$	171,045		$	205,201
Cash used in investing activities		(198,764	)		(49,408	)		(53,857	)		(68,199	)		(186,787	)
Cash provided by (used in) financing activities		150,604			(16,231	)		(32,837	)		(120,250	)		56,754
Effect of exchange rate changes on cash		1,782			(210	)		236			8,722			(14,526	)
Other Data:
Adjusted EBITDA (c)	$	111,879		$	139,876		$	128,012		$	168,844		$	251,063
Cash dividends per share (d)	$	1.00		$	—		$	—		$	—		$	—
Total vessels in fleet as of year end (e)		78			90			88			92			94
Average number of owned or chartered vessels (f)		71.0			73.8			73.4			71.3			59.5

	As of December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	185,175		$	128,817		$	97,195		$	92,079		$	100,761
Vessels, equipment and other fixed assets, including construction in progress, net		1,305,789			1,180,548			1,194,200			1,204,416			1,169,513
Total assets		1,745,674			1,499,799			1,468,649			1,565,659			1,556,967
Long-term debt (g)		500,999			305,830			293,095			326,361			462,941
Total stockholders’ equity		1,027,882			996,860			945,957			987,468			854,843

(a)	See Note 6 to our “Consolidated Financial Statements – Income Taxes”, included in Part II, Item 8.

(b)	Earnings per share is based on the weighted average number of shares of common stock and common stock equivalents outstanding.

(c)

EBITDA is defined as net income (loss) before interest expense, interest income, income tax (benefit) provision, and depreciation, amortization and impairment. Adjusted EBITDA is calculated by adjusting EBITDA for certain items that we believe are non-cash or non-operational, consisting of: (i) cumulative effect of change in accounting principle, (ii) debt refinancing costs, (iii) loss from unconsolidated ventures, (iv) minority interests, and (v) other (income) expense, net. EBITDA and Adjusted EBITDA are not measurements of financial performance under generally accepted accounting principles, or GAAP, and should not be considered as an alternative to cash flow data, a measure of liquidity or an alternative to operating income or net income as indicators of our operating performance or any other measures of performance derived in accordance with GAAP.

EBITDA and Adjusted EBITDA are presented because they are widely used by security analysts, creditors, investors and other interested parties in the evaluation of companies in our industry. This information is a material component of certain financial covenants in debt obligations. Failure to comply with the financial covenants could result in the imposition of restrictions on our financial flexibility. When viewed with GAAP results and the accompanying reconciliation, we believe the EBITDA and Adjusted EBITDA calculation provides additional information that is useful to gain an understanding of the factors and trends affecting our ability to service debt and meet our ongoing liquidity requirements. EBITDA is also a financial metric used by management as a supplemental internal measure for planning and forecasting overall expectations and for evaluating actual results against such expectations. However, because EBITDA and Adjusted EBITDA are not measurements determined in accordance with GAAP and are thus susceptible to varying calculations, EBITDA and Adjusted EBITDA as presented may not be comparable to other similarly titled measures used by other companies or comparable for other purposes. Also, EBITDA and Adjusted EBITDA, as non-GAAP financial measures, have material limitations as compared to cash flow provided by operating activities. EBITDA does not reflect the future payments for capital expenditures, financing–related charges and deferred income taxes that may be required as normal business operations. Management compensates for these limitations by using our GAAP results to supplement the EBITDA and Adjusted EBITDA calculations.

The following table summarizes the calculation of EBITDA and Adjusted EBITDA for the periods indicated.


	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Net income (loss)	$	19,273		$	49,934		$	(34,745	)	$	50,583		$	183,784
Interest expense		23,244			22,314			21,693			20,281			14,291
Interest income		(338	)		(748	)		(985	)		(377	)		(1,446	)
Income tax provision (benefit)		2,669			4,694			(12,701	)		(2,087	)		11,743
Depreciation, amortization and impairment		60,874			61,336			154,624			99,291			44,300

EBITDA		105,722			137,530			127,886			167,691			252,672
Adjustments:
Other *		6,157			2,346			126			1,153			(1,609	)

Adjusted EBITDA	$	111,879		$	139,876		$	128,012		$	168,844		$	251,063

*	Includes foreign currency transaction adjustments and loss on extinguishment of debt.

(d)

(e)	Includes managed vessels in addition to those that are owned and chartered at the end of the applicable period (excludes vessels held for sale). See “Worldwide Fleet” in Part I, Items 1 and 2 “Business and Properties” for further information concerning our fleet.

(f)	Average number of vessels is calculated based on the aggregate number of vessel days available during each period divided by the number of calendar days in such period. Includes owned and bareboat chartered vessels only, and is adjusted for additions and dispositions occurring during each period.

(g)	Excludes current portion of long-term debt.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This information should be read in conjunction with our Consolidated Financial Statements, including the notes thereto, contained in Part II, Item 8 “Consolidated Financial Statements and Supplementary Data”. See also Part II, Item 6 “Selected Consolidated Financial Data”.

Our Strategy

Our goal is to enhance our position as a premier provider of offshore marine services by achieving higher vessel utilization rates, relatively stable growth rates and returns on investments that are superior to those of our competitors. Key elements in implementing our strategy include:

Profitably growing our business: We continually evaluate opportunities to grow our business profitably, as measured by return on capital employed. Such opportunities typically include the acquisition or construction of new OSVs that improve the age and capabilities of our fleet.

Developing and maintaining a large, modern, diversified and technologically advanced fleet: Our fleet size, location and profile allow us to provide a full range of services to our customers from platform supply work to specialized floating, production, storage and offloading, or FPSO support, including anchor handling and remotely operated vehicle, or ROV, operations. We regularly upgrade our fleet to improve capability, reliability and customer satisfaction. We also seek to take advantage of attractive opportunities to acquire or build new vessels to expand our fleet. In addition, we will sell older vessels that no longer meet our objective of maintaining a modern, diversified and technologically advanced fleet. We believe our relatively young fleet, which requires less maintenance and refurbishment work during required drydockings than older fleets, allows for less downtime, resulting in more dependable operations for us and for our customers.

Enhancing fleet utilization through development of specialty applications for our vessels: We operate some of the most technologically advanced vessels available. Our highly efficient, multiple-use vessels provide our customers flexibility and are constructed with design elements such as dynamic positioning, firefighting, moon pools, ROV handling and oil spill response capabilities. In addition, we design and equip new-build vessels specifically to meet our customer needs.

Focusing on attractive markets: We conduct our operations mainly in the North Sea, offshore Southeast Asia and offshore Americas markets. Our focus on these regions is driven by what we perceive to be higher barriers to entry, lower volatility of day rates (except in the Americas) and greater potential for increasing day rates in these markets than in other markets. Our operating experience in these markets has enabled us to anticipate and profitably respond to trends, such as the increasing demand for multi-function vessels, which we believe will be met through the additions we have made in the past few years to our North Sea and Southeast Asia fleets. In addition, we have the capacity under appropriate market conditions to alter the geographic focus of our operations to a limited degree by shifting vessels between our existing markets and by entering new markets as they develop economically and become more profitable.

Managing our risk profile through chartering arrangements: We utilize various contractual arrangements in our fleet operations, including long-term charters, short-term charters, sharing arrangements and vessel pools. We believe a prudent mix of these contractual arrangements helps us reduce volatility in both charter day rates and vessel utilization, while providing us operational flexibility and opportunity to take advantage of improving market conditions.

Opportunistically selling vessels: In order to maintain a modern, technologically advanced fleet, we routinely sell older OSVs that no longer meet our fleet objectives in order to reinvest in newer vessels. Timing of vessel sales is a key attribute to obtaining the best overall sales price, and over the past seven years we have sold 23 vessels with an average age of 22 years for approximately 115% of the combined original cost of these vessels. This is well in excess of the net book value of these vessels, which reflects the depreciated value based on a 15% salvage value and an asset life of 20 to 25 years.

Maintaining a conservative financial profile: We strive to maintain a strong balance sheet with ample liquidity.

General

We provide marine support and transportation services to companies involved in the offshore exploration and production of oil and natural gas. Our vessels transport drilling materials, supplies and personnel to offshore facilities, as well as move and position drilling structures. A substantial portion of our operations are international. Our fleet has grown in both size and capability, from an original 11 vessels in 1990 to our present number of 78 active vessels, through strategic acquisitions and the new construction of technologically advanced vessels, partially offset by dispositions of certain older, less profitable vessels. At February 25, 2013, our active fleet includes 70 owned vessels and 8 managed vessels. In addition, we currently have 11 vessels under construction that have delivery dates ranging from second quarter 2013 through first quarter 2015.

Our results of operations are affected primarily by day rates, fleet utilization and the number and type of vessels in our fleet. Utilization and day rates, in turn, are influenced principally by the demand for vessel services from the exploration and production sectors of the oil and natural gas industry. The supply of vessels to meet this fluctuating demand is related directly to the perception of future activity in both the drilling and production phases of the oil and natural gas industry as well as the availability of capital to build new vessels to meet the changing market requirements.

From time to time, we bareboat charter vessels with revenue and operating expenses reported in the same income and expense categories as our owned vessels. The chartered vessels, however, incur bareboat charter fees instead of depreciation expense. Bareboat charter fees are generally higher than the depreciation expense on owned vessels of similar age and specification. The operating income realized from these vessels is therefore adversely affected by the higher costs associated with the bareboat charter fees. These vessels are included in calculating fleet day rates and utilization in the applicable periods.

We also provide management services to other vessel owners for a fee. We do not include charter revenue and vessel expenses of these vessels in our operating results; however, management fees are included in operating revenue. These vessels are excluded for purposes of calculating fleet rates per day worked and utilization in the applicable periods.

Our operating costs are primarily a function of fleet configuration. The most significant direct operating cost is wages paid to vessel crews, followed by maintenance and repairs and insurance. Generally, fluctuations in vessel utilization have little effect on direct operating costs in the short term and, as a result, direct operating costs as a percentage of revenue may vary substantially due to changes in day rates and utilization.

In addition to direct operating costs, we incur fixed charges related to the depreciation of our fleet and costs for routine drydock inspections and modifications designed to ensure compliance with applicable regulations and maintaining certifications for our vessels with various international classification societies. The number of drydockings and other repairs undertaken in a given period generally determines maintenance and repair expenses. The demands of the market, the expiration of existing contracts, the start of new contracts, and customer preferences influence the timing of drydocks.

Critical Accounting Policies and Estimates

The Consolidated Financial Statements, including notes thereto, contained in Part II, Item 8 contain information that is pertinent to management’s discussion and analysis. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of any contingent assets and liabilities. Management believes these accounting policies involve judgment due to the sensitivity of the methods, assumptions and estimates necessary in determining the related asset and liability amounts. We believe we have exercised proper judgment in determining these estimates based on the facts and circumstances available to management at the time the estimates were made.

Income Taxes

The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under “tonnage tax” regimes having a ten year term and are renewable. Our U.K. regime was renewed in November 2010 for another ten years. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These foreign tax beneficial structures continued to result in our earnings incurring significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions. The tonnage tax regimes in the North Sea significantly reduce the cash required for taxes in that region.

In February 2010, the Norway Supreme Court ruled 2007 tax legislation to be unconstitutional retroactive taxation and we reversed our existing tonnage tax liability and received a refund of pre-2007 tonnage taxes that had been paid in 2008 and 2009, which resulted in our recording an approximately $15.0 million tax benefit in our 2010 tax provision. In June 2010, Norway’s Minister of Finance published revised rules for the taxation of pre-2007 tonnage tax profits permitting a qualified tonnage tax company to elect one of two systems, or methods, to determine and pay tax on its untaxed shipping profits as of December 31, 2006. We decided to elect the simplified tax system, which beginning in 2011 requires three equal annual installment payments of the tax that is calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits. Under this system we recorded a $4.9 million tax provision. The net result of the 2010 Norwegian tonnage tax law changes was a $10.1 million tax benefit recorded in our 2010 tax provision. Our final liability to settle under the simplified tax system is included in our December 31, 2012 balance sheet as a $1.8 million current income tax payable.

Our overall effective tax rate is substantially lower than the U.S. federal statutory income tax rate because our Southeast Asia and North Sea operations are tonnage tax qualified shipping activities that are taxed at relatively low rates or that are otherwise tax exempt. Should our operational structure change or should the laws that created these shipping tax regimes change, we could be required to provide for taxes at rates much higher than those currently reflected in our consolidated financial statements. Additionally, if our pre-tax earnings in higher tax jurisdictions increase, there could be a significant increase in our annual effective tax rate. Any such increase could cause volatility in the comparisons of our effective tax rate from period to period.

U.S. foreign tax credits can be carried forward for ten years. We have $7.6 million of such foreign tax credit carryforwards that begin to expire in 2013. In 2012 we established a $3.1 million valuation allowance for certain of our foreign tax credits. We also have certain foreign net operating loss carryforwards that result in net deferred tax assets of approximately $1.2 million after valuation allowances. We have considered estimated future taxable income in the relevant tax jurisdictions to utilize these tax credit and loss carryforwards and have considered what we believe to be ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance. This information is based on estimates and assumptions including projected taxable income. If these estimates and related assumptions change in the future, or if we determine that we would not be able to realize other deferred tax assets in the future, an adjustment to the valuation allowance would be provided in the period such determination was made.

Mexico’s tax law includes a revenue based tax, which in effect is an alternative minimum tax payable to the extent that the revenue based tax exceeds the current income tax liability. The revenue based tax rate is 17.5%. Effective January 1, 2010, Mexico enacted changes to corporate income tax rates as follows: 2010 through 2012 – 30%; 2013 – 29%; and 2014 and beyond 28%. However, in December 2012 Mexico tax legislation extended the 30% rate for 2013 and delayed the rate reductions by one year.

Based on a more likely than not, or greater than 50% probability, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return, we evaluate and record in certain circumstances an income tax asset/liability for uncertain income tax positions. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and/or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate. We also consider existing accounting guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. Accordingly, we continue to recognize income tax related penalties and interest in our provision for income taxes and, to the extent applicable, in the corresponding consolidated balance sheet presentations for accrued income tax assets and liabilities, including any amounts for uncertain tax positions.

See also Note 1 and Note 6 to our Consolidated Financial Statements included in Part II, Item 8.

Long-Lived Assets, Goodwill and Intangibles

Our long-lived tangible assets consist primarily of vessels and construction-in-progress. Our goodwill primarily relates to the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition of Brovig Supply AS. Our identifiable intangible assets relate to the value assigned to customer relationships as a result of our acquisition of Rigdon Marine Corporation and Rigdon Marine Holdings, LLC, in July 2008 (the “Rigdon Acquisition”). The determination of impairment of all long-lived assets, goodwill, and intangibles is conducted when indicators of impairment are present and at least annually, for goodwill. In assessing goodwill for impairment, we analyze certain qualitative factors that affect the value, including goodwill, of a segment. Impairment testing on tangible long-lived assets is performed on an asset-by-asset basis and impairment testing on goodwill is performed on a reporting-unit basis for the reporting units where the goodwill is recorded.

In assessing potential impairment related to our long-lived assets, the assets’ carrying values are compared with undiscounted expected future cash flows. If the carrying value of any long-lived asset is greater than the related undiscounted expected future cash flows, we measure impairment by comparing the fair value of the asset with its carrying value.

At least annually, we assess whether goodwill is impaired based on certain qualitative factors. If those factors indicate that it is more likely than not that impairment of goodwill has occurred, we will proceed to step one of the goodwill impairment process. Under step one, we assess whether impairment exists by comparing the fair value of each reporting unit to its carrying value, including goodwill. We use a combination of two valuation methods, a market approach and an income approach, to estimate the fair value of our reporting unit.

We had classified one of our North Sea vessels as an asset held for sale. In the fourth quarter of 2011, we determined that the carrying value of this asset was less than our estimate of the amount we would realize in a sale. As a result, we reduced the carrying value by $1.8 million. During 2012, we reduced the carrying value of this asset by an additional $1.2 million. These amounts were based on third party appraisals and sales agreements and are included in our results of operations as impairment charges. We sold this vessel in January 2013 for total proceeds of $0.7 million, which approximated the carrying value of the vessel at December 31, 2012.

In the Rigdon Acquisition, we made a significant acquisition of vessels in the U.S. Gulf of Mexico component of our Americas region. In conjunction with the acquisition, we recorded $97.7 million of goodwill. In the second quarter of 2010, we assessed our Americas region goodwill for impairment. In our assessment, we evaluated the impact on the segment’s fair value due to the

Macondo Incident, the resulting oil spill and the drilling moratorium. Based on the factors discussed above, which were incorporated into our evaluations and testing as prescribed under U.S. GAAP, we determined that an impairment of our Americas region goodwill existed, and accordingly we recorded a $97.7 million impairment charge as of June 30, 2010, reflecting all of our Americas region goodwill. The non-cash charge did not impact our liquidity or debt covenant compliance. See Note 2 to the Consolidated Financial Statements contained in Part II, Item 8.

Drydocking, Mobilization and Financing Costs

The periodic requirements of the various classification societies requires vessels to be placed in drydock twice in a five-year period. Generally, drydocking costs include refurbishment of structural components as well as major overhaul of operating equipment, subject to scrutiny by the relevant classification society. We expense these costs as incurred.

In connection with new long-term contracts, incremental costs incurred that directly relate to mobilization of a vessel from one region to another are deferred and recognized over the primary contract term. Should the contract be terminated by either party prior to the end of the contract term, the deferred amount would be immediately expensed. In contrast, costs of relocating vessels from one region to another without a contract are expensed as incurred.

Deferred financing costs are capitalized as incurred and are amortized over the expected term of the related debt. Should the specific debt terminate by means of payment in full, tender offer or lender termination, the associated deferred financing costs would be immediately expensed.

Allowance for Doubtful Accounts

Our customers are primarily major and independent oil and gas companies, national oil companies and oil service companies. Given our experience where our historical losses have been insignificant and our belief that our related credit risks are minimal, our major and independent oil and gas company and oil service company customers are granted credit on customary business terms. Our exposure to foreign government-owned and controlled oil and gas companies, as well as companies that provide logistics, construction or other services to such oil and natural gas companies, may result in longer payment terms; however, we monitor our aged accounts receivable on an ongoing basis and provide an allowance for doubtful accounts in accordance with our written corporate policy. This formalized policy ensures there is a critical review of our aged accounts receivable to evaluate the collectability of our receivables and to establish appropriate allowances for bad debt. This policy states that a reserve for bad debt is to be established if an account receivable is outstanding a year or longer. The amount of such reserve to be established by management is based on the facts and circumstances relating to the particular customer.

Historically, we have collected appreciably all of our accounts receivable balances; however, in 2012, the amount increased significantly due to a customer that declared bankruptcy. At December 31, 2012 and 2011 we provided an allowance for doubtful accounts of $3.2 million and $0.2 million, respectively. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay, particularly in the event of deteriorating economic conditions. Since amounts due from individual customers can be significant, future adjustments to our allowance for doubtful accounts could be material if one or more individual customer balances are deemed uncollectible. If an account receivable were deemed uncollectible and all reasonable collection efforts were exhausted, the balance would be removed from accounts receivable and the allowance for doubtful accounts.

Commitments and Contingencies

We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims may involve threatened or actual litigation where damages have not been specifically quantified but we have made an assessment of our exposure and recorded a provision in our accounts for the expected loss. Other claims or liabilities, including those related to taxes in foreign jurisdictions, may be estimated based on our experience in these matters and, where appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of the uncertainties surrounding our estimates of contingent liabilities and future claims, our future reported financial results will be impacted by the difference, if any, between our estimates and the actual amounts paid to settle the liabilities. In addition to estimates related to litigation and tax liabilities, other examples of liabilities requiring estimates of future exposure include contingencies arising out of acquisitions and divestitures. Our contingent liabilities are based on the most recent information available to us regarding the nature of the exposure. Such exposures change from period to period based upon updated relevant facts and circumstances, which can cause the estimate to change. In the recent past, our estimates for contingent liabilities have been sufficient to cover the actual amount of our exposure.

We have recently been made aware that a Brazilian state in which we have operated vessels has asserted that certain companies could be assessed for state import taxes with respect to vessels that have operated within Brazilian coastal waters. We have neither been formally assessed nor threatened with this tax. No accrual has been recorded as of December 31, 2012 for any liabilities associated with a possible future assessment. We cannot predict whether any such tax assessment may be made in the future.

Multi-employer Pension Obligation

Certain current and former U.K. subsidiaries are participating in a multi-employer retirement fund known as the Merchant Navy Officers Pension Fund (“MNOPF”). At December 31, 2012, we had $4.7 million accrued related to this liability, which reflects all obligations assessed on us by the fund’s trustee. We continue to have employees who participate in the MNOPF and will as a result continue to make routine payments to the fund as those employees accrue additional benefits over time. The status of the fund is calculated by an actuarial firm every three years. The last assessment was completed in March 2012, however the results will not be published until the second quarter of 2013. The amount and timing of additional potential future obligations relating to underfunding depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, asset performance, the number of participating employers, and the final method used in allocating the required contribution among participating employers. In addition, our obligation could increase if other employers no longer participated in the plan. We made contributions to the plan of $0.8 million, $0.3 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Our contributions do not make up more than five percent of total contributions to the plan.

In addition, we participate in the Merchant Navy Ratings Pension Fund (“MNRPF”) in a capacity similar to our participation in the MNOPF. While historically we have not been required to contribute to any deficit in the MNRPF due to a recent change in the plan rules we have been advised that we will be required to make contributions beginning in 2013. We have also been advised that the actuarial valuation as at March 31, 2011 (the most recent valuation available) identified a total plan deficit. We have accrued an estimate of our share of this deficit totaling $0.1 million during 2012 in anticipation of this obligation.

Cancellation of Split Dollar Life Insurance Plans

In June 2011, we cancelled the split dollar insurance agreements (the “Collateral Assignments”) under which we paid the split-dollar life insurance policy premiums (the “Premiums”) for our President and Chief Executive Officer and our Executive Vice President – Operations. Upon cancellation and pursuant to the term of the Collateral Assignments, we were repaid the Premiums by each covered individual and are no longer obligated to make any future premium payments on the policies. We continue to have a supplemental income plan with participation agreements, as amended, for each covered individual under which we will provide each covered individual, six months after retirement, a cash payment equal to the Premiums.

Off-Balance Sheet Arrangements

We have evaluated our off-balance sheet arrangements, and have concluded that we do not have any material relationships with unconsolidated entities or financial partnerships that have been established for the purpose of facilitating off-balance sheet arrangements (as that term is defined in Item 303(a)(4)(ii) of Regulations S-K). Based on this evaluation we believe that no disclosures relating to off-balance sheet arrangements are required.

Consolidated Results of Operations

Comparison of the Fiscal Years Ended December 31, 2012 and December 31, 2011

Our consolidated revenue increased from $381.9 million to $389.2 million, or $7.3 million, primarily due to higher day rates in the Americas region partially offset by lower utilization in Southeast Asia and the North Sea. For the year ended December 31, 2012, we had net income of $19.3 million, or $0.73 per diluted share, compared to net income of $49.9 million, or $1.91 per diluted share, for the year ended December 31, 2011.

The increase in revenue was primarily the result of increased day rates, which increased 6.1% in 2012, from $16,642 in 2011 to $17,661 in 2012, contributing $26.6 million to the increase in revenue. Net capacity effects due to the purchase of two large PSVs during 2012, also increased revenue by $2.6 million. The strengthening of the U.S. Dollar and other currency movements negatively impacted revenue by $2.9 million. In addition, a decrease in overall utilization, from 85.3% in 2011 to 84.2% in 2012, decreased revenue by $19.0 million.


	Year Ended December 31,
	2012			2011			Increase (Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea (c)	$	20,075		$	20,071		$	4
Southeast Asia		14,383			15,053			(670	)
Americas		17,150			14,526			2,624
Overall Utilization (a) (b):
North Sea (c)		89.6	%		92.4	%		(2.8	)%
Southeast Asia		79.4	%		85.1	%		(5.7	)%
Americas		82.5	%		80.5	%		2.0	%
Average Owned or Chartered Vessels (a) (d):
North Sea		24.2			24.8			(0.6	)
Southeast Asia		14.9			14.0			0.9
Americas		31.9			35.0			(3.1	)

Total		71.0			73.8			(2.8	)

(a)	Owned vessels.

(b)	Average rates per day worked is defined as total charter revenue divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.

(c)

Revenue for vessels in our North Sea fleet are primarily earned in GBP, NOK and Euros, and have been converted to U.S. Dollars at the average exchange rate (US Dollar/GBP, US Dollar/NOK and US Dollar/Euro) for the periods indicated below. The North Sea based fleet also includes vessels working offshore India, offshore Africa and the Mediterranean. Payment for vessels in our Southwest Asia fleet can be earned in other currencies, including the Singapore Dollar (“SGD”). Payment for vessels in our Americas fleet can be earned in other currencies, including the Brazilian Reais (“BRL”).


	Year Ended December 31,
	2012		2011
$1 US=GBP		0.631		0.623
$1 US=NOK		5.814		5.600
$1 US=Euro		0.777		0.718
$1 US=BRL		1.945		1.668
$1 US=SGD		1.249		1.256

(d)	Adjusted for vessel additions and dispositions occurring during each period.

Direct operating expenses increased by $15.6 million during 2012. This was primarily due to an increase in crew salaries and benefits, combined with higher vessel supplies and consumables mainly due to fuel costs related to vessel mobilization, in addition to slightly higher repairs and maintenance expense related to the mobilized vessels. In 2011, we recorded a $1.8 million impairment charge to adjust the net realizable value of a North Sea vessel that was held for sale. Drydock expense increased by $17.3 million from 2011 to 2012 due to a significantly higher number of drydocks. We had 35 vessels drydocked in 2012 compared to 24 in 2011. General and administrative expenses increased by $9.1 million from 2011 due to an increase in salaries and benefits, largely related to termination benefits, higher bad debt expense, higher professional fees and increased travel cost. Depreciation expense remained consistent with the prior year. The gain on sale of assets in 2012 relates to the sale of five of our U.S. crew boats and fast supply vessels as part of our effort to upgrade our existing fleet mix.

Interest expense increased $0.9 million year over year due mainly to the acceleration of recognition of our unrealized losses in other comprehensive income related to interest rate swaps into earnings, combined with a higher overall debt level for part of the year, partially offset by higher capitalized interest related to our vessel construction program. Interest income decreased $0.4 million due to lower cash amounts available for investment and other expense increased by $3.8 million due mainly to $4.4 million of loss on extinguishment of debt, partially offset by $0.6 million of lower foreign currency losses during 2012 compared to 2011.

The income tax expense for 2012 was $2.7 million, compared to $4.7 million for 2011. The 2012 effective tax rate was 12.2% and the 2011 effective tax rate was 8.6%. Tax expense from year to year can vary based on the mix of profitability and taxing jurisdictions.

Comparison of the Fiscal Years Ended December 31, 2011 and December 31, 2010

Our consolidated revenue increased from $359.8 million to $381.9 million, or $22.1 million, primarily due to higher day rates in the North Sea and Americas regions. For the year ended December 31, 2011, we had net income of $49.9 million, or $1.91 per diluted share, compared to a net loss of $34.7 million, or $1.36 per diluted share, for the year ended December 31, 2010.

The increase in revenue was primarily the result of increased day rates and the foreign currency impact of a weaker U.S. Dollar. Day rates increased 5.6% in 2011, from $15,758 in 2010 to $16,642 in 2011, contributing $14.6 million to the increase in revenue. The weakening of the U.S. Dollar and other currency movements contributed $8.2 million to the revenue increase. This increase was offset by a small decrease in utilization from 85.5% in 2010 to 85.3% in 2011, decreasing revenue by $0.5 million. Capacity effects decreased revenue by $0.2 million.


	Year Ended December 31,
	2011			2010			Increase (Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea (c)	$	20,071		$	16,985		$	3,086
Southeast Asia		15,053			16,943			(1,890	)
Americas		14,526			14,281			245
Overall Utilization (a) (b):
North Sea (c)		92.4	%		93.5	%		(1.1	)%
Southeast Asia		85.1	%		84.7	%		0.4	%
Americas		80.5	%		80.1	%		0.4	%
Average Owned or Chartered Vessels (a) (d):
North Sea		24.8			25.1			(0.3	)
Southeast Asia		14.0			13.0			1.0
Americas		35.0			35.3			(0.3	)

Total		73.8			73.4			0.4

(a)	Includes all owned or bareboat chartered vessels. Managed vessels are not included.

(b)	Average rates per day worked is defined as total charter revenue divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.

(c)

Revenue for vessels in our North Sea fleet are primarily earned in GBP, NOK and Euros, and have been converted to U.S. Dollars at the average exchange rate (US Dollar/GBP, US Dollar/NOK and US Dollar/Euro) for the periods indicated below. The North Sea based fleet also includes vessels working offshore India, offshore Africa and the Mediterranean. Payment for vessels in our Southwest Asia fleet can be earned in other currencies, including SGD. Payment for vessels in our Americas fleet can be earned in other currencies, including BRL.


	Year Ended December 31,
	2011		2010
$1 US=GBP		0.623		0.647
$1 US=NOK		5.600		6.036
$1 US=Euro		0.718		0.754
$1 US=BRL		1.668		1.759
$1 US=SGD		1.256		1.362

(d)	Adjusted for vessel additions and dispositions occurring during each period.

Direct operating expenses increased by $11.9 million during 2011 mainly due to an increase in crew salaries and benefits and the foreign currency impact of the weaker U.S. Dollar. In 2011, we recorded a $1.8 million impairment charge to adjust the net realizable value of a North Sea vessel that was held for sale. In 2010, we recorded a $97.7 million dollar impairment of our goodwill as a result of the deteriorating market conditions in the U.S. Gulf of Mexico. Drydock expense decreased by $6.3 million from 2010 to 2011 due to a lower number of drydocks. We had 24 vessels that were drydocked in 2011 compared to 30 in 2010. General and administrative expenses increased by $1.5 million from 2010 due mainly to the increase in salaries and benefits. Depreciation expense increased by $2.6 million year over year as a result of currency effects and our ongoing effort to reduce the average age of our vessel fleet. The gain on sale of assets relates to the sale of one of our North Sea vessels during 2011.

Interest expense increased $0.6 million year over year due mainly to the decrease in capitalized interest resulting from a smaller portion of the year with vessels under construction during 2011 compared to 2010. Interest income decreased $0.2 million due to lower cash amounts available for investment and other expense increased by $2.2 million as a result of foreign currency movements throughout 2011.

The income tax expense for 2011 was $4.7 million, compared to a benefit of $12.7 million from 2010. The 2011 effective tax rate was 8.6% and the 2010 effective tax rate was 26.8%. The 2011 tax expense is primarily due to our mix of profitability in our tax jurisdictions. The 2010 tax benefit was mostly the result of our $10.1 million Norwegian net tax benefit coupled with the net effect of tax benefits from operating losses in our high tax jurisdictions exceeding tax expense from our lower taxed operations.

Segment Results

As discussed in “General Business” included in Part I, Items 1 and 2, we have three operating segments: the North Sea, Southeast Asia and the Americas, each of which is considered a reportable segment under FASB ASC 280. The majority of our revenue is derived from our long-lived assets located in foreign jurisdictions. In 2012, we had $113.6 million in revenue and $374.4 million in long-lived assets attributed to the United States, our country of domicile.

Management evaluates segment performance primarily based on operating income. Cash and debt are managed centrally, and since the regions do not manage those items, the gains and losses on foreign currency remeasurements associated with these items are excluded from operating income. Management considers segment operating income to be a good indicator of each segment’s operating performance from its continuing operations, because it represents the results of the ownership interest in operations without regard to financing methods or capital structures. Each segment’s operating income (loss) is summarized in the following table, and further detailed in the following paragraphs.

Operating Income (Loss) by Operating Segment


	Year Ended December 31,
	2012			2011			2010
	(In thousands)
North Sea	$	30,611		$	50,916		$	38,209
Southeast Asia		23,072			35,287			39,761
Americas		23,746			16,397			(81,223	)

Total reportable segment operating income (loss)		77,429			102,600			(3,253	)
Other		(26,424	)		(24,060	)		(23,359	)

Total reportable segment and other operating income (loss)	$	51,005		$	78,540		$	(26,612	)

North Sea Region:


	Year Ended December 31,
	2012		2011			2010
	(In thousands)
Revenue	$	164,273	$	172,393		$	148,740
Direct operating expenses		84,808		81,528			78,253
Drydock expense		11,587		8,563			7,598
General and administrative expense		16,747		12,169			11,277
Depreciation and amortization expense		19,368		19,495			18,649
Impairment charge		1,152		1,750			—
Gain on sale of assets		—		(2,028	)		(5,246	)

Operating income	$	30,611	$	50,916		$	38,209

Comparison of Fiscal Year Ended December 31, 2012 and December 31, 2011

Revenue for the North Sea decreased $8.1 million, or 4.7%, compared to 2011. The decrease was due primarily to decreased utilization in the region from 92.4% in 2011 to 89.6% in 2012, which negatively impacted revenue by $6.2 million. In addition, currency and other effects as a result of the strengthening of the U.S. Dollar decreased revenue by $2.9 million. Capacity effects, due mainly to the sale of a North Sea vessel in late 2011, also lowered revenue by $1.6 million during 2012. These effects were offset slightly by increased day rates year over year, from $20,071 in 2011 to $20,075 in the current year, which increased revenue by $2.6 million. Operating income of $30.6 million in 2012 was $20.3 million lower than 2011 due to the decrease in revenues coupled with higher operating costs that includes higher crew salaries and benefits and higher fuel costs resulting from vessel mobilizations during 2012. Drydock expense increased $3.0 million from 2011 due to more drydock days incurred. Depreciation expense decreased year over year by $0.1 million. General and administrative expense increased by $4.6 million due primarily to the increase in bad debt expense and higher salaries and professional fees.

Comparison of Fiscal Year Ended December 31, 2011 and December 31, 2010

Revenue for the North Sea increased $23.7 million, or 15.9%, compared to 2010. The increase in day rates from $16,985 in 2010 to $20,071 in the current year contributed $18.7 million to the increase in revenue. Currency and other movements as a result of the weakening of the U.S. Dollar contributed $8.4 million to the increase in revenue in 2011. This increase was offset by decreased utilization and capacity during 2011. Utilization decreased in the current year to 92.4% from 93.5% in 2010, resulting in a decrease to revenue of $0.9 million. Decreased capacity from the sale of a vessel in 2010 and another one late in 2011 offset by the delivery of a new-build vessel in early 2010, negatively impacted revenue by $2.5 million compared to the prior year. Operating income of $50.9 million in 2011 was $12.7 million higher than 2010 due to the increase in revenues offset by higher operating costs and lower gains on asset sales in 2011. Direct operating expenses were higher by $3.3 million in 2011 due to the higher crew salaries combined with the impact of the weakening of the U.S. Dollar. Drydock expense increased $1.0 million from 2010 due to a higher drydock cost per day. Depreciation expense increased year over year by $0.8 million primarily due to currency effects. In 2011, we wrote down the value of an asset held for sale by $1.8 million to properly reflect net realizable value. General and administrative expense increased by $0.9 million due primarily to the increase in salaries and professional fees.

Southeast Asia Region:


	Year Ended December 31,
	2012		2011		2010
	(In thousands)
Revenue	$	60,504	$	63,754	$	66,533
Direct operating expenses		17,150		12,006		10,395
Drydock expense		5,923		3,871		4,796
General and administration expense		3,755		2,852		2,659
Depreciation and amortization expense		10,604		9,738		8,922
Gain on sale of assets		—		—		—

Operating income	$	23,072	$	35,287	$	39,761

Comparison of Fiscal Year Ended December 31, 2012 and December 31, 2011

Revenues for the Southeast Asia based fleet decreased by $3.3 million to $60.5 million in 2012. The decrease was due primarily to decreased utilization in the region from 85.1% in 2011 to 79.4% in 2012, which negatively impacted revenue by $7.0 million. Day rates also decreased, from $15,053 in 2011 to $14,383 in the current year, which decreased revenue by $1.3 million. The increase in fleet size as a result of the arrival of one vessel from the Americas region in the first quarter of 2012 positively contributed $5.0 million to revenue. The second vessel mobilized from the Americas region was in the fourth quarter of 2012 and did not impact 2012 revenue. Operating income was lower during 2012 by $12.2 million, due to the lower revenue, combined with an increase in direct operating expense attributable to higher repairs and maintenance and fuel costs associated with the mobilization of vessels to the area from Brazil, and higher crew salaries and benefits. Depreciation expense increased $0.9 million as a result of the additional vessels arriving from the Americas region. Drydock expense increased by $2.1 million as a result of more drydock days in the current year. General and administrative expense increased by $0.9 million due mainly to charges related to management restructuring.

Comparison of Fiscal Year Ended December 31, 2011 and December 31, 2010

Revenues for the Southeast Asia based fleet decreased by $2.8 million to $63.8 million in 2011. Day rates decreased from $16,943 in 2010 to $15,053 in the current year, which decreased revenue by $8.1 million. This was offset by an increase in utilization from 84.7% in 2010 to 85.1% in 2011, contributing $1.7 million to revenue. Capacity had a positive impact to revenue of $3.6 million compared to 2010 as a result of the full year effect of two new-build vessels added in 2010. Operating income was lower during 2011 by $4.5 million, due mainly to the lower revenue, coupled with increases to direct operating expense and depreciation expense resulting primarily from the full year effect of the increased fleet. Drydock expense decreased by $0.9 million as a result of fewer drydock days in 2011. General and administrative expense increased by $0.2 million as a result of higher office salaries and benefits and higher bad debt expense.

Americas Region:


	Year Ended December 31,
	2012			2011		2010
	(In thousands)
Revenue	$	164,428		$	145,723	$	144,493
Direct operating expenses		96,229			89,051		81,990
Drydock expense		15,770			3,498		9,788
General and administrative expense		10,006			8,376		7,798
Depreciation and amortization expense		27,421			28,391		28,321
Impairment charge		—			—		97,665
(Gain) loss on sale of assets		(8,744	)		10		154

Operating income (loss)	$	23,746		$	16,397	$	(81,223	)

Comparison of Fiscal Year Ended December 31, 2012 and December 31, 2011

Our Americas region revenue increased $18.7 million, or 12.8%, from $145.7 million in 2011 to $164.4 million in 2012. The increase was largely due to the increase of 18.1% in average day rates from $14,526 in 2011 to $17,150 in 2012, contributing $25.3 million to revenue. Utilization also increased from 80.5% to 82.5% in the current year resulting in a $1.0 million increase in revenues. Capacity negatively impacted revenue by $7.6 million due to the departure of one vessel to our Southeast Asia region in the first quarter of 2012, partially offset by the net effect of vessel purchases and sales in the year. The second vessel mobilized to the Southeast Asia region was in the fourth quarter of 2012 and did not impact 2012 revenue. Operating income of $23.7 million is $7.3 million higher than the 2011 amount. The increase is due to the increase in revenue coupled with the gains recognized from the sale of five vessels in the region during 2012. This was offset by higher direct operating expenses, mainly crew salaries and benefits and higher drydock expense as a result of significantly more drydock days. General and administrative expense also increased by $1.6 million due primarily to the increase in salaries and benefits and professional fees.

Comparison of Fiscal Year Ended December 31, 2011 and December 31, 2010

Our Americas region revenue increased $1.2 million from 2010. Day rates increased from $14,281 in 2010 to $14,526 in 2011, which contributed $3.9 million to the increase in revenue. Capacity had a negative revenue impact of $1.4 million as a result of the full year effect of the sale of one of our older vessels during the second quarter of 2010. Utilization increased from 80.1% in 2010 to 80.5% in 2011, however, due to the mix of higher utilization associated with lower day rate contracts, the impact was a negative $1.3 million. Excluding the impairment charge of $97.7 million in 2010, operating income was unchanged in 2011 compared to 2010 as the increase in revenue was effectively offset with higher operating expenses. Operating expenses increased from the prior year due mainly to an increase in crew salaries and benefits. Drydock expense was lower in 2011 by $6.3 million as we incurred 79 fewer drydock days during the current year. General and administrative expense increased by $0.6 million due mainly to increased salaries and benefits, primarily in Brazil.

Liquidity and Capital Resources

Our ongoing liquidity requirements are generally associated with our need to service debt, fund working capital, maintain our fleet, finance the construction of new-build vessels, and acquire or improve equipment or vessels. In December 2012, our Board of Directors declared an annual cash dividend on our Class A common stock of $1.00 per share. While the declaration of dividends is at the discretion of our Board of Directors, commencing in the first quarter of 2013, we intend to pay a recurring quarterly cash dividend of $0.25 per share. We also announced a $100.0 million program to repurchase outstanding stock. We plan to continue to be active in the acquisition of additional vessels through both the resale market and new construction. Public debt, bank financing, equity capital and internally generated funds have historically provided funding for these activities. Internally generated funds are directly related to fleet activity and vessel day rates, which are generally dependent upon the demand for our vessels which is ultimately determined by the supply and demand for the offshore drilling for crude oil and natural gas.

In the third quarter of 2011, our Board of Directors approved the initiation of a new-build construction program. We began the program in the North Sea region where we contracted with three shipyards to build a total of six platform supply vessels (“PSVs”). The estimated total cost of these initial six vessels is $228.0 million. In addition, in late 2011, we exercised an option with one of the shipyards to build an additional vessel at an estimated cost of $60.0 million. The first of these vessels is scheduled to be delivered in the second quarter of 2013 and the last is scheduled to be delivered in the first quarter of 2014.

In June 2012, we signed an agreement with a U.S. shipyard to build two U.S. flagged PSVs for the U.S. Gulf of Mexico at an estimated total cost of $72.0 million. In July 2012, we signed agreements with another U.S. shipyard to build an additional two U.S. flagged PSVs at an estimated total cost of $96.0 million. The first of these vessels is scheduled to be delivered in the third quarter of 2013 and the last is scheduled for the first quarter of 2015.

During the third quarter of 2012, we also placed $52.4 million in escrow related to two of the Americas region new builds. The amount in escrow will be drawn against as progress payments become due. The amount held in escrow is segregated from cash and cash equivalents and is presented in long-term assets on our December 31, 2012 balance sheet.

Interest expense at current rates under our existing debt arrangements, assuming no additional borrowings, will be approximately $18.9 million for 2013. We have no scheduled principle payments for 2013. These amounts are anticipated to be paid from a combination of cash on hand and cash from operations.

In addition, we are required to make expenditures for the certification and maintenance of our vessels. We expect our drydocking expenditures to be approximately $25.5 million in 2013, a decrease from the previous year total of $33.3 million. We had 35 drydocks in 2012 and anticipate 27 drydocks in 2013.

Net working capital at December 31, 2012, was $224.8 million, including $185.2 million in cash. Net cash provided by operating activities was $102.7 million for the year ended December 31, 2012. For the year ended December 31, 2012, net cash used in investing activities was $198.8 million, and net cash provided by financing activities was $150.6 million.

At December 31, 2012, we had approximately $185.2 million of cash on hand. We had no amounts drawn under our Multicurrency Facility Agreement, and $501.0 million outstanding on our newly issued Senior Notes. At December 31, 2012, we had $150.0 million of borrowing capacity under our Multicurrency Facility Agreement.

As of December 31, 2012, approximately 40% of our cash and cash equivalents were held by our foreign subsidiaries. It is our intention to permanently reinvest all of our earnings generated outside the U.S. prior to December 31, 2012 that through that date had not been remitted (unremitted earnings), and as such we have not provided for U.S. income tax expense on these unremitted earnings.

In recent years, we repatriated cash from our foreign subsidiaries from current year foreign earnings and recognized U.S. tax expense, net of available credits, on those occasions. The incremental tax rate associated with these repatriations has been approximately 30% with no U.S. cash tax requirement due to utilization of U.S. net operating losses.

If any portion of the unremitted earnings were ever foreseen to not be permanently reinvested outside the U.S., or if we elect to repatriate a portion of current year foreign earnings, U.S. income tax expense would be required to be recognized and that expense could be material. Although subject to certain limitations, our U.S. net operating loss carryforwards and foreign tax credit carryforwards could be used to reduce a portion or all of the U.S. cash tax requirements of any such future foreign cash repatriations.

We anticipate that cash on hand, future cash flow from operations, periodic sales of older or non-strategic vessels and access to our revolving credit facilities will be adequate to fund our new-build construction program, to service our debt obligations, to complete scheduled drydockings, to make normal recurring capital additions and improvements and to meet operating and working capital requirements including dividend payments and stock purchases. This expectation, however, is dependent upon the success of our operations, our ability to access our credit lines and our ability to sell vessels on a timely basis for reasonable value.

Long-Term Debt

Senior Notes – Due 2022

commencing September 15, 2012 for the March 12, 2012 Senior Notes, and commencing March 15, 2013 for the December 5, 2012 Senior Notes. Prior to March 15, 2017, we may redeem some or all of the Senior Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The make-whole premium is based on U.S. treasuries plus 50 basis points. On and after March 15, 2017, we may redeem some or all of the Senior Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.188% for the twelve-month period beginning March 15, 2017, 102.125% for the twelve-month period beginning March 15, 2018, 101.063% for the twelve-month period beginning March 15, 2019 and 100.000% beginning March 15, 2020, plus accrued and unpaid interest to the redemption date. In conjunction with the Senior Note offerings, we incurred $12.7 million in debt issuance cost which is included in our balance sheet under deferred costs and other assets and which will be amortized into interest cost over the life of the Senior Notes. We used the proceeds from the issuance of the Senior Notes to repay amounts outstanding under the Old Notes and under the Facility Agreement, as described below. In conjunction with the retirement of the Old Notes and the repayment of a substantial portion of the Facility Agreement, we recognized a loss on extinguishment of debt of $4.2 million.

At December 31, 2012, the fair value of the Senior Notes, based on quoted market prices, was approximately $513.8 million, compared to a carrying amount of $501.0 million.

Multicurrency Facility Agreement

On September 21, 2012, we entered into a Multicurrency Facility Agreement, which was amended on February 25, 2013, (the “Multicurrency Facility Agreement”) among us, as guarantor, one of our indirect wholly-owned subsidiaries, as borrower (the “Borrower”), and a group of financial institutions as lenders (the “Lenders”). The Multicurrency Facility Agreement has a scheduled maturity date of September 21, 2017 and commits the Lenders to provide loans up to an aggregate principal amount of $150.0 million at any one time outstanding, subject to certain terms and conditions. Loans under the Multicurrency Facility Agreement will accrue interest at LIBOR, plus an applicable margin based on our leverage ratio. In addition, the Multicurrency Facility Agreement provides for loans to be made in currencies other than U.S. Dollars with approval of the Lenders. We paid fees to the arrangers, the agent and the security trustee totaling $2.7 million which will be amortized into interest cost over the life of the Multicurrency Facility Agreement. The Multicurrency Facility Agreement is secured by certain vessels of the Borrower. We unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower arising under the Multicurrency Facility Agreement and other related loan documents. The Multicurrency Facility Agreement is subject to certain financial covenants. At December 31, 2012, we were in compliance with all the covenants under this agreement.

Norwegian Facility Agreement

We are in the final stages of negotiation of an agreement (the “Norwegian Facility Agreement”) among us, as guarantor, one of our indirect wholly-owned subsidiaries, as borrower (the “Norwegian Borrower”), and a Norwegian bank as lender (the “Lender”). The Norwegian Facility Agreement will have a scheduled maturity date of September 30, 2017 and will commit the Lenders to provide loans up to an aggregate principal amount of 600.0 million NOK (approximately $103.2 million) at any one time outstanding, subject to certain terms and conditions. Loans under the Norwegian Facility Agreement will accrue interest at LIBOR, plus an applicable margin based on our leverage ratio. The Norwegian Facility Agreement will be secured by certain vessels of the Norwegian Borrower. We will unconditionally guarantee all existing and future indebtedness and liabilities of the Norwegian Borrower arising under the Norwegian Facility Agreement and other related loan documents. The Norwegian Facility Agreement will be subject to certain financial covenants. There is no assurance that we will finalize negotiations or complete the Norwegian Facility Agreement.

Secured Reducing Revolving Loan Facility

Prior to September 21, 2012, we had a $175.0 million ($145.0 million borrowing capacity) Secured Reducing Revolving Loan Facility with a syndicate of financial institutions. The facility was to mature in 2013. Security for the facility was provided by first priority mortgages on certain vessels. The interest rate ranged from LIBOR plus a margin of 0.7% to 0.9% depending on our EBITDA coverage ratio. The Secured Reducing Revolving Loan Facility was subject to financial covenants. In connection with the finalization of the Multicurrency Facility Agreement, we terminated the Secured Reducing Revolving Credit Facility and recorded a $0.2 million loss on extinguishment of debt.

Facility Agreement

On December 17, 2009, one of our wholly owned subsidiaries (the “Americas Borrower”) entered into a $200.0 million facility agreement (as amended, the “Facility Agreement”) with The Royal Bank of Scotland plc (“RBS”). The Facility Agreement was to mature on December 31, 2012, with amounts borrowed repayable in quarterly installments of $8.3 million and a final installment of $108.3 million, but, on January 26, 2012, we entered into a financing agreement with RBS to amend the Facility Agreement primarily to extend the maturity to July 1, 2014 and to adjust principal payments. Under the amended agreement, we were not required to make principal payments until maturity. Loans under the Facility Agreement accrued interest at the three month LIBOR rate, plus a margin of 2.5% per annum. The Facility Agreement was secured by certain vessels and all of the shares of common stock of the Americas

Borrower were pledged to the agent, on behalf of the lender, as security for the Facility Agreement. In the first quarter of 2012, we incurred $1.4 million of cost associated with the amendment. This cost was capitalized in our balance sheet under deferred costs and other assets and was to be amortized into interest cost over the life of the Facility Agreement. The repayment in March 2012 of $100.0 million of the $140.0 million then outstanding under the Facility Agreement increased the amortization of the costs to expense.

We used a portion of the net proceeds from the March 2012 Senior Notes issuance to repay $100.0 million of the indebtedness outstanding related to the Facility Agreement. In connection with the additional December 2012 Senior Notes issuance, we used a portion of the proceeds to repay the remaining $40.0 million of indebtedness, and we terminated the Facility Agreement and recorded a $0.5 million loss on extinguishment of debt.

Senior Notes – Due 2014

On July 21, 2004, we issued $160.0 million aggregate principal amount of 7.75% senior notes (the “Old Notes”) due July 2014. On February 27, 2012, we commenced a tender offer to purchase all of our outstanding Old Notes. In conjunction with the tender offer, we solicited consents to eliminate most of the covenants, certain events of default applicable to the Old Notes and certain other provisions contained in the indenture governing the Old Notes. On March 12, 2012, we funded the tender offer with $80.3 million of the proceeds of the new Senior Notes. On April 2, 2012, we redeemed the remainder of the Old Notes with $79.7 million. At December 31, 2012, we had no amount outstanding under the Old Notes.

Stock Repurchases

On December 11, 2012, our Board of Directors approved a stock repurchase program for up to a total of $100.0 million of our issued and outstanding Class A common stock. The stock may be repurchased from time to time on the open market or in privately negotiated transactions. Repurchases can be made from time to time using a variety of methods, which may include open market purchases or purchases through a Rule 10b5-1 trading plan, all in accordance with Securities and Exchange Commission and other applicable legal requirements. The specific timing, price and size of purchases will be determined by our management based on prevailing stock prices, general economic and market conditions and other considerations. The repurchase program does not obligate us to acquire any particular amount of common stock and may be suspended or discontinued at any time.

The value of the common stock repurchased, along with number of shares repurchased, and average price paid per share for the three months ended December 31, 2012 are as follows:

Repurchase of Equity Securities


Period	Total Number of Common Shares Repurchased		Average Price Paid Per Common Share		Total Number of Common Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Common Shares that May Yet Be Purchased Under the Plans or Programs
October 1 - 31		—		—		—		—
November 1 - 30		—		—		—		—
December 1 - 31		35,400	$	33.93		—		—

During the period from January 1, 2013 through February 25, 2013, we repurchased 288,219 shares of common stock for an aggregate price of $10.3 million or an average price of $35.65 per share.

Dividends


	2012		2011
Dividends Declared (in thousands)	$	26,613		—
Dividend per share	$	1.00		—

Current Year Cash Flow

At December 31, 2012, we had cash on hand of $185.2 million. Cash provided by operating activities for the year ended December 31, 2012, was $102.7 million compared to $97.5 million in the previous year. The increase was primarily attributable to operating income and the proceeds from the issuance during 2012 of $500.0 million of Senior Notes, a portion of which was used to pay down existing debt.

Cash used in investing activities for the years ended December 31, 2012 and 2011 was $198.8 million and $49.4 million, respectively. In 2012, we spent approximately $192.3 million on asset purchases, primarily new construction. In 2011, we spent approximately $52.3 million. In 2012 and 2011, we sold assets for approximately $40.6 million and $2.9 million, respectively. The proceeds from these asset sales decreased the reported cash used in investing activities.

In 2012, we had $150.6 million provided by financing activities compared to $16.2 million used in financing activities in 2011. In 2012, we incurred $558.0 million in new long-term debt and repaid $364.6 million of debt. During 2011, we incurred $16.0 million of new long-term debt and repaid $35.0 million in debt.

Debt and Other Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2012, and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions):


	2013		2014		2015		2016		2017		Thereafter
Purchase Obligations for New-Build Program	$	227.8	$	38.3	$	9.6	$	—	$	—	$	—
Repayment of Long-Term Debt, Excluding Debt Premium of $1.0 million		—		—		—		—		—		500.0
Interest Payments		31.9		31.9		31.9		31.9		31.9		143.7
Non-Cancelable Operating Leases		2.0		2.3		1.8		1.1		0.9		8.9
Long-Term Income Taxes Payable		1.8		—		—		—		—		—
Other		1.0		0.8		0.7		—		—		6.1

Total	$	264.5	$	73.3	$	44.0	$	33.0	$	32.8	$	658.7

Due to the uncertainty with respect to the timing of future cash payments, if any, associated with our unrecognized tax benefits at December 31, 2012, we are unable to make reasonably reliable estimates of the period of cash settlements with the respective taxing authorities. Therefore, $22.4 million of unrecognized tax benefits have been excluded from the contractual obligations table above.

Other Commitments

We execute letters of credit, performance bonds and other guarantees in the normal course of business that ensure our performance or payments to third parties. The aggregate notional value of these instruments was $4.8 million and $4.4 million at December 31, 2012 and 2011, respectively. In the past, no significant claims have been made against these financial instruments. We believe the likelihood of demand for payment is minimal and expect no material cash outlays to occur from these instruments.

Currency Fluctuations and Inflation

A majority of our operations are international; therefore we are exposed to currency fluctuations and exchange rate risks. Charters for vessels in our North Sea fleet are primarily denominated in GBP, with a portion denominated in NOK or Euros. In areas where currency risks are potentially high, we normally accept only a small percentage of charter hire in local currency, with the remainder paid in U.S. Dollars. Operating costs are substantially denominated in the same currency as charter hire in order to reduce the risk of currency fluctuations. The North Sea fleet generated 42% of our total consolidated revenue for the year ended December 31, 2012. In 2012, the exchange rates of GBP, NOK, Euro, BRL, and SGD against the U.S. Dollar ranged as follows:


	High		Low		Year Average		As of February 25, 2013
$ 1 US=GBP		0.654		0.614		0.631		0.659
$ 1 US=NOK		6.131		5.560		5.814		5.700
$ 1 US=Euro		0.829		0.742		0.777		0.765
$ 1 US=BRL		2.137		1.698		1.945		1.982
$ 1 US=SGD		1.297		1.217		1.249		1.240

Our outstanding debt is denominated in U.S. Dollars, but a substantial portion of our revenue is generated in currencies other than the U.S. Dollar. We have evaluated these conditions and have determined that it is not in our interest to use any financial instruments to hedge this exposure under present conditions. Our strategy is in part based on a number of factors including the following:

•

the cost of using hedging instruments in relation to the risks of currency fluctuations;

•

the propensity for adjustments in these foreign currency denominated vessel day rates over time to compensate for changes in the purchasing power of these currencies as measured in U.S. Dollars;

•

the level of U.S. Dollar-denominated borrowings available to us; and

•

the conditions in our U.S. Dollar-generating regional markets.

One or more of these factors may change and, in response, we may begin to use financial instruments to hedge risks of currency fluctuations. We will from time to time hedge known liabilities denominated in foreign currencies to reduce the effects of exchange rate fluctuations on our financial results. We do not use foreign currency forward contracts for trading or speculative purposes.

Reflected in the accompanying consolidated balance sheet at December 31, 2012, is $59.9 million in accumulated other comprehensive income primarily relating to the higher exchange rates at December 31, 2012 in comparison to the exchange rate when we invested capital in these markets. Accumulated other comprehensive income related to the changes in foreign currency exchange rates was $32.5 million at December 31, 2011. Changes in the accumulated other comprehensive income are non-cash items that are primarily attributable to investments in vessels and U.S. Dollar-based capitalization between our parent company and our foreign subsidiaries. The current year activity reflects the changes in the U.S. Dollar compared to the functional currencies of our major operating subsidiaries, particularly in the U.K. and Norway.

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

New Accounting Pronouncements

Refer to Note 1 “Nature of Operations and Summary of Significant Accounting Policies–New Accounting Pronouncements” in our Notes to Consolidated Financial Statements included in Part II, Item 8.

Forward-Looking Statements

This Form 10-K, particularly this Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part I, Items 1 and 2 “Business and Properties” contain certain forward-looking statements and other statements that are not historical facts concerning, among other things, market conditions, the demand for marine supply and transportation services and future capital expenditures. Such statements are subject to certain risks, uncertainties and assumptions, including, without limitation, operational risk, catastrophic or adverse sea or weather conditions, dependence on the oil and natural gas industry, volatility in oil and gas prices, delay or cost overruns on construction projects or insolvency of the shipbuilders, lack of shipyard or equipment availability, ongoing capital expenditure requirements, uncertainties surrounding environmental and government regulation, risks relating to compliance with the Jones Act, risks relating to leverage, risks of foreign operations, risk of war, sabotage, piracy or terrorism, assumptions concerning competition, and risks of currency fluctuations and other matters. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to risks and uncertainties, including the risk factors discussed above and in Part I, Item 1A “Risk Factors”, general economic and business conditions, the business opportunities that may be presented to and pursued by us, changes in law or regulations and other factors, many of which are beyond our control. There can be no assurance that we have accurately identified and properly weighed all of the factors which affect market conditions and demand for our vessels, that the information upon which we have relied is accurate or complete, that our analysis of the market and demand for our vessels is correct or that the strategy based on such analysis will be successful. Important factors that could cause actual results to differ materially from our expectations are disclosed within Part I, Item 1A “Risk Factors”, this Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and Part I, Items 1 and 2 “Business and Properties” and elsewhere in this Form 10-K.

ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

Financial Instruments

We are subject to financial market risks, including fluctuations in foreign currency exchange rates and interest rates. In order to manage and mitigate our exposure to these risks, we may use derivative financial instruments in accordance with established policies and procedures. At December 31, 2012, our derivative holdings consist of an interest rate swap agreement. Refer to Note 1 “Nature of Operations and Summary of Significant Accounting Policies—Fair Value of Financial Instruments” in our Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information on financial instruments.

Foreign Currency Risk

The functional currency for the majority of our international operations is that operation’s local currency. Adjustments resulting from the translation of the local functional currency financial statements to the U.S. Dollar, which is based on current exchange rates, are included in the Consolidated Statements of Stockholders’ Equity as a separate component of “Accumulated Other Comprehensive Income (Loss)”. Working capital of our international operations may in part be held or denominated in a currency other than the local currency, and gains and losses resulting from holding those balances are included in the Consolidated Statements of Operations in “Other income (expense)” in the current period.

We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. Dollars, which exposes us to foreign currency exchange risk. At various times we may utilize forward exchange contracts, local currency borrowings and the payment structure of customer contracts to selectively hedge exposure to exchange rate fluctuations in connection with monetary assets, liabilities and cash flows denominated in certain foreign currency. Other information required under this Item 7A has been provided in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Currency Fluctuations and Inflation”. Other than trade accounts receivable and trade accounts payable, we do not currently have financial instruments that are sensitive to foreign currency exchange rates.

We transact business in various foreign currencies which subjects our cash flows and earnings to exposure related to changes in foreign currency exchange rates. We attempt to manage this exposure through operational strategies and not through the use of foreign currency forward exchange contracts. We do not engage in hedging activity for speculative or trading purposes.

From time to time, we may hedge firmly committed, anticipated transactions in the normal course of business and these contracts are designated and qualify as fair value hedges. Changes in the fair value of derivatives that are designated as fair value hedges are deferred in the Consolidated Statements of Stockholders’ Equity as a separate component of “Consolidated Statements of Comprehensive Income” until the underlying transactions occur. At such time, the related deferred hedging gains or losses are recorded on the same line as the hedged item.

Net foreign currency losses, including derivative activity, for the years ended December 31, 2012, 2011 and 2010 were $1.7 million, $3.3 million, and $0.1 million, respectively.

Interest Rates

We are and will be subject to market risk for changes in interest rates related primarily to our long-term debt. The following table, which presents principal cash flows by expected maturity dates and weighted average interest rates, summarizes our fixed and variable rate debt obligations at December 31, 2012 and 2011 that are sensitive to changes in interest rates. The floating portion of our variable debt is based on LIBOR.

We had a fixed-for-floating interest rate swap agreement that was entered into to fix the LIBOR interest rate component on $100.0 million of the outstanding balance on our Facility Agreement. The fixed rate component of the swap was set at 4.145% and was accounted for as a cash flow hedge. In conjunction with the issuance of the new Senior Notes in the first quarter of 2012 and the concurrent repayment of $100.0 million of our Facility Agreement debt, we de-designated hedge accounting for this swap. For the year ended December 31, 2012, $1.1 million related to this interest rate swap was reclassified from other comprehensive income to interest expense. We also reclassified an additional $1.8 million from accumulated other comprehensive income to interest expense as a result of de-designating hedge accounting during the first quarter of 2012. We recognized the fair value of our derivative swap as a Level 2 valuation. We determined the fair value of our interest rate swap based on the contractual fixed rate in the swap agreement and the forward curve of three month LIBOR supplied by our counterparty as of December 31, 2012. The swap matured on December 31, 2012.

The following table shows our debt principal obligation as of December 31, 2012 and 2011 and the interest rate exposure in subsequent years of the hedged and unhedged components of our debt.


December 31, 2012	2013			2014			2015			2016			2017			Thereafter
	(Dollar amounts in thousands)
Long-term Debt:
Fixed rate	$	500,000		$	500,000		$	500,000		$	500,000		$	500,000		$	500,000
Average interest rate		6.375	%		6.375	%		6.375	%		6.375	%		6.375	%		6.375	%

Variable rate-Multicurrency Facility Agreement	$	—		$	—		$	—		$	—		$	—		$	—
Average interest rate		0.00	%		0.00	%		0.00	%		0.00	%		0.00	%		—


December 31, 2011	2012			2013			2014			2015		2016		Thereafter
	(Dollar amounts in thousands)
Long-term Debt:
Fixed rate	$	160,000		$	160,000		$	160,000		$	—	$	—	$	—
Average interest rate		7.75	%		7.75	%		7.75	%		—		—		—

Variable rate-Facility Agreement	$	41,667		$	140,000		$	140,000		$	—	$	—	$	—
Average interest rate		3.17	%		3.05	%		3.21	%		—		—		—

Variable rate – Revolving Loan Facility	$	6,000		$	6,000		$	—		$	—	$	—	$	—
Average interest rate		1.47	%		1.35	%

Interest rate swap-Variable to Fixed	$	100,000		$	—		$	—		$	—			$	—
Average pay rate		4.15	%		—			—			—				—
Average receive rate		0.67	%		—			—			—				—

Our fixed rate 6.375 % Senior Notes outstanding at December 31, 2012, subject us to risks related to changes in the fair value of the debt and exposes us to potential gains or losses if we were to repay or refinance such debt. A 1% change in market interest rates would increase or decrease the fair value of our fixed rate debt by approximately $35.0 million.

The fair value of our 6.375% Senior Notes and our 7.75% Senior Notes as compared to the carrying value at December 31, 2012 and 2011, was as follows:


	December 31,
	2012				2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
6.375% Senior Notes due 2022	$	501.0	$	513.8	$	—	$	—
7.75% Senior Notes due 2014	$	—	$	—	$	159.8	$	161.2

ITEM 8.

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

GulfMark Offshore, Inc.:

We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), GulfMark Offshore, Inc. and its consolidated subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Houston, Texas

February 27, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of GulfMark Offshore, Inc. and its subsidiaries:

We have audited the accompanying consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows of GulfMark Offshore, Inc. and its subsidiaries for year ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of the operations and the cash flows of GulfMark Offshore, Inc. and its subsidiaries for the year ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

UHY LLP

Houston, Texas

February 24, 2011

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012			2011
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	185,175		$	128,817
Trade accounts receivable, net of allowance for doubtful accounts of $3,250 and $198, respectively		85,706			85,214
Other accounts receivable		8,506			6,314
Prepaid expenses and other current assets		25,186			21,197

Total current assets		304,573			241,542

Vessels, equipment, and other fixed assets at cost, net of accumulated depreciation of $389,469 and $329,299, respectively		1,136,360			1,143,441
Construction in progress		169,429			37,107
Goodwill		33,438			31,153
Intangibles, net of accumulated amortization of $12,975 and $10,030, respectively		21,624			24,569
Cash held in escrow		47,028			—
Deferred costs and other assets		33,222			21,987

Total assets	$	1,745,674		$	1,499,799

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	1,667
Accounts payable		29,089			14,475
Income and other taxes payable		6,262			5,568
Accrued personnel costs		23,656			23,059
Accrued interest expense		9,327			5,777
Fair value of derivative		—			3,530
Other accrued liabilities		11,402			8,565

Total current liabilities		79,736			62,641

Long-term debt		500,999			305,830
Long-term income taxes:
Deferred tax liabilities		105,867			105,131
Other income taxes payable		23,665			22,769
Other liabilities		7,525			6,568
Stockholders’ equity:
Preferred stock, no par value; 2,000 shares authorized; no shares issued		—			—
Class A Common stock, $0.01 par value; 60,000 shares authorized; 26,941 and 26,631 shares issued and 26,906 and 26,617 shares outstanding, respectively; Class B Common Stock $.01 par value; 60,000 shares authorized; no shares issued		266			262
Additional paid-in capital		389,881			379,673
Retained earnings		579,062			586,402
Accumulated other comprehensive income		59,875			31,105
Treasury stock, at cost		(11,533	)		(8,968	)
Deferred compensation		10,331			8,386

Total stockholders’ equity		1,027,882			996,860

Total liabilities and stockholders’ equity	$	1,745,674		$	1,499,799

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2012			2011			2010
	(In thousands, except per share amounts)
Revenue	$	389,205		$	381,870		$	359,766

Costs and expenses:
Direct operating expenses		198,187			182,585			170,638
Drydock expense		33,280			15,932			22,182
General and administrative expenses		54,600			45,495			44,029
Depreciation and amortization		59,722			59,586			56,959
Impairment charge		1,152			1,750			97,665
Gain on sale of assets		(8,741	)		(2,018	)		(5,095	)

Total costs and expenses		338,200			303,330			386,378

Operating income (loss)		51,005			78,540			(26,612	)

Other income (expense):
Interest expense		(23,244	)		(22,314	)		(21,693	)
Interest income		338			748			985
Loss on extinguishment of debt		(4,378	)		—			—
Foreign currency loss and other		(1,779	)		(2,346	)		(126	)

Total other expense		(29,063	)		(23,912	)		(20,834	)

Income (loss) before income taxes		21,942			54,628			(47,446	)
Income tax (provision) benefit		(2,669	)		(4,694	)		12,701

Net income (loss)	$	19,273		$	49,934		$	(34,745	)

Earnings (loss) per share:
Basic	$	0.73		$	1.92		$	(1.36	)
Diluted	$	0.73		$	1.91		$	(1.36	)
Weighted average shares outstanding:
Basic		26,208			25,828			25,519

Diluted		26,228			25,962			25,519

Cash dividends declared per common share	$	1.00		$	—		$	—

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Year Ended December 31,
	2012		2011			2010
	(In thousands)
Net income (loss)	$	19,273	$	49,934		$	(34,745	)
Comprehensive income:
Gain (loss) on cash flow hedge, net of tax ⁽¹⁾		1,364		1,954			(722	)
Foreign currency gain (loss)		27,406		(9,986	)		(14,146	)

Total comprehensive income (loss)	$	48,043	$	41,902		$	(49,613	)

(1)	Net of income tax expense of $1.9 million, $0.7 million and $0.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2012, 2011 and 2010

(In thousands)


	Common Stock at $0.01 Par Value		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (loss)			Treasury Stock						Deferred Compensation		Total Stockholders’ Equity
											Shares			Share Value
Balance at December 31, 2009	$	255	$	362,022	$	571,213		$	54,005			(209	)	$	(5,865	)	$	5,838	$	987,468
Net loss		—		—		(34,745	)		—			—			—			—		(34,745	)
Issuance of common stock		2		6,224		—			—			—			—			—		6,226
Exercise of stock options		2		1,836		—			—			—			—			—		1,838
Deferred compensation plan		—		136		—			—			(47	)		(1,363	)		1,265		38
Loss on cash flow hedge, net of tax		—		—		—			(722	)		—			—			—		(722	)
Translation adjustment		—		—		—			(14,146	)		—			—			—		(14,146	)

Balance at December 31, 2010		259		370,218		536,468			39,137			(256	)		(7,228	)		7,103		945,957
Net income		—		—		49,934			—			—			—			—		49,934
Issuance of common stock		2		6,751		—			—			—			—			—		6,753
Exercise of stock options		1		2,690		—			—			—			—			—		2,691
Deferred compensation plan		—		14		—			—			(39	)		(1,740	)		1,283		(443	)
Gain on cash flow hedge, net of tax		—		—		—			1,954			—			—			—		1,954
Translation adjustment		—		—		—			(9,986	)		—			—			—		(9,986	)

Balance at December 31, 2011		262		379,673		586,402			31,105			(295	)		(8,968	)		8,386		996,860
Net income		—		—		19,273			—			—			—			—		19,273
Issuance of common stock		2		7,781		—			—			—			—			—		7,783
Exercise of stock options		2		2,396		—			—			—			—			—		2,398
Deferred compensation plan		—		31		—			—			(37	)		(1,363	)		1,945		613
Stock repurchases		—		—		—			—			(35	)		(1,202	)		—		(1,202	)
Cash dividends declared		—		—		(26,613	)		—			—			—			—		(26,613	)
Gain on cash flow hedge, net of tax		—		—		—			1,364			—			—			—		1,364
Translation adjustment		—		—		—			27,406			—			—			—		27,406

Balance at December 31, 2012	$	266	$	389,881	$	579,062		$	59,875			(367	)	$	(11,533	)	$	10,331	$	1,027,882

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	19,273		$	49,934		$	(34,745	)
Adjustments to reconcile net income (loss) from operations to net cash provided by operating activities
Depreciation and amortization		59,722			59,586			56,959
Amortization of deferred financing costs		2,750			1,685			1,598
Amortization of stock-based compensation		7,037			6,159			5,670
Provision for doubtful accounts receivable, net of write offs		2,224			(84	)		(1	)
Deferred income tax benefit		(2,879	)		(232	)		(8,371	)
Gain on sale of assets		(8,741	)		(2,018	)		(5,095	)
Impairment charge		1,152			1,750			97,665
Loss on extinguishment of debt		2,104			—			—
Foreign currency transaction loss		821			3,051			1,195
Change in operating assets and liabilities —
Accounts receivable		(3,443	)		(15,983	)		3,287
Prepaids and other		(3,626	)		(1,236	)		(7,906	)
Accounts payable		14,051			(464	)		(4,118	)
Other accrued liabilities and other		12,291			(4,677	)		(14,564	)

Net cash provided by operating activities		102,736			97,471			91,574

Cash flows from investing activities:
Purchases of vessels, equipment and other fixed assets		(192,301	)		(52,258	)		(73,439	)
Deposits held in escrow		(52,390	)		—			—
Release of deposits held in escrow		5,362
Proceeds from disposition of vessels, equipment and other fixed assets		40,565			2,850			19,582

Net cash used in investing activities		(198,764	)		(49,408	)		(53,857	)

Cash flows from financing activities:
Proceeds from issuance of 6.375% senior notes		501,000			—			—
Repayment of 7.75% senior notes		(160,000	)		—			—
Repayment of secured credit facilities		(141,667	)		(25,000	)		(33,334	)
Borrowings under revolving loan facility, net		(5,995	)		6,000			—
Cash dividends		(26,352	)		—			—
Stock repurchases		(515	)		—			—
Debt issuance cost		(16,736	)		—			(2,000	)
Debt extinguishment cost		(2,274	)		—			—
Proceeds from exercise of stock options		2,398			2,131			1,838
Proceeds from issuance of stock		745			638			659

Net cash provided by (used in) financing activities		150,604			(16,231	)		(32,837	)

Effect of exchange rate changes on cash		1,782			(210	)		236

Net increase in cash and cash equivalents		56,358			31,622			5,116
Cash and cash equivalents at beginning of year		128,817			97,195			92,079

Cash and cash equivalents at end of year	$	185,175		$	128,817		$	97,195

Supplemental cash flow information:
Interest paid, net of interest capitalized	$	17,590		$	21,673		$	21,285

Income taxes paid, net	$	3,798		$	6,023		$	4,712

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

GulfMark Offshore, Inc. and its subsidiaries (collectively referred to as “we”, “us”, “our” or the “Company”) own and operate offshore supply vessels, principally in the North Sea, offshore Southeast Asia and offshore the Americas. The vessels provide transportation of materials, supplies and personnel to and from offshore platforms and drilling rigs. Some of these vessels also perform anchor handling and towing services.

On February 23, 2010, we reorganized the Company. The Reorganization was effected primarily to better position us to benefit from and adhere to U.S. maritime laws and regulations. See Reorganization in Note 10.

Principles of Consolidation

Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries. All significant inter-company accounts and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. The accompanying consolidated financial statements include significant estimates for allowance for doubtful accounts receivable, depreciable lives of vessels and equipment, valuation of goodwill, income taxes and commitments and contingencies. While we believe current estimates are reasonable and appropriate, actual results could differ from these estimates.

Cash and Cash Equivalents

Our investments, consisting of U.S. Government securities and commercial paper with original maturities of up to three months, are included in cash and cash equivalents in the accompanying consolidated balance sheets and consolidated statements of cash flows.

Vessels and Equipment

Vessels and equipment are stated at cost, net of accumulated depreciation, which is provided by the straight-line method over their estimated useful life of 25 years for all vessels other than crew boats which are depreciated over 20 years. Interest is capitalized in connection with the construction of vessels. The capitalized interest is included as part of the asset to which it relates and is depreciated over the asset’s estimated useful life. In 2012, 2011, and 2010, interest of $5.5 million, $0.4 million, and $1.4 million, respectively, was capitalized. Office equipment, furniture and fixtures, and vehicles are depreciated over two to five years.

Major renovation costs and modifications that extend the life or usefulness of the related assets are capitalized and depreciated over the assets’ estimated remaining useful lives. Maintenance and repair costs are expensed as incurred. Included in the consolidated statements of operations for 2012, 2011 and 2010, are $23.7 million, $21.9 million, and $20.6 million, respectively, of costs for maintenance and repairs.

Goodwill and Intangibles

At December 31, 2012, our goodwill consisted of $33.4 million related to acquisitions in the North Sea region. The determination of impairment of all long-lived assets, goodwill, and intangibles is conducted when indicators of impairment are present and at least annually for goodwill. Impairment testing for goodwill is performed on a reporting segment basis. In assessing goodwill for impairment, we analyze certain qualitative factors that affect the value, including goodwill of a segment. If those factors indicate that it is more likely than not that impairment of goodwill has occurred, we will proceed to step one of the goodwill impairment process.

In 2008, we acquired assets in the Americas region that included $97.7 million of goodwill. In the second quarter of 2010, we assessed our Americas region goodwill for impairment and, as a result, recorded a $97.7 million impairment charge, reflecting all of our Americas region goodwill. See Note 2 for a discussion of the goodwill impairment charge.

Impairment of Long-Lived Assets

We review long-lived assets for impairment whenever there is evidence that the carrying amount of such assets may not be recoverable. This consists of comparing the carrying amount of the asset with its expected future undiscounted cash flows before tax and interest costs. If the asset’s carrying amount is less than such cash flow estimate, it is written down to its fair value on a discounted cash flow basis. Estimates of expected future cash flows represent management’s best estimate based on currently available information and reasonable and supportable assumptions. Any impairment recognized is permanent and may not be restored.

Fair Value of Financial Instruments

As of December 31, 2012 and 2011, our financial instruments consist primarily of accounts receivable and payable (which are stated at carrying value which approximates fair value), long-term debt and an interest rate swap for a portion of the Facility Agreement.

On February 27, 2012, we announced our intent to issue the Senior Notes with a fixed interest rate, the proceeds of which would be used to pay down amounts outstanding under our Old Notes and our Facility Agreement. As a result we no longer had forecasted interest payments that qualify for hedge accounting. When a cash flow hedge ceases to qualify for hedge accounting, any amounts remaining in accumulated other comprehensive income are released and charged or credited to the underlying expense, in this case interest expense. At September 30, 2012, we had paid down $100.0 million of the $140.0 million outstanding under our Facility Agreement with proceeds from the Senior Notes. We allocated a proportionate amount of the accumulated change in the fair value of the interest rate swaps recorded in accumulated other comprehensive income to the remaining $40.0 million of Facility Agreement debt. This balance was amortized to interest expense over the remaining life of the interest rate swap which matured December 31, 2012. We determined that, based upon current market conditions and other factors, liquidation of the interest rate swap was not economically beneficial prior to its scheduled maturity. Accordingly, we elected to retain and hold the interest rate swap to maturity. Since it no longer qualified as a cash flow hedge, it was considered a derivative with no hedging designation. Changes in fair value of the swap were included in earnings in the period of the change. For the year ended December 31, 2012, insignificant losses were recorded related to this derivative.

In addition, when we terminated the interest rate swaps associated with our previous senior indebtedness, there was a $4.3 million balance remaining in other comprehensive income representing expected future interest payments. Of this amount, $2.4 million was amortized to interest expense in 2010, $1.3 million was amortized to interest expense in 2011 and the remaining $0.6 million was amortized into interest expense in 2012.

Deferred Costs and Other Assets

Deferred costs and other assets consist primarily of deferred financing costs and deferred vessel mobilization costs. Deferred financing costs are amortized over the expected term of the related debt. Should the debt for which a deferred financing cost has been recorded terminate by means of payment in full, tender offer or lender termination, the associated deferred financing costs would be immediately expensed.

In connection with new long-term contracts, costs incurred that directly relate to mobilization of a vessel from one region to another are deferred and recognized over the primary contract term. Should either party terminate the contract prior to the end of the original contract term, the deferred amount would be immediately expensed. Costs of relocating vessels from one region to another without a contract are expensed as incurred.

Revenue Recognition

Revenue from charters for offshore marine services is recognized as performed based on contractual charter rates and when collectability is reasonably assured. Currently, charter terms range from as short as several days to as long as 10 years in duration. Management services revenue is recognized in the period in which the services are performed.

Income Taxes

We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates and laws in effect in the years in which the differences are expected to reverse. The likelihood and amount of future taxable income and tax planning strategies are included in the criteria used to determine the timing and amount of tax benefits recognized for net operating loss and tax credit carryforwards in our consolidated financial statements.

In addition, we also account for uncertainty in income taxes by determining a more likely than not, or greater than 50% probability, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and /or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate.

Foreign Currency Translation

The local currencies of the majority of our foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operations. Assets and liabilities of our foreign affiliates are translated at year-end exchange rates, while revenue and expenses are translated at average rates for the period. As a result, amounts related to changes in assets and liabilities reported in the consolidated statements of cash flows will not necessarily agree to changes in the corresponding balances on the consolidated balance sheets. We consider most intercompany loans to be long-term investments; accordingly, the related translation gains and losses are reported as a component of stockholders’ equity. Transaction gains and losses are reported directly in the consolidated statements of operations. During the years ended December 31, 2012, 2011 and 2010, we reported net foreign currency losses in the amounts of $1.7 million, $3.3 million and $0.1 million, respectively.

Concentration of Credit Risk

We extend credit to various companies in the energy industry that may be affected by changes in economic or other external conditions. Our policy is to manage our exposure to credit risk through credit approvals and limits. Our trade accounts receivable are aged based on contractual payment terms and an allowance for doubtful accounts is established in accordance with our written corporate policy. The age of the trade accounts receivable, customer collection history and management’s judgment as to the customer’s ability to pay are considered in determining whether an allowance is necessary. Historically, write-offs for doubtful accounts have been insignificant however, in 2012, the amount increased significantly due to a customer that declared bankruptcy. For the year ended December 31, 2012, we had revenue from two customers in our Americas region who each accounted for 10% or more of total consolidated revenue, totaling $44.4 million and $42.0 million, or 22.4% of total consolidated revenue. For the year ended December 31, 2011, we had revenue from one customer in our Americas region totaling $57.0 million or 14.9% of our total consolidated revenue. In 2010, no single customer accounted for 10% or more of total consolidated revenue.

Stock-Based Compensation

We have share-based compensation plans covering officers and other employees as well as our Board of Directors. Stock-based grants made under our stock plans are recorded at fair value on the date of the grant and the cost is recognized ratably over the vesting period of the restricted stock. Our stock-based compensation plans are more fully described in Note 8.

Our employee stock purchase plan would be considered compensatory whereby it allows all of our U.S. employees and participating subsidiaries to acquire shares of common stock at 85% of the fair market value of the common stock under a qualified plan as defined by Section 423 of the Internal Revenue Code. The plan has a look-back option that establishes the purchase price as an amount based on the lesser of the common stock’s market price at the grant date or its market price at the exercise date. The total value of the look-back option imbedded in the plan is calculated using the component approach where each award is computed as the sum of 15% of a share of non-vested stock, a call option on 85% of a share of non-vested stock, and a put option on 15% of a share of non-vested stock.

Earnings Per Share

Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the year. Diluted EPS is computed using the treasury stock method for common stock equivalents. The detail of the earnings per share calculations for continuing operations for the years ended December 31, 2012, 2011 and 2010 is as follows (in thousands, except per share amounts):


	Year ended December 31,
	2012			2011			2010
Income (loss):
Net income (loss) attributable to common stockholders	$	19,273		$	49,934		$	(34,745	)
Undistributed income allocated to participating securities		(42	)		(470	)		—

Basic		19,231			49,464			(34,745	)

Undistributed income allocated to participating securities		—			470			—
Undistributed income reallocated to participating securities		—			(468	)		—

Diluted	$	19,231		$	49,466		$	(34,745	)

Shares:
Basic
Weighted-average common shares outstanding		26,208			25,828			25,519
Dilutive effect of stock options and restricted stock awards		20			134			—

Diluted		26,228			25,962			25,519

Income (loss) per common share:
Basic	$	0.73		$	1.92		$	(1.36	)
Diluted	$	0.73		$	1.91		$	(1.36	)

Reclassifications

Certain reclassifications of previously reported information have been made to conform to the current year presentation.

New Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities”. Offsetting, otherwise known as netting, is the presentation of assets and liabilities as a single net amount in the statement of financial position (balance sheet). U.S. GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. The amendments to the FASB Accounting Standards Codification in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of ASU 2011-11 will not have a material impact on our consolidated financial statements.

In July 2012, the FASB issued ASU No. 2012-02, “Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment”. In accordance with the amendments in this update, an entity has the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Subtopic 350-30. An entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The adoption of ASU 2012-02 will not have a material impact on our consolidated financial statements.

In October 2012, the FASB issued ASU No. 2012-04, “Technical Corrections and Improvements”. The amendments in this update represent changes to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification that are not expected to have a significant effect on current accounting practice or create a significant administrative cost to most entities. Additionally, the amendments will make the codification easier to understand and the fair value measurement guidance easier to apply by eliminating inconsistencies and providing needed clarifications. The amendments in this update that will not have transition guidance will be effective upon issuance for both public entities and nonpublic entities. For public entities, the amendments that are subject to the transition guidance will be effective for fiscal periods beginning after December 15, 2012. The adoption of ASU 2012-04 will not have a material impact on our consolidated financial statements.

(2) IMPAIRMENT CHARGES

Asset Held for Sale

Goodwill

In 2008, we acquired assets in the Americas region that included $97.7 million in goodwill. In the second quarter of 2010, we assessed our Americas region goodwill for impairment. In our assessment, we evaluated the impact on the segment’s fair value due to the April 2010 catastrophic fire and explosion that sank a deepwater drilling rig in the U.S. Gulf Of Mexico, and the resulting oil spill and drilling moratorium. Based on these events, which were incorporated into our evaluations and testing as prescribed under U.S. GAAP, we determined that an impairment of our Americas region goodwill existed. As a result, we recorded a $97.7 million impairment charge as of June 30, 2010, reflecting all of our Americas region goodwill. The non-cash charge did not impact our liquidity or debt covenant compliance. The impairment charge was based on fair value measurements classified as Level 3 of the valuation hierarchy.

(3) VESSEL ACQUISITIONS, DISPOSITIONS AND NEW-BUILD PROGRAM

In the third quarter of 2011, our Board of Directors approved the initiation of a new-build construction program. We began the program in the North Sea region where we contracted with three shipyards to build a total of six platform supply vessels (“PSVs”). The estimated total cost of these initial six vessels is $228.0 million. In late 2011, we exercised an option with one of the shipyards to build an additional vessel at an estimated cost of $60.0 million. The first of these vessels is scheduled to be delivered in the second quarter of 2013 and the last is scheduled to be delivered in the first quarter of 2014.

During the third quarter of 2012, we placed $52.4 million in escrow related to the two Thoma-Sea new-builds (U.S. flagged PSVs) described in the table below. Progress payments will be drawn from escrow as they become due. The amount held in escrow is segregated from cash and cash equivalents and is presented in long-term assets on our December 31, 2012 balance sheet. As of December 31, 2012, the total amount held in escrow was $47.0 million. Funds in the escrow account are invested in government securities.

In 2010, we sold one of our Americas vessels and one of our North Sea vessels and recorded a combined $5.1 million gain. In 2011, we sold one of our North Sea vessels and recorded a $2.0 million gain. During 2012, we sold four crew boats and one fast supply vessel that had operated in our Americas region for an aggregate gain of $8.7 million. During 2012, we purchased a vessel for operation in the Americas region for a total price of $22.5 million and a vessel for operation in our North Sea region for a total price of $28.6 million.

The following tables illustrate the details of the vessels under construction, the vessels acquired, the vessels disposed of and the vessels classified as held for sale as indicated at December 31, 2012:


Vessels Under Construction at December 31, 2012
Construction Yard	Region		Type⁽¹⁾		Expected		Length		BHP⁽²⁾		DWT⁽³⁾		Expected
Construction Yard	Region		Type⁽¹⁾		Delivery		(feet)		BHP⁽²⁾		DWT⁽³⁾		Cost
													(in millions)
Remontowa		North Sea		LgPSV		Q2 2013		292		9,574		5,100	$	37.0
Remontowa		North Sea		LgPSV		Q3 2013		292		9,574		5,100		37.0
Remontowa		North Sea		LgPSV		Q3 2013		261		9,574		4,000		34.0
Rosetti Marino		North Sea		LgPSV		Q4 2013		246		8,457		3,000		31.0
Rosetti Marino		North Sea		LgPSV		Q1 2014		246		8,457		3,000		31.0
Simek		North Sea		LgPSV		Q2 2013		304		11,935		4,700		58.0
Simek		North Sea		LgPSV		Q4 2013		304		11,935		4,700		60.0
Thoma-Sea		Americas		LgPSV		Q3 2013		271		9,990		3,600		36.0
Thoma-Sea		Americas		LgPSV		Q4 2013		271		9,990		3,600		36.0
BAE Systems		Americas		LgPSV		Q3 2014		288		10,960		5,300		48.0
BAE Systems		Americas		LgPSV		Q1 2015		288		10,960		5,300		48.0

Note: Final cost may differ due to foreign currency fluctuations.

Vessels Acquired Since December 31, 2011

Vessel

Region

Type⁽¹⁾

Year

Length

BHP⁽²⁾

DWT⁽³⁾

Cost

Built

(feet)

(in millions)

Thomas Wainwright

Americas

LgPSV

2010

242

5,472

2,700

22.5

F.D. Invincible

North Sea

LgPSV

2006

236

5,450

3,200

28.6

Vessels Disposed of Since December 31, 2011

Vessel

Region

Type⁽¹⁾

Year

Length

BHP⁽²⁾

DWT⁽³⁾

Month

Built

(feet)

Disposed

Bluefin

Americas

Crew

2008

165

7,200

337

Jan-12

Sailfish

Americas

Crew

2007

176

7,200

307

May-12

Swordfish

Americas

Crew

2009

176

7,200

307

May-12

Albacore

Americas

Crew

2008

165

7,200

337

Jul-12

Blacktip

Americas

FSV

2009

181

7,200

543

Aug-12

Vessels Held for Sale (Laid Up)

Vessel

Region

Type⁽¹⁾

Year

Length

BHP⁽²⁾

DWT⁽³⁾

Built

(feet)

Clwyd Supporter

N. Sea

SpV

1984

266

10,700

1,350

Note: This vessel was sold in January 2013.

⁽¹⁾

LgPSV - Large Platform Supply Vessel

PSV

- Platform Supply Vessel

FSV

- Fast Vessel Supply

SpV

- Specialty Vessel

Crew

- Crewboat

⁽²⁾

BHP - Brake Horsepower

⁽³⁾

DWT - Deadweight Tons

(4) GOODWILL AND INTANGIBLES

Changes to goodwill are as follows:


	2012		2011			2010
	(In thousands)
Balance, January 1,	$	31,153	$	31,987		$	129,849
Adjustment related to acquisition		—		—			—
Impact of foreign currency translation and adjusment		2,285		(834	)		(197	)
Impairment (see Note 2)		—		—			(97,665	)

Balance, December 31,	$	33,438	$	31,153		$	31,987

Intangible assets of $21.6 million, net of accumulated amortization of $13.0 million, as of December 31, 2012 are recorded at cost and are amortized on a straight-line basis over the years expected to be benefited, currently estimated to be 12 years. Amortization expense related to intangible assets was $2.9 million for each of the years ended December 31, 2012, 2011 and 2010. Annual amortization expense related to existing intangible assets for years 2013 through 2017 is expected to be $2.9 million per year.

(5) LONG-TERM DEBT

Our long-term debt at December 31, 2012 and 2011 consisted of the following:


	2012		2011
	(In thousands)
Senior Notes Due 2022	$	500,000	$	—
Multicurrency Facility Agreement		—		—
Facility Agreement		—		141,667
Senior Notes Due 2014		—		160,000
Secured Reducing Revolving Loan Facility		—		6,000

		500,000		307,667

Less: Current maturities of long-term debt		—		(1,667	)
Debt premium (discount), net		999		(170	)

Total	$	500,999	$	305,830

The following is a summary of scheduled debt maturities by year:


Year	Debt Maturity
	(In thousands)
2013	$	—
2014		—
2015		—
2016		—
2017		—
Thereafter		500,000

Total	$	500,000

Senior Notes – Due 2022

On March 12, 2012, we issued $300.0 million aggregate principal amount of 6.375% senior notes due 2022. On December 5, 2012, we issued an additional $200.0 million of senior notes with substantially the same terms as the previous $300.0 million issuance (together with the original issue, the “Senior Notes”). The Senior Notes pay interest semi-annually on March 15 and September 15, commencing September 15, 2012 for the March 12, 2012 Senior Notes, and commencing March 15, 2013 for the December 5, 2012 Senior Notes. Prior to March 15, 2017, we may redeem some or all of the Senior Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The make-whole premium is based on U.S. treasuries plus 50 basis points. On and after March 15, 2017, we may redeem some or all of the Senior Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.188% for the twelve-month period beginning March 15, 2017, 102.125% for the twelve-month period beginning March 15, 2018, 101.063% for the twelve-month period

beginning March 15, 2019 and 100.000% beginning March 15, 2020, plus accrued and unpaid interest to the redemption date. In conjunction with the Senior Note offering, we incurred $12.7 million in debt issuance cost which is included in our balance sheet under deferred costs and other assets and will be amortized into interest cost over the life of the Senior Notes. We used the proceeds from the issuance of the Senior Notes to repay amounts outstanding under the Old Notes and under the Facility Agreement, as described below. In conjunction with the retirement of the Old Notes and the repayment of a substantial portion of the Facility Agreement, we recognized a loss on extinguishment of debt of $4.2 million.

At December 31, 2012, the fair value of the Senior Notes, based on quoted market prices, was approximately $513.8 million, compared to a carrying amount of $501.0 million.

Multicurrency Facility Agreement

The Multicurrency Facility Agreement is secured by certain vessels of the Borrower. The collateral that secures the loans under the Multicurrency Facility Agreement may also secure all of the Borrower’s obligations under any hedging agreements between the Borrower and any Lender or other hedge counterparty party to the Multicurrency Facility Agreement.

We unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower arising under the Multicurrency Facility Agreement and other related loan documents. Such guarantee may also cover obligations of the Borrower arising under any hedging arrangements described above. The Multicurrency Facility Agreement is subject to certain financial covenants. At December 31, 2012, we were in compliance with all the covenants under this agreement.

Norwegian Facility Agreement

We are in the final stages of negotiating an agreement (the “Norwegian Facility Agreement”) among us, as guarantor, one of our indirect wholly-owned subsidiaries, as borrower (the “Norwegian Borrower”), and a Norwegian bank as lender (the “Lender”). The Norwegian Facility Agreement will have a scheduled maturity date of September 30, 2017 and will commit the Lenders to provide loans up to an aggregate principal amount of 600.0 million NOK (approximately $103.2 million) at any one time outstanding, subject to certain terms and conditions. Loans under the Norwegian Facility Agreement will accrue interest at LIBOR, plus an applicable margin based on our leverage ratio.

The Norwegian Facility Agreement will be secured by certain vessels of the Norwegian Borrower. The collateral that secures the loans under the Norwegian Facility Agreement may also secure all of the Norwegian Borrower’s obligations under any hedging agreements between the Norwegian Borrower and any Lender or other hedge counterparty party to the Norwegian Facility Agreement.

We will unconditionally guarantee all existing and future indebtedness and liabilities of the Norwegian Borrower arising under the Norwegian Facility Agreement and other related loan documents. Such guarantee may also cover obligations of the Norwegian Borrower arising under any hedging arrangements described above. The Norwegian Facility Agreement will be subject to certain financial covenants.

There is no assurance that we will finalize negotiations or complete the Norwegian Facility Agreement.

Secured Reducing Revolving Loan Facility

Prior to September 21, 2012, we had a $175.0 million ($145.0 million borrowing capacity) Secured Reducing Revolving Loan Facility with a syndicate of financial institutions. The facility was to mature in 2013 and the maximum availability reduced in increments of $15.0 million every six months beginning in December 2011, with a final reduction of $130.0 million in June 2013. Security for the facility was provided by first priority mortgages on certain vessels. The interest rate ranged from LIBOR plus a margin of 0.7% to 0.9% depending on our EBITDA coverage ratio. The Secured Reducing Revolving Loan Facility was subject to financial covenants. In connection with the finalization of the Multicurrency Facility Agreement, we terminated the Secured Reducing Revolving Credit Facility and recorded a $0.2 million loss on extinguishment of debt.

Facility Agreement

On December 17, 2009, one of wholly owned subsidiaries (the “Americas Borrower”) entered into a $200.0 million facility agreement (as amended, the “Facility Agreement”) with The Royal Bank of Scotland plc (“RBS”). The Facility Agreement was to mature on December 31, 2012, with amounts borrowed repayable in quarterly installments of $8.3 million and a final installment of $108.3 million, but, on January 26, 2012, we entered into a financing agreement with RBS to amend the Facility Agreement primarily to extend the maturity to July 1, 2014 and to adjust principal payments. Under the amended agreement, we were not required to make principal payments until maturity. Loans under the Facility Agreement accrued interest at the three month LIBOR rate, plus a margin of 2.5% per annum. The Facility Agreement was secured by certain vessels and all of the shares of common stock of the Americas Borrower were pledged to the agent, on behalf of the lender, as security for the Facility Agreement. In the first quarter of 2012, we incurred $1.4 million of cost associated with the amendment. This cost was capitalized in our balance sheet under deferred costs and other assets and was to be amortized into interest cost over the life of the Facility Agreement. The repayment in March 2012 of $100.0 million of the $140.0 million then outstanding under the Facility Agreement increased the amortization of the costs to expense.

Senior Notes – Due 2014

(6) INCOME TAXES

The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under ten year “tonnage tax” regimes. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These foreign tax beneficial structures continued to result in our earnings incurring significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions.

In February 2010, the Norway Supreme Court ruled 2007 tonnage tax legislation to be unconstitutional retroactive taxation and we reversed our existing tonnage tax liability and received a refund of pre-2007 tonnage taxes that had been paid in 2008 and 2009, which resulted in our recording an approximately $15.0 million tax benefit in our 2010 tax provision. In June 2010, Norway’s Minister of Finance published revised rules for the taxation of pre-2007 tonnage tax profits permitting a qualified tonnage tax company to elect one of two systems, or methods, to determine and pay tax on its untaxed shipping profits as of December 31, 2006. We decided to elect the simplified tax system, which, beginning in 2011 required three equal annual installment payments of the tax that is calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits. Under this system, we recorded a $4.9 million tax provision. The net result of the 2010 Norwegian tonnage tax law changes was a $10.1 million tax benefit recorded in our 2010 tax provision. Our final liability to settle under the simplified tax system is included in our December 31, 2012 balance sheet as $1.8 million current income tax payable.

Our overall effective tax rate is substantially lower than the U.S. federal statutory income tax rate because our Southeast Asia and North Sea operations are tonnage tax qualified shipping activities that are taxed at relatively low rates or that are otherwise tax exempt. Should our operational structure change or should the laws that created these shipping tax regimes change, we could be required to provide for taxes at rates much higher than those currently reflected in our financial statements. Additionally, if our pre-tax earnings in higher tax jurisdictions increase, there could be a significant increase in our annual effective tax rate. Any such increase could cause volatility in the comparisons of our effective tax rate from period to period.

for the valuation allowance. This information is based on estimates and assumptions including projected taxable income. If these estimates and related assumptions change in the future, or if we determine that we would not be able to realize other deferred tax assets in the future, an adjustment to the valuation allowance would be recorded in the period such determination was made.

Income (loss) before income taxes attributable to domestic and foreign operations was (in thousands):


	Year Ended December 31,
	2012			2011			2010
U.S.	$	(24,006	)	$	(33,742	)	$	(121,938	)
Foreign		45,948			88,370			74,492

	$	21,942		$	54,628		$	(47,446	)

The components of our tax provision (benefit) attributable to income before income taxes are as follows for the year ended December 31, (in thousands):


	2012										2011										2010
	Current		Deferred			Other (a)		Total			Current		Deferred			Other (a)		Total			Current		Deferred			Other (a)			Total
U.S.	$	19	$	(1,761	)	$	—	$	(1,742	)	$	65	$	(2,989	)	$	—	$	(2,924	)	$	65	$	(7,519	)	$	—		$	(7,454	)
Foreign		3,546		(1,118	)		1,983		4,411			1,439		2,757			3,422		7,618			3,576		(852	)		(7,972	)		(5,247	)

	$	3,565	$	(2,879	)	$	1,983	$	2,669		$	1,504	$	(232	)	$	3,422	$	4,694		$	3,641	$	(8,371	)	$	(7,972	)	$	(12,701	)

(a)	Income tax effects determined under a more likely than not, or greater than 50% probability, threshold.

The mix of our operations within various taxing jurisdictions affects our overall tax provision. The difference between the provision at the statutory U.S. federal tax rate and the tax provision attributable to income before income taxes in the accompanying consolidated statements of operations is as follows:


	2012			2011			2010
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Effect of foreign operations		(49.0	)		(26.7	)		66.0
US state income taxes		3.9			0.5			(0.7	)
Valuation allowance		20.8			1.9			—
Impairment		—			—			(72.0	)
Other		1.5			(2.1	)		(1.5	)

Total		12.2	%		8.6	%		26.8	%

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. The components of the net deferred tax assets and liabilities at December 31, 2012 and 2011 are as follows:


	December 31,
	2012			2011
	(In thousands)
Deferred tax assets
Net operating loss carryforwards	$	35,544		$	42,997
Items currently not deductible for tax purposes		32,368			27,730
Foreign and other tax credit carryforwards		13,772			10,338

		81,684			81,065
Less valuation allowance		(12,191	)		(5,867	)

Net deferred tax assets	$	69,493		$	75,198

Deferred tax liabilities
Depreciation	$	(150,496	)	$	(148,697	)
Other		(21,237	)		(30,242	)

Total deferred tax liabilities	$	(171,733	)	$	(178,939	)

Net deferred tax liability	$	(102,240	)	$	(103,741	)

The net change in the total valuation allowance for the years ended December 31, 2012 and 2011 was an increase of $6.3 million and $1.4 million, respectively. As of December 31, 2012, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $106.9 million in the U.S., $18.0 million in Brazil, $5.0 million in Norway, and $0.8 million in Mexico that are, subject to certain limitations, available to offset future taxable income. The U.S. NOLs, which we expect to fully utilize, will begin to expire beginning in 2027 and beyond, and the NOLs in Mexico will begin to expire in 2016. It is more likely than not that the Mexican and Norway NOLs will not be utilized and a full valuation allowance has been established for these NOLs. Except for the amounts related to Brazilian temporary differences, it is also more likely than not that the Brazilian NOLs will not be utilized and a $5.2 million valuation allowance has been established for such NOLs. Based on future expected U.S. taxable income, in 2012 we recorded $4.6 million of valuation allowance against U.S. foreign tax credits.

Net income tax assets and liabilities based on classification as current, or short-term, and long-term are included in our balance sheet as follows (in thousands):


	December 31,
	2012		2011
	(In thousands)
Prepaid expenses and other current assets	$	5,038	$	3,708
Deferred costs and other assets		1,460		1,155

Total tax assets		6,498		4,863

Income taxes and other taxes payable	$	6,261	$	5,568
Other accrued liabilities		212		1,112
Deferred tax liabilities		105,867		105,130
Other income taxes payable		23,665		22,769

Total tax liabilities	$	136,005	$	134,579

Currently, our intention is to permanently reinvest the unremitted earnings of our non-U.S. subsidiaries. As a result, we have not provided for U.S. deferred taxes on the cumulative unremitted earnings of $879.2 million at December 31, 2012. In addition, as of December 31, 2012, we had approximately $73.9 million of cash held by our foreign subsidiaries which is subject to U.S. tax upon repatriation.

Based on a more likely than not, or greater than 50% probability, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return, we evaluate and record in certain circumstances an income tax asset / liability for uncertain income tax positions. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and/or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate. We also consider existing accounting guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. Accordingly, we continue to recognize income tax related penalties and interest in our provision for

income taxes and, to the extent applicable, in the corresponding balance sheet presentations for accrued income tax assets and liabilities, including any amounts for uncertain tax positions included in other income taxes payable in the consolidated balance sheets and which total $22.4 million at December 31, 2012 and $19.9 million at December 31, 2011.

A reconciliation of the beginning and ending balances of the total amounts of gross unrecognized tax benefits is as follows:


	2012			2011
	(in thousands)
Unrecognized tax benefits balance at January 1,	$	10,735		$	10,636
Gross increases for tax positions taken in prior years		1,125			695
Gross decreases for tax positions taken in prior years		(458	)		(596	)
Decreases for settlements		(846	)		—

Unrecognized tax benefits balance at December 31,	$	10,556		$	10,735

As of December 31, 2012, we are under tax examination, or may be subject to examination in the U. S. for years after 2002 and in seven major foreign tax jurisdictions with open years from 2000 to 2011.

We accrue interest and penalties related to unrecognized tax benefits in our provision for income taxes. At December 31, 2012, we had accrued interest and penalties related to unrecognized tax benefits of $14.6 million. The amount of interest and penalties recognized in our tax provision for the year ended December 31, 2012 was $1.6 million.

(7) COMMITMENTS AND CONTINGENCIES

At December 31, 2012, we had long-term operating leases for office space, automobiles, temporary residences, and office equipment. Aggregate operating lease expense for the years ended December 31, 2012, 2011 and 2010 was $2.4 million, $2.3 million, and $2.2 million, respectively. Future minimum rental commitments under these leases are as follows (in thousands):


Year	Minimum Rental Commitments
2013	$	1,970
2014		2,285
2015		1,822
2016		1,086
2017		891
Thereafter		8,910

Total	$	16,964

The Austral Abrolhos is subject to an annual right of its charterer to purchase the vessel during the term of the charter, which commenced May 2, 2003 and, subject to the charterer’s right to extend, terminates April 29, 2016, at a purchase price in the first year of $26.8 million declining to an adjusted purchase price of $12.9 million in the thirteenth year.

The Highland Rover is subject to a purchase option on the part of the charterer, pursuant to terms of an amendment to the original charter which was executed in late 2007 and amended in 2008. The charterer may purchase the vessel based on a stipulated formula on each of April 1, 2015, and October 1, 2016, provided 120 days notice has been given by the charterer.

We execute letters of credit, performance bonds and other guarantees in the normal course of business that ensure our performance or payments to third parties. The aggregate notional value of these instruments was $4.8 million and $4.4 million at December 31, 2012 and 2011, respectively. In the past, no significant claims have been made against these financial instruments. We believe the likelihood of demand for payment under these instruments is remote and expect no material cash outlays to occur from these instruments.

uncertainties surrounding our estimates of contingent liabilities and future claims, our future reported financial results will be impacted by the difference, if any, between our estimates and the actual amounts paid to settle the liabilities. In addition to estimates related to litigation and tax liabilities, other examples of liabilities requiring estimates of future exposure include contingencies arising out of acquisitions and divestitures. Our contingent liabilities are based on the most recent information available to us regarding the nature of the exposure. Such exposures change from period to period based upon updated relevant facts and circumstances, which can cause the estimate to change. In the recent past, our estimates for contingent liabilities have been sufficient to cover the actual amount of our exposure. We do not believe that the outcome of these matters will have a material adverse effect on our business, financial condition, or results of operations.

We have recently been made aware that a Brazilian state in which we have operated vessels has asserted that certain companies could be assessed for state import taxes with respect to vessels that have operated within Brazilian coastal waters. We have neither been formally assessed nor threatened with this tax. No accrual has been recorded as of December 31, 2012 for any liabilities associated with a possible future assessment. We can’t predict whether any such tax assessment may be made in the future.

(8) EQUITY INCENTIVE PLANS

Stock Options, Restricted Stock and Stock Option Plans

Under the terms of our Amended and Restated 1993 Non-Employee Director Stock Option Plan, or 1993 Director Plan, options to purchase 20,000 shares of our common stock were granted to each of our five non-employee directors in 1993, 1996, 1999 and 2002, and to a newly appointed director in 2001 and 2003. The exercise price of options granted under the 1993 Director Plan is fixed at the market price at the date of grant. A total of 800,000 shares were reserved for issuance under the 1993 Director Plan. The options have a term of ten years. On April 21, 2006, the 1993 Director Plan was terminated and, therefore, no additional shares were reserved for granting of options under this plan, although options remain outstanding under this plan.

In May 1998, the stockholders approved the GulfMark Offshore, Inc. 1997 Incentive Equity Plan that replaced the 1987 Employee Plan. A total of 814,000 shares were reserved for issuance of options or awards of restricted stock under this plan. Stock options generally become exercisable in 1/3 increments over a three-year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. During the restricted period, the recipient has the right to vote on the restricted shares and receive dividends on the unvested restricted shares. Under the terms of the 2010 Omnibus Equity Incentive Plan (described below) which replaced the 1997 Incentive Equity Plan, no further shares have been awarded under the 1997 Equity Incentive Plan, although unvested restricted stock remains outstanding under this plan.

In June 2010, the stockholders approved the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan that replaced the 1997 Incentive Equity Plan. A total of 1,000,000 shares of common stock were reserved for issuance of stock options, stock appreciation rights, restricted stock, stock units and performance cash awards under this plan. During the restricted period, the recipient has the right to vote on the restricted shares and receive dividends on the unvested restricted shares. Dividends are accrued on these unvested restricted shares and ultimately paid only if the awards vest.

In June 2011, the stockholders approved the GulfMark Offshore, Inc. 2011 Non-Employee Director Plan, or 2011 Director Plan. The 2011 Director Plan replaced the GulfMark Offshore, Inc. 2005 Non-Employee Director Plan. The terms of our 2011 Director Plan provide that each non-employee director will receive an annual grant of stock awards. The non-employee director may also be granted an annual stock option to purchase up to 6,000 shares of common stock. The exercise price of options granted under the 2011 Director Plan is fixed at the fair market value of the common stock on the date of grant. The maximum number of shares authorized under the 2011 Director Plan is 150,000.

A summary of the unvested restricted stock awarded pursuant to our 1997 Incentive Equity Plan and our 2010 Omnibus Equity Incentive Plan as of December 31, 2012 and changes during the year, are presented below:


	Shares			Weighted- Average Grant Date Fair Value
Nonvested at December 31, 2011		378,372		$	32.91
Granted		185,294			45.23
Vested		(235,352	)		44.61
Cancelled		(18,869	)		40.10

Nonvested at December 31, 2012		309,445			41.69


	2012		2011		2010
Weighted average grant date fair value of restricted stock awards granted	$	45.16	$	42.42	$	27.52
Fair value of restricted stock vested (in millions)	$	10.4	$	8.5	$	6.1

The restrictions terminate at the end of three years from the date of grant and the value of the restricted shares is amortized to expense over that period. Total amortization of stock based compensation related to restricted stock was $6.9 million, $6.0 million and $5.5 million for the years ended December 31, 2012, 2011, and 2010, respectively. As of December 31, 2012, the total unrecognized compensation expense for unvested restricted stock awards was $11.0 million. This expense is expected to be recorded over a weighted-average period of 2.3 years.

The following table summarizes the activity of our stock incentive plans in the indicated periods:


	2012				2011				2010
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding at beginning of year		140,000	$	19.14		299,650	$	17.92		457,650	$	15.75
Granted		—		—		—		—		—		—
Forfeitures		—		—		—		—		—		—
Exercised		120,000		19.98		159,650		16.85		158,000		11.63

Outstanding at end of year		20,000	$	14.11		140,000	$	19.14		299,650	$	17.92

Exercisable shares and weighted average exercise price		20,000	$	14.11		140,000	$	19.14		299,650	$	17.92
Shares available for future grants at December 31:
2011 Director Plan		113,124				132,535				—
2010 Omnibus Equity Incentive Plan		657,734				812,909				985,294


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Exercise Price		Weighted Average Remaining Life		Shares		Weighted Average Exercise Price
$13.10 to $17.44		20,000	$	14.11		0.82 years		20,000	$	14.11

		20,000	$	14.11				20,000	$	14.11

ESPP

We have an employee stock purchase plan, or ESPP, that is available to all of our U.S. employees and certain subsidiaries and is qualified under Section 423 of the Internal Revenue Code. At the end of each fiscal quarter, or Option Period, during the term of the ESPP, the employee contributions are used to acquire shares of common stock at 85% of the fair market value of the common stock on the first or the last day of the Option Period, whichever is lower. Prior to 2006, these plans were considered non-compensatory and as

such, our financial statements did not reflect any related expense through December 31, 2005. However, effective January 1, 2006, we adopted FASB ASC 718, Stock Compensation, and expense these costs as compensation. Total compensation expense related to the ESPP was $0.2 million, $0.1 million and $0.1 million during the years ended December 31, 2012, 2011 and 2010, respectively. We have authorized the issuance of up to 400,000 shares of common stock through these plans. At December 31, 2012, there were 238,963 shares remaining in reserve for future issuance. See Note 1 “Nature of Operations and Summary of Significant Accounting Policies – Stock-Based Compensation”.

U.K. ESPP

Certain employees of our U.K. subsidiaries participate in a share incentive plan, which is similar to our ESPP but contains certain provisions designed to meet the requirements of the U.K. tax authorities. The shares purchased by our U.K. employees through the share incentive plan are currently issued through our 2010 Omnibus Equity Incentive Plan, and were previously issued under our 1997 Incentive Equity Plan.

Executive Deferred Compensation Plan

We maintain an executive deferred compensation plan, or EDC Plan. Under the EDC Plan, a portion of the compensation for certain of our key employees, including officers and directors, can be deferred for payment after retirement or termination of employment. Under the EDC Plan, deferred compensation can be used to purchase our common stock or may be retained by us and earn interest at Prime plus 2%. The first 7.5% of compensation deferred must be used to purchase common stock and may be matched by us. At December 31, 2012, a total of $3.7 million had been deferred into the Prime plus 2% portion of the plan, which is included in our consolidated balance sheet.

We have established a “Rabbi” trust to hold the stock portion of benefits under the EDC Plan. The funds provided to the trust are invested by a trustee independent of us in our common stock, which is purchased by the trustee on the open market. The assets of the trust are available to satisfy the claims of all general creditors in the event of bankruptcy or insolvency. Accordingly, the common stock held by the trust and our liabilities under the EDC Plan are included in the accompanying consolidated balance sheets as treasury stock and deferred compensation expense. Dividend equivalents are paid on the stock units at the same rate as dividends on our common stock and are re-invested as additional stock units based upon the fair market value of a share of our common stock on the date of payment of the dividend.

(9) EMPLOYEE BENEFIT PLANS

401(k)

We offer a 401(k) plan to all of our U.S. employees and provide matching contribution to those employees that participate. The matching contributions paid by us totaled $1.6 million, $1.3 million and $1.4 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Multi-employer Pension Obligation

Certain current and former U.K. subsidiaries are participating in a multi-employer retirement fund known as the Merchant Navy Officers Pension Fund (“MNOPF”). At December 31, 2012, we had $4.7 million accrued related to this liability, which reflects all obligations assessed by the fund’s trustee on us. We continue to have employees who participate in the MNOPF and will as a result continue to make routine payments to the fund as those employees accrue additional benefits over time. The status of the fund is calculated by an actuarial firm every three years. The last assessment was completed in March 2012, however the results will not be published until April or May 2013. The amount and timing of additional potential future obligations relating to underfunding depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, asset performance, the number of participating employers, and the final method used in allocating the required contribution among participating employers. In addition, our obligation could increase if other employers no longer participated in the plan. We made contributions to the plan of $0.8 million, $0.3 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Our contributions do not make up more than five percent of total contributions to the plan.

In addition, we participate in the Merchant Navy Ratings Pension Fund (“MNRPF”) in a capacity similar to our participation in the MNOPF. While historically we have not been required to contribute to any deficit in the MNRPF, due to a recent change in the plan rules we have been advised that we will be required to make contributions beginning in 2013. We have also been advised that the actuarial valuation as at March 31, 2011 (the most recent valuation available) identified a total plan deficit. We have accrued an estimate of our share of this deficit totaling $0.1 million during 2012 in anticipation of this obligation.

Norwegian Pension Plans

The Norwegian benefit pension plans include approximately seven of our office employees and 216 seamen and are defined benefit, multiple-employer plans, insured with Nordea Liv. We also have instituted a defined contribution plan in 2008 for shore based personnel that existing personnel could elect to participate in while discontinuing any further obligations in the defined benefit plan. All newly hired shore based personnel are required to join the defined contribution plan. Benefits under the defined benefit plans are based primarily on participants’ years of credited service, wage level at age of retirement and the contribution from the Norwegian National Insurance. A December 31, 2012 measurement date is used for the actuarial computation of the defined benefit pension plans.

The following tables provide information about changes in the benefit obligation and plan assets and the funded status of the Norwegian defined benefit pension plans (in thousands):


	2012			2011
Change in Benefit Obligation
Benefit obligation at beginning of the year	$	8,625		$	8,389
Benefit periodic cost		730			684
Interest cost		288			256
Benefits paid		(351	)		(324	)
Actuarial (gain) loss		339			(160	)
Translation adjustment		637			(220	)

Benefit obligation at year end	$	10,268		$	8,625


	2012			2011
Change in Plan Assets
Fair value of plan assets at beginning of the year	$	6,373		$	6,019
Actual return on plan assets		351			293
Contributions		1,284			646
Benefits paid		(147	)		(149	)
Administrative fee		(69	)		(68	)
Actuarial loss		(919	)		(175	)
Translation adjustment		493			(193	)

Fair value of plan assets at end of year	$	7,366		$	6,373


	2012			2011
Funded status	$	(2,902	)	$	(2,252	)

Amounts recognized in the balance sheet consist of (in thousands):


	December 31,
	2012			2011
Deferred costs and other assets	$	20		$	108
Other liabilities		1,831			1,922

	Year Ended December 31,
	2012			2011
Components of Net Period Benefit Cost
Service cost	$	699		$	730
Interest cost		276			273
Return on plan assets		(351	)		(292	)
Administrative fee		69			68
Recognized net actuarial (gain) loss		1,419			(8	)

Net periodic benefit cost	$	2,112		$	771

The vested benefit obligation is calculated as the actuarial present value of the vested benefits to which employees are currently entitled based on the employees’ expected date of separation or retirement.


	2012			2011
Weighted-average assumptions
Discount rate		3.8	%		3.1	%
Return on plan assets		4.0	%		4.8	%
Rate of compensation increase		3.5	%		3.5	%

The weighted average assumptions shown above were used for both the determination of net periodic benefit cost and the determination of benefit obligations as of the measurement date. In determining the weighted average assumptions, the overall market performance and specific historical performance of the investments of the Norwegian pension plan were reviewed. The asset allocations at the measurement date were as follows:


	2012			2011
Equity securities		9	%		6	%
Property		17	%		18	%
Held-to-Maturity bonds		36	%		44	%
Bonds		16	%		29	%
Other		22	%		3	%

All asset categories		100	%		100	%

The investment strategy focuses on providing a stable return on plan assets using a diversified portfolio of investments.

The projected benefit obligation and the fair value of plan assets for the Norwegian pension plan were approximately $10.3 million and $7.4 million, respectively as of December 31, 2012, and $8.6 million and $6.4 million, respectively as of December 31, 2011. We expect to contribute approximately $0.8 million to the Norwegian pension plan in 2013. No plan assets are expected to be returned to us in 2013.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):


Year ended December 31,	Benefit Payments
2013	$	392
2014		409
2015		423
2016		443
2017		465

Total	$	2,132

(10) STOCKHOLDERS’ EQUITY

Common Stock Issuances

During 2012, 20,648 shares were issued through the ESPP, generating approximately $0.7 million in proceeds. The provisions of the ESPP are described above in Note 8 in more detail.

A total of 162,653 and 170,252 restricted shares of our stock were granted to certain officers and key employees in 2012 and 2011, respectively, pursuant to our 1997 Incentive Equity Plan and 2010 Omnibus Equity Incentive Plan described above in Note 8, with an aggregate market value of $7.5 million and $7.3 million, respectively, on the grant dates.

Preferred Stock

We are authorized by our Certificate of Incorporation, as amended, to issue up to 2,000,000 shares of no par value preferred stock. No shares have been issued.

Stock Repurchases

On December 11, 2012, our Board of Directors approved a stock repurchase program for up to a total of $100 million of our issued and outstanding Class A common stock. The stock may be repurchased from time to time on the open market or in privately negotiated transactions. Repurchases can be made from time to time using a variety of methods, which may include open market purchases or purchases through a Rule 10b5-1 trading plan, all in accordance with Securities and Exchange Commission and other applicable legal requirements. The specific timing, price and size of purchases will be determined by our management based on prevailing stock prices, general economic and market conditions and other considerations. The repurchase program does not obligate us to acquire any particular amount of common stock and may be suspended or discontinued at any time.

The value of the common stock repurchased, along with number of shares repurchased, and average price paid per share for the three months ended December 31, 2012 are as follows:


Repurchase of Equity Securities

Period	Total Number of Common Shares Repurchased		Average Price Paid Per Common Share		Total Number of Common Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Common Shares that May Yet Be Purchased Under the Plans or Programs
October 1 - 31		—		—		—		—
November 1 - 30		—		—		—		—
December 1 - 31		35,400	$	33.93		—		—

Dividends


	2012		2011
Dividends Declared (in thousands)	$	26,613		—
Dividend per share	$	1.00		—

Reorganization

On February 23, 2010, our stockholders approved a corporate reorganization (the “Reorganization”) and as a result, we have a new Certificate of Incorporation.

The Certificate of Incorporation created two classes of common stock: Class A and Class B, and authorized 60 million shares of each class of common stock. All existing shares were converted to Class A common stock in the Reorganization. These shares contain restrictions that, among other things, limit the maximum permitted percentage of outstanding shares of Class A common stock that may be owned or controlled in the aggregate by non-U.S. citizens to a maximum of 22 percent, collectively, the “Maritime Restrictions”. Any purported transfer that would result in more than 22 percent of the outstanding shares of Class A common stock being owned (of record or beneficially) or controlled by non-U.S. citizens will be void and ineffective. In the event such transfers are unable to be voided, shares in excess of the maximum permitted percentage are subject to automatic sale by a trustee appointed by us or, if such sale is ineffective, redemption by us. In any event such non-U.S. citizen will not be entitled to any voting, dividend or distribution rights with respect to the excess shares and may be required to disgorge any profits, dividends or distributions received with respect to the excess shares. The Class B shares do not have the Maritime Restrictions noted above.

Pursuant to the Reorganization, our Certificate of Incorporation and the Bylaws now require that the Chairman of the Board and chief executive officer, by whatever title, must each be U.S. citizens and not more than a minority of the minimum number of directors of the Board of Directors necessary to constitute a quorum of the Board of Directors (or such other portion as the Board of Directors may determine is necessary to comply with the Jones Act) may be non-U.S. citizens so long as shares of New GulfMark Class A common stock remain outstanding.

Initially, the shares of Class B common stock may only be issued upon conversion of all of the outstanding and treasury shares of our Class A common stock into shares of Class B common stock automatically following a determination by our Board of Directors that either the U.S. ownership requirements of the applicable U.S. maritime and vessel documentation laws are no longer applicable to (or have been amended so that the Maritime Restrictions are no longer necessary) or that the elimination of such restrictions is in the best interests of our stockholders. Upon conversion of the outstanding and treasury shares of Class A common stock into outstanding or treasury shares of Class B common stock, as the case may be, such shares of Class A common stock will be canceled, will no longer be outstanding and will not be reissued. There are currently no shares of Class B common stock outstanding.

Our business, assets, liabilities, directors and executive officers did not change as a result of the Reorganization.

(11) DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are accounted for at fair value. The accounting for changes in the fair value of a derivative depends on the intended use and designation of the derivative instrument. For a derivative instrument designated as a fair value hedge, the gain or loss on the derivative is recognized in earnings in the period of change in fair value together with the offsetting gain or loss on the hedged item. For a derivative instrument designated as a cash flow hedge, the effective portion of the derivative’s gain or loss is initially reported as a component of other comprehensive income and is subsequently recognized in earnings when the hedged exposure affects earnings. The ineffective portion of the gain or loss is recognized in current period results of operations. Gains and losses from changes in fair values of derivatives that are not designated as hedges for accounting purposes are recognized in current period results of operations.

Using derivative instruments means assuming counterparty credit risk. Counterparty credit risk relates to the loss we could incur if a counterparty were to default on a derivative contract. We deal with investment grade counterparties and monitor the overall credit risk and exposure to individual counterparties. We do not anticipate nonperformance by any counterparties. The amount of counterparty credit exposure is the unrealized gains, if any, on such derivative contracts. We do not require, nor do we post, collateral or security on such contracts.

Hedging Strategy

We are exposed to certain risks relating to our ongoing business operations. As a result, we enter into derivative transactions to manage certain of these exposures that arise in the normal course of business. The primary risks managed by using derivative instruments are foreign currency exchange rate and interest rate risks. Fluctuations in these rates and prices can affect our operating results and financial condition. We manage the exposure to these market risks through operating and financing activities and through the use of derivative financial instruments. We do not enter into derivative financial instruments for trading or speculative purposes.

We periodically enter into foreign currency forward contracts which are designated as fair value hedges related to payments under our new-build vessel construction programs and are highly effective, as the terms of the forward contracts approximate the purchase commitments under the related contracts. Any gains or losses resulting from changes in fair value are recognized in construction-in-progress related to the vessel under construction. As of December 31, 2012, we had open foreign currency forward contracts hedging British Pound exposure to 47 million in Euro denominated contract payments due at varying times from January 2013 through July 2013.

We entered into an interest rate swap with the objective of reducing our exposure to interest rate risk for $100.0 million of our $200.0 million Facility Agreement variable-rate debt. The swap was designated as a cash flow hedge. The terms of this swap, including reset dates and floating rate indices, matched those of our underlying variable-rate debt and no ineffectiveness was recorded in prior periods.

On February 27, 2012, we announced our intent to issue the new Senior Notes with a fixed interest rate, the proceeds of which would be used to pay down amounts outstanding under our Old Notes and our Facility Agreement. As a result we no longer had forecasted interest payments that qualify for hedge accounting. When a cash flow hedge ceases to qualify for hedge accounting, any amounts remaining in accumulated other comprehensive income are released and charged or credited to the underlying expense, in this case interest expense. At September 30, 2012, we had paid down $100.0 million of the $140.0 million outstanding under our Facility Agreement with proceeds from the new Senior Notes. We allocated a proportionate amount of the accumulated change in the fair value of the interest rate swaps recorded in accumulated other comprehensive income to the remaining $40.0 million of Facility Agreement debt. This balance was amortized to interest expense over the remaining life of the interest rate swap, which matured December 31, 2012. We determined that, based upon current market conditions and other factors, liquidation of the interest rate swap was not economically beneficial prior to its scheduled maturity. Accordingly, we elected to retain and hold the interest rate swap to maturity. Since it no longer qualified as a cash flow hedge, it was considered a derivative with no hedging designation. Changes in fair value of the swap were included in earnings in the period of the change. For the year ended December 31, 2012, insignificant losses were recorded related to this derivative.

Early Hedge Settlement

During December 2009, we cash settled certain interest rate swap contracts prior to their scheduled settlement dates. As a result of these transactions, we paid $6.4 million in cash, which represented the fair value of the contracts at the date of settlement. The forecasted payments associated with these settled swaps are related to the Facility Agreement. For reasons discussed above, we reclassified $0.3 million from accumulated other comprehensive income as the forecasted transaction was reduced below $100.0 million to $40.0 million. This balance was amortized into interest expense through December 31, 2012 when the interest rate swap expired based on forecasted payments as of the settlement date.

The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies the balance sheet location as of December 31, 2012 and December 31, 2011 (dollars in thousands):

Asset Derivatives

Liability Derivatives

December 31, 2012

December 31, 2011

December 31, 2012

December 31, 2011

Derivatives designed as
hedging instruments

Balance

Sheet
Location

Fair
Value

Balance
Sheet
Location

Fair
Value

Balance Sheet
Location

Fair
Value

Balance
Sheet
Location

Fair
Value

Interest rate swap

$ —

Fair value of
derivative

$3,530

Foreign currency forwards

Other current assets

568

—

$ 568

$ —

$3,530

The following table quantifies the amount of gain or loss recognized during the years ended December 31, and identifies the consolidated statement of operations location:


Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in OCI on Derivative					Location of Loss Reclassified from Accumulated OCI into Income		Amount of Loss Reclassified from Accumulated OCI into Income
	2012		2011					2012		2011
	(in thousands)							(in thousands)
Interest rate swaps	$	176	$	(604	)		Interest expense	$	3,435	$	(3,208	)

Changes in the fair values of our derivative instruments with no hedging designation (both assets and liabilities) are reflected in current earnings.

(12) FAIR VALUE MEASUREMENTS

Each asset and liability required to be carried at fair value is classified under one of the following criteria:

Level 1: Quoted market prices in active markets for identical assets or liabilities

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data

Level 3: Unobservable inputs that are not corroborated by market data

Financial Instruments

At December 31, 2012, we had open fair value hedges associated with firm contractual commitments for future vessel payments denominated in a foreign currency. These forward contracts are designated as fair value hedges and are highly effective. We recognize the fair value of our derivative asset as a Level 2 valuation. The fair value at December 31, 2012 was $0.6 million. We determined the fair value based on the contractual rate in each forward agreement and compared the contractual rate to the forward rate as provided by our counterparty as of December 31, 2012.

We had a fixed-for-floating interest rate swap agreement that was entered into to fix the LIBOR interest rate component on $100.0 million of the outstanding balance on the Facility Agreement. The fixed rate component of the swap was set at 4.145% and was accounted for as a cash flow hedge. In conjunction with the issuance of the new Senior Notes in the first quarter of 2012 and the concurrent repayment of $100.0 million of the Facility Agreement debt, we de-designated hedge accounting for this swap. For the year ended December 31, 2012, $1.1 million related to this interest rate swap was reclassified from other comprehensive income to interest expense. We also reclassified an additional $1.8 million from accumulated other comprehensive income to interest expense as a result of de-designating hedge accounting during the first quarter of 2012. We recognize the fair value of our derivative swap as a Level 2 valuation. We determined the fair value of our interest rate swap based on the contractual fixed rate in the swap agreement and the forward curve of three month LIBOR supplied by our counterparty as of December 31, 2012. There was no balance for the swap at December 31, 2012.

In 2011, we wrote down the value of a vessel held for sale from its $3.5 million carrying value to its $1.7 million estimated fair value. During 2012, we reduced the carrying value of this asset by an additional $1.2 million. The impairment losses are included in our statement of operations under impairment charges. The fair value was based on third party appraisals.

The following table presents information about our assets (liabilities) measured at fair value on a recurring and non-recurring basis as of December 31, 2012, and indicates the fair value hierarchy we utilized to determine such fair value (in millions).


	Level 1		Level 2		Level 3		Total
Fair Value Hedge	$	—	$	0.6	$	—	$	0.6
Asset Held For Sale	$	—	$	0.7	$	—	$	0.7

The following table presents information about our assets (liabilities) measured at fair value on a recurring basis as of December 31, 2011, and indicates the fair value hierarchy we utilized to determine such fair value (in millions).


	Level 1		Level 2			Level 3		Total
Cash Flow Hedge	$	—	$	(3.5	)	$	—	$	(3.5	)
Asset Held For Sale	$	—	$	1.7		$	—	$	1.7

The fair value of the derivative is included in current liabilities on the consolidated balance sheet as of December 31, 2012 and 2011. The asset held for sale is included in other current assets on our consolidated balance sheet as of December 31, 2012.

(13) OPERATING SEGMENT INFORMATION

Business Segments

We operate our business based on geographical locations and maintain the following operating segments: the North Sea, Southeast Asia and the Americas. Our chief operating decision-maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate performance. The business within each of these geographic regions has similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under FASB ASC 280, “Segment Reporting”.

Management evaluates segment performance primarily based on operating income. Cash and debt are managed centrally. Because the regions do not manage those items, the gains and losses on foreign currency remeasurements associated with these items are excluded from operating income. Management considers segment operating income to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of the ownership interest in operations without regard to financing methods or capital structures. All significant transactions between segments are conducted on an arms-length basis based on prevailing market prices and are accounted for as such. Operating income and other information regularly provided to our chief operating decision-maker is summarized in the following table (all amounts in thousands):


	North Sea			Southeast Asia		Americas			Other			Total
Year Ended December 31, 2012
Revenue	$	164,273		$	60,504	$	164,428		$	—		$	389,205
Direct operating expenses		84,808			17,150		96,229			—			198,187
Drydock expense		11,587			5,923		15,770			—			33,280
General and administrative expense		16,747			3,755		10,006			24,092			54,600
Depreciation and amortization		19,368			10,604		27,421			2,329			59,722
Impairment charge		1,152			—		—						1,152
(Gain) loss on sale of assets		—			—		(8,744	)		3			(8,741	)

Operating income (loss)	$	30,611		$	23,072	$	23,746		$	(26,424	)	$	51,005

Cash and cash equivalents	$	39,070		$	19,497	$	113,450		$	13,158		$	185,175
Long-lived assets(a)(b)		538,460			262,394		555,425			4,572			1,360,851
Total assets		643,492			306,494		786,305			9,383			1,745,674
Capital expenditures		108,767			990		80,251			2,292			192,301
Year Ended December 31, 2011
Revenue	$	172,393		$	63,754	$	145,723		$	—		$	381,870
Direct operating expenses		81,528			12,006		89,051			—			182,585
Drydock expense		8,563			3,871		3,498			—			15,932
General and administrative expense		12,169			2,852		8,376			22,098			45,495
Depreciation and amortization		19,495			9,738		28,391			1,962			59,586
Impairment charge		1,750			—		—			—			1,750
(Gain) loss on sale of assets		(2,028	)		—		10			—			(2,018	)

Operating income (loss)	$	50,916		$	35,287	$	16,397		$	(24,060	)	$	78,540

Cash and cash equivalents	$	32,554		$	22,721	$	20,730		$	52,812		$	128,817
Long-lived assets(a)(b)		424,115			239,985		567,546			4,624			1,236,270
Total assets		521,675			285,027		626,071			67,026			1,499,799
Capital expenditures		40,776			552		8,756			2,174			52,258
Year Ended December 31, 2010
Revenue	$	148,740		$	66,533	$	144,493		$	—		$	359,766
Direct operating expenses		78,253			10,395		81,990			—			170,638
Drydock expense		7,598			4,796		9,788			—			22,182
General and administrative expense		11,277			2,659		7,798			22,295			44,029
Depreciation and amortization		18,649			8,922		28,321			1,067			56,959
Impairment charge		—			—		97,665			—			97,665
(Gain) loss on sale of assets		(5,246	)		—		154			(3	)		(5,095	)

Operating income (loss)	$	38,209		$	39,761	$	(81,223	)	$	(23,359	)	$	(26,612	)

Cash and cash equivalents	$	47,628		$	16,532	$	16,123		$	16,912		$	97,195
Long-lived assets(a)(b)		408,798			249,678		590,436			4,665			1,253,577
Total assets		505,062			292,189		635,582			35,816			1,468,649
Capital expenditures		31,997			34,959		4,456			2,027			73,439

a.	Goodwill is included in the North Sea segment. The Americas segment goodwill was charged to impairment expense in the second quarter of 2010.

Most vessels under construction are included in Other until delivered. Revenue, long-lived assets and capital expenditures presented in the table above are allocated to segments based on the location the vessel is employed, which in some instances differs from the segment that legally owns the vessel. In 2012, we had $113.6 million in revenue and $374.4 million in long-lived assets attributed to business in the United States, our country of domicile. In 2011, we had $80.8 million in revenue and $393.1 million in long-lived assets attributed to the United States. In 2010, we had $104.5 million in revenue and $462.9 million in long-lived assets attributed to the United States.

(14) UNAUDITED QUARTERLY FINANCIAL DATA

Summarized quarterly financial data for the two years ended December 31, 2012 and 2011 are as follows:


	Quarter
	First			Second		Third		Fourth
	(In thousands, except per share amounts)
2012
Revenues	$	87,435		$	104,884	$	101,867	$	95,019
Operating income		6,434			25,229		17,548		1,793
Net income (loss)		(2,909	)		14,064		13,006		(4,889	)
Per share (basic)		($0.11	)	$	0.53	$	0.49		($0.19	)
Per share (diluted)		($0.11	)	$	0.53	$	0.49		($0.19	)

2011
Revenue	$	81,289		$	96,911	$	103,778	$	99,892
Operating income		4,339			20,428		23,194		30,579
Net income (loss)		(1,167	)		13,291		14,165		23,645
Per share (basic)		($0.05	)	$	0.51	$	0.54	$	0.91
Per share (diluted)		($0.05	)	$	0.51	$	0.54	$	0.90

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

NONE

ITEM 9A. Controls and Procedures

(a) Disclosure Controls and Procedures. We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the fiscal year covered by this Annual Report on Form 10-K. Our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective.

(b) Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f).

Our management assessed the effectiveness of our internal control over financial reporting at December 31, 2012, and in making this assessment, used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management determined that our internal control over financial reporting was effective as of December 31, 2012. KPMG LLP has issued the following opinion on the Company’s internal control over financial reporting.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

GulfMark Offshore, Inc.:

We have audited GulfMark Offshore, Inc. and consolidated subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GulfMark Offshore, Inc. and consolidated subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, GulfMark Offshore, Inc. and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the years then ended, and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Houston, Texas

February 27, 2013

(c) Changes in Internal Control Over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended December 31, 2012, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. Other Information

NONE

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance⁽¹⁾

ITEM 11. Executive Compensation⁽¹⁾

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters⁽¹⁾

ITEM 13. Certain Relationships and Related Transactions, and Director Independence⁽¹⁾

ITEM 14. Principal Accounting Fees and Services⁽¹⁾

(1)	The information required by ITEMS 10, 11, 12, 13 and 14 will be included in our definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days of the close of our fiscal year and is hereby incorporated by reference herein.

PART IV

ITEM 15. Exhibits, Financial Statement Schedules

(a) Exhibits, Financial Statements and Financial Statement Schedules.

(1) and (2) Financial Statements and Financial Statement Schedules.

Consolidated Financial Statements of the Company are included in Part II, Item 8 “Consolidated Financial Statements and Supplementary Data”. All schedules have been omitted because the required information is not present or not present in an amount sufficient to require submission of the schedule, or because the information required is included in the Consolidated Financial Statements or the notes thereto.

(3) Exhibits


Exhibits		Description	Filed Herewith or Incorporated by Reference from the Following Documents

	3.1	Certificate of Incorporation, as amended	Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010

	3.2	Bylaws, as amended	Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010

	4.1	Description of GulfMark Offshore, Inc. Common Stock	Exhibit 4.1 to our current report on Form 8-K filed on February 24, 2010

	4.2	Form of U.S. Citizen Stock Certificates	Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010

	4.3	Form of Non-U.S. Citizen Stock Certificates	Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010

	4.4	Indenture, dated as of July 21, 2004, between GulfMark Offshore, Inc., as the Company, and U.S. Bank National Association, as Trustee, including a form of the Company’s 7.75% Senior Notes due 2014	Exhibit 4.4 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004

	4.5	First Supplemental Indenture, dated as of February 24, 2010, between GulfMark Offshore, Inc. (f/k/a New GulfMark Offshore, Inc.), as the Company and U.S. Bank Association, as Trustee, for the Company’s 7.75% Senior Notes due 2014	Exhibit 10.1 to our current report on Form 8-K filed on February 24, 2010

	4.6	Form of Debt Securities Indenture (Including Form of Note for Debt Securities)	Exhibit 4.7 to our Post-Effective Amendment No. 2/A to our Registration Statement on Form S-3 filed on May 14, 2010

	4.7	Indenture, dated as of March 12, 2012, between GulfMark Offshore, Inc., as issuer, and U.S. Bank National Association, as trustee, including a form of the Company’s 6.375% Senior Notes due 2022	Exhibit 4.1 to our current report on Form 8-K filed on March 12, 2012

	4.8	Second Supplemental Indenture, dated as of March 12, 2012, by and among GulfMark Offshore, Inc. and U.S. Bank National Association, as trustee, for the Company’s 7.75% Senior Notes due 2014	Exhibit 4.2 to our current report on Form 8-K filed on March 12, 2012



4.9	$300 Million GulfMark Offshore, Inc. 6.375% Senior Notes due 2022 Registration Rights Agreement dated as of March 12, 2012, by among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities Inc.	Exhibit 4.3 to our current report on Form 8-K filed on March 12, 2012

4.10	$200 Million GulfMark Offshore, Inc. 6.375% Senior Notes due 2022 Registration Rights Agreement dated as of December 5, 2012, by among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities Inc.	Exhibit 4.3 to our current report on Form 8-K filed on December 6, 2012

4.11	See Exhibit No. 3.1 for provisions of the Certificate of Incorporation and Exhibit 3.2 for provisions of the Bylaws defining the rights of the holders of Common Stock	Exhibits 3.1 and 3.2 to our current report on Form 8-K filed on February 24, 2010

10.1	GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.7 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.2	Amendment No. 1 to the GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.8 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.3	GulfMark Offshore, Inc. Instrument of Assumption and Adjustment (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.9 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.4	Form of Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.12 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.5	Form of Amendment No. 1 to Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.11 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.6	GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.6 to our Form 10-K for the year ended December 31, 2011

10.7	Amendment No. 1 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.4.2 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on March 20, 2001

10.8	Amendment No. 2 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.3 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007

10.9	Amendment No. 3 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.4 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007

10.10	Amendment No. 4 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan *	Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2008

10.11	Amendment No. 5 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.4 to our current report on Form 8-K filed on October 19, 2009

10.12	Form of Incentive Stock Option Agreement (1997 Incentive Equity Plan)*	Exhibit 10.12 to our Form 10-K for the year ended December 31, 2011



10.13	GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010

10.14	Amendment No. 1 to the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit 10.2 to our current report on Form 8-K filed on June 11, 2010

10.15	Form of Notice of Stock Option Award and Form of Stock Option Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.3 to our current report on Form 8-K filed on June 11, 2010

10.16	Form of Notice of Restricted Stock Award and Form of Restricted Stock Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.4 to our current report on Form 8-K filed on June 11, 2010

10.17	Executive Nonqualified Excess Plan*	Exhibit 10.1 to our quarterly report on Form 10-Q filed on October 27, 2010

10.18	Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010*	Exhibit 10.2 to our quarterly report on Form 10-Q filed on October 27, 2010

10.19	Form of the Executive Nonqualified Excess Plan Participation Agreement*	Exhibit 10.3 to our quarterly report on Form 10-Q filed on October 27, 2010

10.20	GulfMark Offshore, Inc. Deferred Compensation Plan *	Appendix C to our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.21	GulfMark Offshore, Inc. 2011 Non-Employee Director Share Incentive Plan *	Appendix B of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.22	GulfMark Offshore, Inc. 2011 Employee Stock Purchase Plan*	Appendix A of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.23	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Bruce A. Streeter*	Exhibit 10.1 to our current report on Form 8-K filed on October 19, 2009

10.24	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on October 19, 2009

10.25	Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Quintin V. Kneen*	Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009

10.26	Employment Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.1 to our current report on Form 8-K filed on March 21, 2011

10.27	Change of Control Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.2 to our current report on Form 8-K filed on March 21, 2011

10.28	GulfMark Offshore, Inc. Severance Benefits Policy, effective as of August 1, 2001*	Exhibit 10.6 to our current report on Form 8-K filed on October 19, 2009

10.29	Amendment to GulfMark Offshore, Inc. Severance Benefits Policy, effective as of October 13, 2009*	Exhibit 10.7 to our current report on Form 8-K filed on October 19, 2009

10.30	Form of Indemnification Agreements*	Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010



10.31	GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000*	Exhibit 10.34 to our annual report on Form 10-K filed on February 24, 2011

10.32	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter*	Exhibit 10.36 to our annual report on Form 10-K filed on February 24, 2011

10.33	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter*	Exhibit 10.37 to our annual report on Form 10-K filed on February 24, 2011

10.34	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 10, 2012, between GulfMark Offshore, Inc. and Bruce A. Streeter *	Exhibit 10.1 to our current report on Form 8-K filed on February 15, 2012

10.35	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech*	Exhibit 10.39 to our annual report on Form 10-K filed February 24, 2011

10.36	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.40 to our annual report on Form 10-K filed February 24, 2011

10.37	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 9, 2012, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on February 15, 2012

10.38	U.S. $25.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008	Exhibits 10.24 and 10.25 to our quarterly report on Form 10-Q filed on July 31, 2008

10.39	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.39 to our Form 10-K for the year ended December 31, 2011

10.40	U.S. $30.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Rederi AS and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.40 to our Form 10-K for the year ended December 31, 2011

10.41	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Marine Far East Pte. Ltd. And DnB NOR Bank ASA and others dated June 5, 2008	Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.42	U.S. $200.0 million Facility Agreement among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, The Royal Bank of Scotland plc, as arranger, as agent of the Finance Parties and as security trustee for the Secured Parties, and the lenders that are parties thereto, dated December 17, 2009	Exhibit 10.1 to our current report on Form 8-K filed on December 17, 2009

10.43	Amendment Agreement dated January 26, 2012, among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as parent and original guarantor, and The Royal Bank of Scotland plc, as original lender, arranger, agent and security agent, relating to the U.S. $200.0 million Facility Agreement dated December 17, 2009	Exhibit 10.1 to our current report on Form 8-K filed on January 26, 2012



10.44	U.S. $150.0 million Multicurrency Facility Agreement dated September 21, 2012, between GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, the financial institutions listed in Part 2 of Schedule 1 thereto, as lenders, The Royal Bank of Scotland plc, Wells Fargo Bank, N.A. and JPMorgan Chase Bank, N.A., as arrangers, and The Royal Bank of Scotland plc, as agent of the finance parties thereto, and as security trustee for the secured parties thereunder	Exhibit 10.1 to our current report on Form 8-K filed September 26, 2012

10.45	Amendment Agreement dated February 25, 2013, among GulfMark Americas, Inc., as original borrower, and GulfMark Offshore, Inc., as parent and original guarantor and the Royal Bank of Scotland plc, as agent, relating to the U.S. $150.0 million Facility Agreement originally dated September 21, 2012.	Exhibit 10.1 to our current report on Form 8-K filed February 26, 2013

10.46	$300 Million GulfMark Offshore, Inc. 6.375% Senior Notes Due 2022 Purchase Agreement dated as of March 1, 2012 among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities, Inc.	Exhibit 1.1 to our current report on Form 8-K filed on March 3, 2012

10.47	$200 Million GulfMark Offshore, Inc. 6.375% Senior Notes Due 2022 Purchase Agreement dated as of November 30, 2012 among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities, Inc.	Exhibit 1.1 to our current report on Form 8-K filed on December 6, 2012

12.1	Computation of Ratio of Earnings to Fixed Charges	Filed herewith

21.1	Subsidiaries of GulfMark Offshore, Inc.	Filed herewith

23.1	Consent of KPMG LLP	Filed herewith

23.2	Consent of UHY LLP	Filed herewith

31.1	Section 302 Certification for B.A. Streeter	Filed herewith

31.2	Section 302 Certification for Q.V. Kneen	Filed herewith

32.1	Section 906 Certification furnished for B.A. Streeter	Filed herewith

32.2	Section 906 Certification furnished for Q.V. Kneen	Filed herewith

101	The following materials from GulfMark Offshore, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Comprehensive Income (Loss) (v) Consolidated Statements of Stockholders’ Equity (vi) Consolidated Statement of Cash Flows and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.	Filed herewith

	* Denotes compensation arrangements.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.


GulfMark Offshore, Inc. (Registrant)

By:		/s/ Bruce A. Streeter
		Bruce A. Streeter
		Chief Executive Officer, President and Director (Principal Executive Officer)

Date: February 27 , 2013

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



/s/ Bruce A. Streeter Bruce A. Streeter	Chief Executive Officer, President and Director (Principal Executive Officer)	February 27, 2013

/s/ Quintin V. Kneen Quintin V. Kneen	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2013

/s/ Samuel R. Rubio Samuel R. Rubio	Senior Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	February 27, 2013

/s/ David J. Butters David J. Butters	Director	February 27, 2013

/s/ Peter I. Bijur Peter I. Bijur	Director	February 27, 2013

/s/ Brian R. Ford Brian R. Ford	Director	February 27, 2013

/s/ Louis S. Gimbel, 3rd Louis S. Gimbel 3rd	Director	February 27, 2013

/s/ Sheldon S. Gordon Sheldon S. Gordon	Director	February 27, 2013

/s/ Robert B. Millard Robert B. Millard	Director	February 27, 2013

/s/ Rex C. Ross Rex C. Ross	Director	February 27, 2013


Exhibits		Description	Filed Herewith or Incorporated by Reference from the Following Documents

	3.1	Certificate of Incorporation, as amended	Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010

	3.2	Bylaws, as amended	Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010

	4.1	Description of GulfMark Offshore, Inc. Common Stock	Exhibit 4.1 to our current report on Form 8-K filed on February 24, 2010

	4.2	Form of U.S. Citizen Stock Certificates	Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010

	4.3	Form of Non-U.S. Citizen Stock Certificates	Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010

	4.4	Indenture, dated as of July 21, 2004, between GulfMark Offshore, Inc., as the Company, and U.S. Bank National Association, as Trustee, including a form of the Company’s 7.75% Senior Notes due 2014	Exhibit 4.4 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004

	4.5	First Supplemental Indenture, dated as of February 24, 2010, between GulfMark Offshore, Inc. (f/k/a New GulfMark Offshore, Inc.), as the Company and U.S. Bank Association, as Trustee, for the Company’s 7.75% Senior Notes due 2014	Exhibit 10.1 to our current report on Form 8-K filed on February 24, 2010

	4.6	Form of Debt Securities Indenture (Including Form of Note for Debt Securities)	Exhibit 4.7 to our Post-Effective Amendment No. 2/A to our Registration Statement on Form S-3 filed on May 14, 2010

	4.7	Indenture, dated as of March 12, 2012, between GulfMark Offshore, Inc., as issuer, and U.S. Bank National Association, as trustee, including a form of the Company’s 6.375% Senior Notes due 2022	Exhibit 4.1 to our current report on Form 8-K filed on March 12, 2012

	4.8	Second Supplemental Indenture, dated as of March 12, 2012, by and among GulfMark Offshore, Inc. and U.S. Bank National Association, as trustee, for the Company’s 7.75% Senior Notes due 2014	Exhibit 4.2 to our current report on Form 8-K filed on March 12, 2012

	4.9	$300 Million GulfMark Offshore, Inc. 6.375% Senior Notes due 2022 Registration Rights Agreement dated as of March 12, 2012, by among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities Inc.	Exhibit 4.3 to our current report on Form 8-K filed on March 12, 2012

	4.10	$200 Million GulfMark Offshore, Inc. 6.375% Senior Notes due 2022 Registration Rights Agreement dated as of December 5, 2012, by among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities Inc.	Exhibit 4.3 to our current report on Form 8-K filed on December 6, 2012

	4.11	See Exhibit No. 3.1 for provisions of the Certificate of Incorporation and Exhibit 3.2 for provisions of the Bylaws defining the rights of the holders of Common Stock	Exhibits 3.1 and 3.2 to our current report on Form 8-K filed on February 24, 2010



10.1	GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.7 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.2	Amendment No. 1 to the GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.8 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.3	GulfMark Offshore, Inc. Instrument of Assumption and Adjustment (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.9 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.4	Form of Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.12 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.5	Form of Amendment No. 1 to Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.11 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

10.6	GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.6 to our Form 10-K for the year ended December 31, 2011

10.7	Amendment No. 1 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.4.2 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on March 20, 2001

10.8	Amendment No. 2 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.3 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007

10.9	Amendment No. 3 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.4 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007

10.10	Amendment No. 4 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan *	Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2008

10.11	Amendment No. 5 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.4 to our current report on Form 8-K filed on October 19, 2009

10.12	Form of Incentive Stock Option Agreement (1997 Incentive Equity Plan)*	Exhibit 10.12 to our Form 10-K for the year ended December 31, 2011

10.13	GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010

10.14	Amendment No. 1 to the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit 10.2 to our current report on Form 8-K filed on June 11, 2010

10.15	Form of Notice of Stock Option Award and Form of Stock Option Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.3 to our current report on Form 8-K filed on June 11, 2010

10.16	Form of Notice of Restricted Stock Award and Form of Restricted Stock Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.4 to our current report on Form 8-K filed on June 11, 2010

10.17	Executive Nonqualified Excess Plan*	Exhibit 10.1 to our quarterly report on Form 10-Q filed on October 27, 2010



10.18	Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010*	Exhibit 10.2 to our quarterly report on Form 10-Q filed on October 27, 2010

10.19	Form of the Executive Nonqualified Excess Plan Participation Agreement*	Exhibit 10.3 to our quarterly report on Form 10-Q filed on October 27, 2010

10.20	GulfMark Offshore, Inc. Deferred Compensation Plan *	Appendix C to our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.21	GulfMark Offshore, Inc. 2011 Non-Employee Director Share Incentive Plan *	Appendix B of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.22	GulfMark Offshore, Inc. 2011 Employee Stock Purchase Plan*	Appendix A of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.23	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Bruce A. Streeter*	Exhibit 10.1 to our current report on Form 8-K filed on October 19, 2009

10.24	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on October 19, 2009

10.25	Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Quintin V. Kneen*	Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009

10.26	Employment Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.1 to our current report on Form 8-K filed on March 21, 2011

10.27	Change of Control Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.2 to our current report on Form 8-K filed on March 21, 2011

10.28	GulfMark Offshore, Inc. Severance Benefits Policy, effective as of August 1, 2001*	Exhibit 10.6 to our current report on Form 8-K filed on October 19, 2009

10.29	Amendment to GulfMark Offshore, Inc. Severance Benefits Policy, effective as of October 13, 2009*	Exhibit 10.7 to our current report on Form 8-K filed on October 19, 2009

10.30	Form of Indemnification Agreements*	Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010

10.31	GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000*	Exhibit 10.34 to our annual report on Form 10-K filed on February 24, 2011

10.32	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter*	Exhibit 10.36 to our annual report on Form 10-K filed on February 24, 2011

10.33	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter*	Exhibit 10.37 to our annual report on Form 10-K filed on February 24, 2011

10.34	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 10, 2012, between GulfMark Offshore, Inc. and Bruce A. Streeter *	Exhibit 10.1 to our current report on Form 8-K filed on February 15, 2012



10.35	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech*	Exhibit 10.39 to our annual report on Form 10-K filed February 24, 2011

10.36	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.40 to our annual report on Form 10-K filed February 24, 2011

10.37	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 9, 2012, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on February 15, 2012

10.38	U.S. $25.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008	Exhibits 10.24 and 10.25 to our quarterly report on Form 10-Q filed on July 31, 2008

10.39	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.39 to our Form 10-K for the year ended December 31, 2011

10.40	U.S. $30.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Rederi AS and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.40 to our Form 10-K for the year ended December 31, 2011

10.41	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Marine Far East Pte. Ltd. And DnB NOR Bank ASA and others dated June 5, 2008	Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.42	U.S. $200.0 million Facility Agreement among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, The Royal Bank of Scotland plc, as arranger, as agent of the Finance Parties and as security trustee for the Secured Parties, and the lenders that are parties thereto, dated December 17, 2009	Exhibit 10.1 to our current report on Form 8-K filed on December 17, 2009

10.43	Amendment Agreement dated January 26, 2012, among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as parent and original guarantor, and The Royal Bank of Scotland plc, as original lender, arranger, agent and security agent, relating to the U.S. $200.0 million Facility Agreement dated December 17, 2009	Exhibit 10.1 to our current report on Form 8-K filed on January 26, 2012

10.44	U.S. $150.0 million Multicurrency Facility Agreement dated September 21, 2012, between GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, the financial institutions listed in Part 2 of Schedule 1 thereto, as lenders, The Royal Bank of Scotland plc, Wells Fargo Bank, N.A. and JPMorgan Chase Bank, N.A., as arrangers, and The Royal Bank of Scotland plc, as agent of the finance parties thereto, and as security trustee for the secured parties thereunder	Exhibit 10.1 to our current report on Form 8-K filed September 26, 2012

10.45	Amendment Agreement dated February 25, 2013, among GulfMark Americas, Inc., as original borrower, and GulfMark Offshore, Inc., as parent and original guarantor and the Royal Bank of Scotland plc, as agent, relating to the U.S. $150.0 million Facility Agreement originally dated September 21, 2012.	Exhibit 10.1 to our current report on Form 8-K filed February 26, 2013

10.46	$300 Million GulfMark Offshore, Inc. 6.375% Senior Notes Due 2022 Purchase Agreement dated as of March 1, 2012 among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities, Inc.	Exhibit 1.1 to our current report on Form 8-K filed on March 3, 2012



10.47	$200 Million GulfMark Offshore, Inc. 6.375% Senior Notes Due 2022 Purchase Agreement dated as of November 30, 2012 among GulfMark Offshore, Inc., Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBS Securities, Inc.	Exhibit 1.1 to our current report on Form 8-K filed on December 6, 2012

12.1	Computation of Ratio of Earnings to Fixed Charges	Filed herewith

21.1	Subsidiaries of GulfMark Offshore, Inc.	Filed herewith

23.1	Consent of KPMG LLP	Filed herewith

23.2	Consent of UHY LLP	Filed herewith

31.1	Section 302 Certification for B.A. Streeter	Filed herewith

31.2	Section 302 Certification for Q.V. Kneen	Filed herewith

32.1	Section 906 Certification furnished for B.A. Streeter	Filed herewith

32.2	Section 906 Certification furnished for Q.V. Kneen	Filed herewith

101	The following materials from GulfMark Offshore, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Comprehensive Income (Loss) (v) Consolidated Statements of Stockholders’ Equity (vi) Consolidated Statement of Cash Flows and (v) Notes to Consolidated Financial Statements, tagged as blocks of text. *Denotes compensation arrangements.	Filed herewith

	*Denotescompensation arrangements.